EXHIBIT D. 3.1.1
STATE OF NEW HAMPSHIRE
BEFORE THE
PUBLIC UTILITIES COMMISSION
AGREEMENT TO SETTLE PSNH RESTRUCTURING
August 2, 1999
Conformed as of June 23, 2000
STATE OF NEW HAMPSHIRE
BEFORE THE
PUBLIC UTILITIES COMMISSION
AGREEMENT TO SETTLE PSNH RESTRUCTURING
August 2, 1999
Conformed as of June 23, 2000
TABLE OF CONTENTS
I. INTRODUCTION
II. DEFINITIONS
III. WRITE-OFF
IV. RATE DESIGN
V. INDIVIDUAL RATE COMPONENTS
A. DELIVERY CHARGE
B. STRANDED COST RECOVERY CHARGE
1. Part 1 - Securitized Assets
2. Part 2 - Nuclear Decommissioning, IPP Costs and Going Forward Costs
3. Part 3 - Non-Securitized Stranded Costs
4. Rate Calculation and Reconciliation
C. RISK SHARING
D. ENERGY CHARGES
1. Competitive Energy Service
2. Transition Service
3. Default Service
E. SYSTEM BENEFITS AND ENERGY CONSUMPTION TAX
1. The Low-Income Electric Assistance Program
2. Energy Efficiency Programs
F. OTHER RATE ISSUES
1. Changes in Nuclear Decommissioning and Public Policy Charges
2. Fuel and Purchased Power Adjustment Clause ("FPPAC")
3. Sharing Agreement.
4. The Rate Agreement and the Seabrook Power Contract.
G. AVOIDED COSTS FOR IPPS
H. TERMINATION OF PILOT PROGRAM
VI. TRANSMISSION AND DISTRIBUTION ISSUES
A. CLASSIFICATION OF TRANSMISSION AND DISTRIBUTION FACILITIES
B. WHITE LAKE POWER PLANT
VII. SPECIAL CONTRACT, ECONOMIC DEVELOPMENT AND BUSINESS
RETENTION CUSTOMERS
VIII. DIVESTITURE
A. GENERAL
B. TIMING AND DETAILS OF THE FOSSIL/HYDRO AUCTIONS
C. FACILITY DESCRIPTIONS
D. APPROVALS
1. Federal
2. State
3. Other
E. MUNICIPAL INTEREST IN PURCHASING HYDROELECTRIC GENERATING
ASSETS
F. HYDRO QUEBEC
1. HQ Phase II Energy Contract or Firm Energy Contract
2. HQ Energy Banking Agreement
3. HQ Support Agreements
G. WYMAN UNIT
H. OTHER POTENTIAL GENERATION SITES
I. MILLSTONE
J. VERMONT YANKEE
K. SEABROOK
L. FAILED AUCTION
IX. MARKETING OF ENERGY
A. PRUDENT OPERATION OF PSNH GENERATING ASSETS
B. MARKETING OF PSNH POWER
1. Fossil Steam, Hydroelectric, Internal Combustion and Nuclear Ownership,
Entitlements or Purchase Obligations
2. Purchases from Qualifying Facilities ("IPPs") at Short Term Avoided Cost
Rates
3. Purchases from Qualifying Facilities ("IPPs") under Long-Term Contracts or
PUC-Approved, Long-Term Rate Orders
C. PROCEDURE FOR REVIEW OF PLANT OPERATION AND MARKETING OF
POWER
X. EMPLOYEE PROTECTION
A. PSNH FOSSIL/HYDRO REPRESENTED EMPLOYEES
B. NAESCO REPRESENTED EMPLOYEES
C. PSNH AND NAESCO NON-REPRESENTED EMPLOYEES
D. RETIREMENT BENEFITS FOR REPRESENTED AND NON-REPRESENTED
EMPLOYEES OF PSNH
OR NAESCO
1. Pension
2. Pension Rule
3. Pension Plan Modification
4. Pension Benefits - General
5. Vesting and Years of Credited Service
E. FOSSIL/HYDRO AND NUCLEAR EMPLOYEES GENERALLY
F. PSNH RETAIL BUSINESS GROUP (T&D COMPANY) COMMITMENTS TO UNION
WORKERS
XI. CODE OF CONDUCT
XII. EXEMPT WHOLESALE GENERATOR STATUS
XIII. SECURITIZATION OF STRANDED COSTS
A. ROLE OF SECURITIZATION IN SETTLEMENT
B. LEGISLATION
C. PUC ORDER
D. RRB TRANSACTION OVERVIEW
1. Sale of RRB Property
2. Issuance of RRBs
3. Servicing of RRBs
4. RRB Charge
5. Credit Enhancement; Overcollateralization and True-Up Mechanism
E. USE OF PROCEEDS
F. STATE OVERSIGHT
XIV. OTHER PSNH COMMITMENTS
A. BANKRUPTCY OF NU OR OTHER AFFILIATES
B. DIVIDEND
C. SALE OF PSNH OR NU
XV. PROCEEDINGS TO BE TERMINATED UPON IMPLEMENTATION OF
SETTLEMENT
A. FEDERAL COURT LITIGATION
B. PUBLIC UTILITIES COMMISSION PROCEEDINGS
XVI. CONDITIONS FOR IMPLEMENTING THE SETTLEMENT
XVII. MISCELLANEOUS
A. APPLICABLE LAW
B. SUCCESSORS AND ASSIGNS
C. ENTIRE AGREEMENT
D. GENERAL PROVISIONS
APPENDICES
APPENDIX A - SUMMARY OF PROPOSED RATES
APPENDIX B - ENVIRONMENTAL RESERVE FUND IDENTIFIED SITES
APPENDIX C - ESTIMATED BALANCE OF THE ASSETS AS OF JUNE 30, 2000
APPENDIX D - FORECAST AMORTIZATION SCHEDULE
APPENDIX E - TRANSITION SERVICE / DEFAULT SERVICE PROTOCOL
APPENDIX F - FOSSIL/HYDRO ASSET AUCTION
APPENDIX G - DESCRIPTION OF PSNH FOSSIL/HYDRO ASSETS TO BE DIVESTED
VIA AUCTION
APPENDIX H - NEW HAMPSHIRE AFFILIATE TRANSACTION RULES APPLICABLE
TO
PSNH AND NU
APPENDIX I - THE CALIFORNIA AFFILIATE TRANSACTION RULES
AGREEMENT TO SETTLE PSNH RESTRUCTURING
I. INTRODUCTION
This Settlement Agreement is entered into this 2nd day of August, 1999, (and
conformed as of June 23, 2000, to reflect changes and corrections made during
hearings before the New Hampshire Public Utilities Commission in Docket No. DE
99-099, the requirements of Chapter 249 of the Session Laws of 2000 and Order
No. 23,443 of the New Hampshire Public Utilities Commission) between the
Governor of New Hampshire, the Governor's Office of Energy and Community
Services, the Office of the Attorney General, Staff of the New Hampshire
Public Utilities Commission, Public Service Company of New Hampshire ("PSNH")
and Northeast Utilities ("NU") (collectively, the "Parties"). This Agreement
is designed to provide a resolution of all major issues pertaining to PSNH in
the electric industry restructuring proceeding of the New Hampshire Public
Utilities Commission ("PUC") Docket No. DR 96-150, as well as in the other
dockets and pending litigation described in Section XV of this Agreement.
Implementation of this Agreement requires the approval of the PUC, as well
as passage of securitization legislation by the New Hampshire Legislature.
The enactment of Chapter 249 of the Session Laws of 2000 meets this latter
requirement. When implemented, this Agreement will result in the restructuring
of PSNH in compliance with the competitive market structure objectives of both
the Legislature, as set forth in RSA Chapter 374-F, and the PUC, as set forth
in Docket No. DR 96-150, as well as the legislation relative to electric rate
reduction financing contained in Chapter 289 of the Session Laws of 1999 and
Chapter 249 of the Session Laws of 2000.
The key components of this Agreement include:
* An initial 15.3% average rate reduction for PSNH's customers, followed by
subsequent decreases through the life of this Agreement.
* Substantial burden sharing by PSNH in the form of a $225 million after-tax
write-off that will reduce Stranded Costs by approximately $367 million.
* Sharing of the risks of Stranded Cost recovery.
* Retail choice for all of PSNH's customers.
* Resolution of all issues pertaining to the Rate Agreement in a manner that is
balanced and equitable.
* Resolution of the Fuel and Purchased Power Adjustment Clause ("FPPAC") under-
recovery that will exist as of Competition Day, and elimination of FPPAC in the
future.
* Rate relief that is sustainable over the long-term.
* Refinancing that benefits customers through the issuance of low-cost Rate
Reduction Bonds in an amount consistent with RSA Chapter 369-B
("securitization").
* Provision for low-income assistance and energy conservation programs for
PSNH's customers.
* Transition Service that provides stable and predictable prices for all
customers during the transition to competition.
* Divestiture of PSNH's generating assets and purchased power obligations,
including its entitlement to power generated at the Seabrook Nuclear Plant
under its contract with North Atlantic Energy Corporation ("NAEC").
This Agreement is designed to be implemented on Competition Day, which is the
first day of the month following the month in which the conditions contained in
Section XVI are satisfied. Until the earlier of Competition Day or October 1,
2000, PSNH's existing temporary rates for bundled service, the existing FPPAC
rate of 0.383Cent/kWh, and the FPPAC BA amount of 6.281Cent/kWh will remain in
effect, subject only to adjustment for future changes in Nuclear
Decommissioning Charges and new levels of public policy expenditures ordered
by the PUC after August 2, 1999. If Competition Day has not occurred by
October 1, 2000, then effective October 1, 2000 PSNH shall temporarily reduce
its current effective total rates (base rates plus FPPAC rates) by 5 percent
across the board in the same manner as was used to implement the temporary rate
reduction ordered in Docket No. DR 97-059 until either Competition Day or
April 1, 2001, whichever occurs earlier. On Competition Day, PSNH's rates
will be unbundled and retail customers will have the opportunity to choose
an energy supplier. During the first year following Competition Day, this
Agreement will result in an average retail rate of 10.985 Cent per kWh for a
customer taking Transition Service, broken down as follows:
Transition Service Energy Charge 4.400 Cent
Delivery Charge 2.800
Hydro-Quebec Support Payments 0.130
Stranded Cost Recovery Charge 3.400
System Benefits Charge 0.200
Consumption Tax 0.055 Cent
Total 10.985 Cent/kWh
Customers may be able to obtain even lower overall electricity costs by
choosing a Competitive Supplier for energy.
The Parties recognize and understand that their mutual undertakings, as
expressed in this Agreement, reflect their efforts to settle the issues raised
in Docket No. DR 96-150, settle all outstanding federal and state proceedings
involving PSNH restructuring, and lay to rest various other areas of dispute
between the Parties as provided herein. The Parties agree that their
understandings regarding securitization will require enactment of legislation
by the New Hampshire Legislature, in addition to the approval of the PUC.
Chapter 249 of the Session Laws of 2000 meets the requirement for a legislative
enactment.
The Parties believe the terms of this Agreement reflect a fair resolution of
all outstanding disputes that is in the public interest. More specifically,
this Agreement is substantially consistent with the restructuring goals set
forth in RSA Chapter 374-F and Chapter 289 of the Session Laws of 1999,
including, but not limited to, near-term rate relief; retail choice; non-
discriminatory open access to the electric system; unbundling of rates;
equitable benefits for all customer classes; electricity prices that narrow
the rate gap for New Hampshire customers; universal service and energy
efficiency commitments; risk sharing by PSNH; a substantial write-off of
Stranded Costs; limited Stranded Cost recovery that is appropriate,
equitable and balanced; and, issuance of Rate Reduction Bonds that are not an
obligation of the State, and that will provide equitable and extraordinary
benefits to PSNH's customers in the form of significant rate reductions.
In compliance with the requirements of RSA 369-A:1,X(h), PSNH and the New
Hampshire Electric Cooperative, Inc. ("NHEC"), have entered into a FERC-
approved settlement of all issues.
II. DEFINITIONS
Acquisition Premium: The Acquisition Premium referred to in paragraph 2(b) of
the Rate Agreement.
Agreement: This Settlement Agreement signed by the Parties on August 2, 1999,
including all appendices, and conformed as of June 23, 2000, to reflect changes
and corrections made during hearings before the New Hampshire Public Utilities
Commission in Docket No. DE 99-099, the requirements of Chapter 249 of the
Session Laws of 2000 and Order No. 23,443 of the New Hampshire Public
Utilities Commission.
All-In Cost: The cost of the RRBs, including the coupon rate, any discounts or
premiums, ongoing fees, the overcollateralization account, SPSE expenses, any
letter of credit costs, but excluding servicing fees.
California Code: The Code of Conduct adopted by the California Public
Utilities Commission, as set out in Appendix I and referred to in New
Hampshire PUC Order No 22,875 issued in Docket No. DR 96-150 dated March 20,
1998.
Capacity Transfer Agreements: The Capacity Transfer Agreements between PSNH
and the NU initial system referred to in paragraph 3 of the Rate Agreement.
Capital Subaccount: An account that will belong to the Special Purpose
Securitization Entity, and will hold the initial capital contribution to the
Special Purpose Securitization Entity and certain related amounts as described
in Section XIII(D) of this Agreement.
Competition Day: The date upon which all PSNH retail customers will be able to
choose a Competitive Supplier of energy. More specifically, Competition Day is
the first day of the month following the month in which the conditions
contained in Section XVI are satisfied.
Competitive Supplier: An "Electricity Supplier" as defined in RSA 374-F:2,II,
who meets all PUC requirements to sell energy to PSNH's customers.
Default Service: The source of electric energy for customers who are not
eligible for Transition Service and who are not receiving energy from a
Competitive Supplier. Default service is designed to provide a temporary
safety net for customers and to assure universal access and system integrity
as set forth in RSA 374-F:3,V(c).
Delivery Charge: The delivery portion of the unbundled retail distribution
bill.
Demand-Side Management ("DSM"): Programs traditionally designed to reduce or
manage customer electricity usage as specified in Section V(E)(2).
Distribution: The portion of PSNH's delivery system subject to the regulatory
jurisdiction of the PUC.
Energy Consumption Tax: The tax specified in RSA 83-E:2.
Energy Efficiency Programs: Programs designed to improve the efficiency of,
and thus reduce, customer electricity usage as specified in Section V(E)(2).
Energy Efficiency Working Group ("EEWG"): A collaborative of interested
parties in PUC Docket No. DR 96-150 developing energy efficiency
recommendations.
Environmental Remediation Expenditures: Costs of remediating the environmental
issues at the sites identified in Appendix B.
Environmental Reserve ("ER"): A reserve account established by PSNH on its
books to provide for environmental remediation expenditures, as provided in
Section V(A).
Exempt Wholesale Generator: Any entity who qualifies for Exempt Wholesale
Generator status under Section 32 of the Public Utility Holding Company Act
of 1935.
Failed Auction: An asset auction that results in some or all of the assets
either not being bid upon at auction, or being bid at prices less than the
minimum prices established or approved by the PUC.
FERC: The Federal Energy Regulatory Commission.
Final Order: An order issued by the PUC pursuant to RSA-363:17-b on the merits
of the Agreement, effective at the expiration of the rehearing period set forth
in RSA 541:3, or, if the order is subject to one or more motions for rehearing,
effective the date that the PUC acts on the last pending motion for rehearing
pursuant to RSA 541:5.
Fuel and Purchased Power Adjustment Clause ("FPPAC"): The Fuel and Purchased
Power Adjustment Clause referred to in paragraph 7 of the Rate Agreement.
Independent Power Producer ("IPP") costs: The costs to PSNH of purchasing
energy and/or capacity from PURPA qualifying facilities or LEEPA facilities.
Initial Delivery Charge Period: The first thirty-three months following
Competition Day during which delivery rates are set at 2.80 cents per
kilowatt-hour, exclusive of Hydro Quebec transmission support payments.
Initial Transition Service End Day: The date occurring nine months after
Competition Day.
LEEPA: The Limited Electrical Energy Producers Act, RSA Chapter 362-A.
Legislature: The General Court of the State of New Hampshire.
Low-Income Electric Assistance Program: A statewide payment assistance program
designed to enable low-income residential customers to manage and afford
essential electricity requirements, as provided in Section V(E)(1).
Major Storm Cost Reserve: An account to be established by PSNH to fund the
costs identified in Section V(A).
New Hampshire Code of Conduct: The Code of Conduct to be adopted by the PUC
pursuant to Order No. 22,875 issued in Docket No. DR 96-150 dated March 20,
1998, as provided in Section XI of this Agreement.
Non-Securitized Stranded Costs: The Stranded Costs for which recovery is
allowed under Part 3 of the Stranded Cost Recovery Charge as provided in
Section V(B)(3) of this Agreement.
Nuclear Decommissioning Charge: The ongoing expenses for nuclear
decommissioning for Seabrook, Millstone Unit 3 and Vermont Yankee.
Overcollateralization Subaccount: An account that will belong to the Special
Purpose Securitization Entity and will hold the Overcollateralization amount
on the RRBs as described in Section XIII(D) of this Agreement.
Parties: The Governor of New Hampshire, the Governor's Office of Energy and
Community Services, the Office of the Attorney General, Staff of the New
Hampshire Public Utilities Commission, Public Service Company of New Hampshire
and Northeast Utilities.
Present Value: Unless otherwise specified, the net present value that results
from applying the Stipulated Rate of Return.
Prudence: The standard of care which qualified utility management would be
expected to exercise under the circumstances that existed at the time the
decision in question had to be made. In determining whether a decision was
prudently made, only those facts known or knowable at the time of the decision
can be considered.
PSNH: Public Service Company of New Hampshire.
PUC: The New Hampshire Public Utilities Commission.
Purchased Power Obligation: A commitment created by contract, order or law
for PSNH to purchase power from a third party.
PURPA: The Public Utility Regulatory Policies Act of 1978. Generally, 16 U.S.
Code 2601, et seq.
Rate Agreement: The agreement dated November 22, 1989, as amended, executed by
and between the Governor and Attorney General of the State of New Hampshire,
acting on behalf of the State of New Hampshire, and Northeast Utilities Service
Company, acting on behalf of its parent Northeast Utilities.
See RSA 362-C:2,I.
Rate Reduction Bonds ("RRBs"): Bonds, notes, certificates of participation or
beneficial interest, or other evidences of indebtedness or ownership, issued
pursuant to an executed indenture or other agreement of a financing entity, in
accordance with New Hampshire law, the proceeds of which are used, directly or
indirectly, to recover, finance, or refinance Stranded Costs, and which,
directly or indirectly, are secured by evidence of ownership interests in, or
are payable from, RRB property.
Recovery End Date: The risk sharing date established in Section V(C) at which
recovery by PSNH of its Non-Securitized Stranded Costs ends, even if all such
costs have not been recovered. The Recovery End Date may be different for
various customer classes.
Reserve Subaccount: An account of the Special Purpose Securitization Entity
that will hold any excess collections of RRB Charges beyond the amount needed
to make periodic allocations with respect to RRB Costs as described in Section
XIII(D) of this Agreement.
Retail Choice: The ability of retail electric customers to choose a
Competitive Supplier on or after Competition Day.
RRB Charge: Part 1 of the SCRC, which is dedicated to the payment of the RRBs.
RRB Costs: Principal, interest, credit enhancement costs, fees and expenses
with respect to RRBs.
RRB Property: An irrevocable property right to bill and collect nonbypassable
RRB Charges in amounts sufficient to recover the RRB Costs.
Seabrook Power Contract: The agreement between PSNH and North Atlantic Energy
Corporation referred to in paragraph 2 of the Rate Agreement.
Service Territory: The geographic area established by the PUC as the retail
electric service territory of PSNH, as such territory is depicted on the
"Electric Utilities Franchise Areas" map issued by the PUC, dated July 1,
1993, together with any other geographic area in which PSNH actually provided
retail electric service on such date.
Sharing Agreement: The agreement referred to in paragraph 4 of the Rate
Agreement.
Special Purpose Securitization Entity ("SPSE"): Any special purpose trust,
limited liability company, or other entity that is authorized in accordance
with the terms of a finance order to issue Rate Reduction Bonds, acquire RRB
Property, or both.
Stipulated Rate of Return: A rate of return calculated assuming a return on
equity of 8% after tax, an equity ratio of 40%, and the weighted cost of PSNH's
non-securitized long-term debt. The Stipulated Rate of Return will be computed
as of two dates. The first calculation will occur on Competition Day, and will
take into account the reduction in long-term debt costs occasioned by the
issuance of the RRBs. The second calculation will occur as of the date of the
closing of the sale of all of PSNH's fossil and hydro assets, and will take
into account any additional reduction in long-term debt costs occasioned by the
proceeds from the sales of those assets.
Stranded Costs: Costs, liabilities, and investments that PSNH would reasonably
expect to recover if the existing regulatory structure with retail rates for
the bundled provision of electric service continued, but which would likely not
be recovered as a result of restructuring of the electric industry that allows
retail choice of electricity suppliers unless a specific mechanism for such
cost recovery is provided. See RSA 374-F:2,IV.
Stranded Cost Recovery Charge ("SCRC"): The portion of the unbundled retail
delivery service bill that is a non-bypassable charge as provided in RSA
Chapter 374-F:3 to recover the portion of PSNH's Stranded Costs that are
allowed by this Agreement. The SCRC includes the RRB Charge, nuclear
decommissioning and IPP costs, Non-Securitized Stranded Costs, and other
costs and expenses allowed by this Agreement.
System Benefits Charge: A nonbypassable charge authorized by RSA 374:F:3,VI,
which is designed to recover the costs of PUC-approved public benefits related
to the provision of electricity, including the Low-Income Electric Assistance
Program and Energy Efficiency Programs specified in this Agreement.
Tariff: The Electric Delivery Service Tariff pursuant to which PSNH will
provide service beginning on Competition Day. In the event of any conflicts
between the Tariff and this Agreement, the terms of this Agreement shall
control.
Transition Service: Electricity supply to be made available for the time
periods set forth in RSA 369-B:3,IV,b,1 to all customers who have not chosen
a Competitive Supplier, or who in certain circumstances have left such a
supplier. Transition Service is designed to afford customers the option of
stable and predictable ceiling prices in accordance with RSA 374-F:3,V(b).
Transmission: The portion of PSNH's delivery system that is subject to the
regulatory jurisdiction of the Federal Energy Regulatory Commission.
Triple-A Rating: A determination by a majority of (a) Duff & Phelps Credit
Rating Co., Fitch Investors Service, L.P., Moody's Investors Service, and
Standard & Poor's Ratings Services, or (b) the ratings agencies in (a) that
actually rate the RRBs at issuance, that the RRBs are entitled to their highest
rating.
True-Up Mechanism: A periodic adjustment to the RRB Charge, which accounts for
any over or under-collections of the RRB Charge.
III. WRITE-OFF
Subsequent to receipt of a Final Order from the PUC approving this Settlement
Agreement as submitted by the Parties and upon satisfaction of the conditions
contained in Section XVI, PSNH will write off $225 million after-tax
(approximately $367 million pre-tax as of January 1, 2000). Such write-off
shall take place on or before Competition Day. The write-off will be first
taken against the Seabrook Deferred Return and the Acquisition Premium in a
manner that will maximize benefits for customers. In addition to the
write-off described above, PSNH will take an additional pre-tax write-off
of $6,200,000 on or before Competition Day resulting from the settlement of
issues pertaining to New Hampshire Electric Cooperative, Inc. and will also
reduce its Stranded Costs by an additional $10 million upon the transfer of
the following market-based wholesale contracts to an affiliate:
Braintree Littleton Electric Light & Water Dept.
Burlington Electric Dept. Littleton, NH
Central Maine Power Mansfield
Citizens Lehman Middleton
Citizens System Reading
Commonwealth Electric Select Energy
Danvers Sterling
Fitchburg Gas & Electric UNITIL
Holyoke Gas & Electric VT. Marble
IV. RATE DESIGN
The rate design principles to which the Parties have agreed are as described
below.
All classes of customers are to be charged an equal cents per kilowatt-hour
amount for the System Benefits Charge and the Energy Consumption Tax (unless
modified by a revision to the legislation). Other than the specific items
referenced above, PSNH will recover its costs through customer, demand, meter,
and usage (kWh) charges, subject to the constraint that any change to rate
design will not result in a shifting of costs between the residential class
and all other classes. All rate design changes will be performed on a revenue
neutral basis. The average rate reduction for each class will be determined
in accordance with PUC Order No. 23,443 and Chapter 249 of the Session Laws of
2000.
The average reduction for the limited number of optional rates that are already
discounted may be less than the average reduction for the class, or there may
be no reduction. If the percent decrease to certain optional rates is lower or
if there is no decrease, the decrease to the other rates within the class will
be higher in order to ensure that the class receives the overall average
percentage decrease as set forth in Appendix A. Because economic development
("ED") and business retention ("BR") rates are already discounted, the average
rate reduction for ED and BR customers will be less than the average reduction
for the class into which ED and BR customers would ordinarily fall.
The rate design will not result in a higher bill for any customer, when
comparing the customer's bill calculated as of the date of this Agreement
to that bill calculated as of Competition Day, assuming that customer receives
Transition Service. Having committed in this Agreement to address low-income
assistance and energy conservation in a more appropriately targeted fashion,
PSNH has eliminated the current "humped" design of the standard residential
rate, and it has also redesigned its general service rates (Rates G, GV and LG)
to provide for a smooth transition for customers who switch from one rate class
to another as a result of load changes.
A table incorporating the foregoing Rate Design principles is contained in
Appendix A. PSNH is filing a proposed Tariff implementing these rates with
its supporting testimony. The other Parties reserve the right to file
testimony supporting or opposing PSNH's proposed rate design and Tariff
filing.
V. INDIVIDUAL RATE COMPONENTS
A. Delivery Charge
In order to insure that customers will enjoy stable and predictable prices
through the transition to competition, PSNH will set the Delivery Charge at
an overall average level of 2.80 cents per kilowatt-hour for the first
thirty-three months following Competition Day (the "Initial Delivery Charge
Period"), exclusive of Hydro Quebec transmission support payments, unless
adjusted as provided herein. As discussed in Section IV of this Agreement,
("Rate Design"), the Delivery Charge includes customer, demand, meter and
usage (kWh) charges. The average Delivery Charge reflects the amount necessary
for that class to receive the rate reduction provided by this Agreement, once
all other rate design changes have been incorporated and after taking into
account all other charges provided for by this Agreement, including the
Stranded Cost Recovery Charge.
No later than thirty-two months following Competition Day, PSNH will file with
the PUC proposed new delivery rates, including supporting cost and rate
information and pro forma adjustments based on the four most recent calendar
quarters for which data are available, for effect after the end of the Initial
Delivery Charge Period.
The new delivery rates shall take into account any revenues received by PSNH
for servicing of outstanding RRBs subsequent to the Initial Delivery Charge
Period. During the Initial Delivery Charge Period the revenues received from
servicing the RRBs will be reserved in a liability account on PSNH's books and
refunded with a return at the Stipulated Rate of Return when new delivery rates
are determined, over such period as may be ordered by the PUC.
The new delivery rates will become effective after investigation and hearings.
If the new delivery rates are suspended by the PUC, any final rates determined
by the PUC will be calculated retrospectively on an aggregate basis beginning
as of the end of the Initial Delivery Charge Period, with an appropriate refund
or recoupment of costs made prospectively from the effective date of the PUC's
order. The 2.80 Cent delivery rates proposed for the Initial Delivery Charge
Period (exclusive of Hydro Quebec transmission support payments) shall not be
considered a precedent for the establishment of the level of rates subsequent
to the Initial Delivery Charge Period.
During the Initial Delivery Charge Period, a Major Storm Cost Reserve ("MSCR")
shall be established by PSNH, and shall be funded at a rate of $3 million per
year. Major storm costs shall be charged to the MSCR during that period. A
"major storm" shall be defined as any time that either: (a) 10% or more of
PSNH's retail customers lose power and there are more than 200 reported
troubles, or (b) there are 300 or more reported troubles. As part of the
filing for new delivery rates described above, PSNH will report the
difference, if any, between the actual costs charged to the MSCR and the
funding of the MSCR. During the Initial Delivery Charge Period, PSNH will
defer any major storm costs which exceed the funding of the MSCR, and PSNH
will recover or refund (with a return or interest at the Stipulated Rate of
Return) during the subsequent twelve months (or such other period ordered by
the PUC) any difference between the prudent costs properly charged to the MSCR
and the amount of funding of the MSCR.
PSNH has established an Environmental Reserve ("ER") on its books of account.
The ER is for expenditures associated with the sites specified in Appendix B
and is expected to amount to $11.5 million as of January 1, 2000, with the
amount to be adjusted as may be necessary to reflect any reasonable and
prudent adjustments made to such books of account between the filing date
of this Agreement and Competition Day. During the Initial Delivery Charge
Period, PSNH will charge its actual environmental remediation expenditures
for the specifically identified sites to the ER. Subsequent to the Initial
Delivery Charge Period, PSNH will recover or refund (with a return or interest
at the Stipulated Rate of Return) any difference over a period not to exceed
three years, subject to a prudence finding for the costs charged thereto.
Because the average Delivery Charge of 2.80 cents per kilowatt-hour does not
recover any Environmental Remediation Expenditures, during the Initial Delivery
Charge Period PSNH will defer for future recovery environmental expenses for
any new site that is identified or for any increase to estimated remediation
costs for any existing sites. As part of the filing for new delivery rates,
PSNH will propose recovery of any such deferrals. The PUC shall grant recovery
of such costs that it determines to be prudent. If the PUC grants recovery,
such deferrals shall be amortized as they are recovered through the new
Delivery Charge. Any actual Environmental Remediation Expenditures will
decrease the ER.
During the Initial Delivery Charge Period, the Delivery Charge shall, upon
request by PSNH or on a motion by the PUC, be adjusted to fully recover any
changes in PSNH's costs that the PUC determines have resulted from the
imposition or modification of any tax, program, service, or accounting change
resulting from an order by any regulatory agency or by the enactment or
revision of any law, or in the case of accounting changes, by the Financial
Accounting Standards Board ("FASB") or the Emerging Issues Task Force ("EITF").
Any such adjustment of the Delivery Charge during the first 24 months
following Competition Day shall be applied as an equal change in the cost
per kWh for all rate classes to which such adjustment applies.
The Delivery Charge of 2.80 cents per kilowatt-hour during the Initial
Delivery Charge Period (exclusive of Hydro Quebec transmission support
payments) will only apply to PSNH's customer, demand, meter, and usage
(kWh) charges. Changes to other fees and service charges (e.g., late
payment charges, service connection charges, line extension charges, and
fees for services provided to energy suppliers) will continue to be subject
to PUC approval.
In order to achieve the Delivery Charge specified above, the Parties agree
that a ten-year extension for depreciation lives is appropriate for PSNH's
Transmission and Distribution assets. The Parties hereby support PSNH's
request to make such an adjustment to the depreciation lives. When and if
approved by the PUC, PSNH will make corresponding adjustments to the book
lives of the affected assets.
PSNH will fund PUC expenses during the Initial Delivery Charge Period that
are necessary to monitor Agreement compliance, to assure that Transmission
and Distribution system quality and reliability are maintained, to assure
that PSNH has prudently sold the output of its generating assets and
entitlements prior to divestiture, to assure that allocators utilized to
assess charges among affiliates are proper and timely, and for other matters
deemed necessary by the PUC. If the cost to PSNH of such funding exceeds the
historical special assessment of $350,000 per year, PSNH may recover the
incremental amount through an increase to the Delivery Charge during the
Initial Delivery Charge Period, pursuant to the provisions of this section
allowing the Delivery Charge to be adjusted for changes in costs resulting
from the imposition or modification of any tax, program, service or accounting
change.
Revenue received by PSNH from the provision of wheeling service across PSNH's
Transmission system or the Transmission system of its affiliates (except for
revenues received for usage of the Hydro Quebec line) will continue to be
credited on a pro-rata basis against Delivery Charge revenue requirements.
Revenue received by PSNH from the provision of wheeling service across PSNH's
Distribution facilities will also be credited against Delivery Charge revenue
requirements. Such credit shall not affect the level of the Delivery Charge
during the Initial Delivery Charge Period.
In addition to the 2.8 Cent/kWh Delivery Charge, PSNH will be allowed to
recover Hydro Quebec transmission support payments. The cost of such
transmission support payments shall be included on customer bills as an
increase of 0.13 Cent/kWh in the Delivery Charge above the otherwise effective
2.8 Cent/kWh rate during the Initial Delivery Charge Period. The offsetting
credits for all revenues received for usage of the line shall be credited to
Part 3 Stranded Costs pursuant to Section V.B.3 of this Agreement. Subsequent
to the Initial Delivery Charge Period, the level of Hydro Quebec transmission
support payment charges included in rates shall be determined by the PUC as
part of the normal ratemaking process.
B. Stranded Cost Recovery Charge
The Stranded Cost Recovery Charge ("SCRC") will be a non-bypassable charge as
provided in RSA 374-F:3 and RSA 369-B:4, IV to recover the portion of PSNH's
Stranded Costs as well as other specified costs and expenses that are allowed
by this Agreement. Stranded costs to be recovered through the SCRC will
consist of securitized assets and Non-Securitized Stranded Costs, and the net
of ongoing expenses and/or revenue requirements (including decommissioning
costs) for any generating unit, entitlement or obligation that has not been
sold or otherwise divested as of Competition Day. The SCRC will recover the
amortization of the assets and the ongoing expenses, and will be reconciled
with a return applied at the Stipulated Rate of Return to any overrecoveries
or underrecoveries of costs, subject to the provisions of Section V(C),
("Risk Sharing"), except with respect to the RRB Charge, for which
reconciliations shall be calculated in accordance with the True-Up Mechanism
described in Section XIII. Appendix C shows the estimated balance of the
assets as of July 1, 2000, and Appendix D provides an illustrative
amortization schedule for the assets. Appendices C and D will be updated as
required to reflect additional amortization of and/or prudent capital additions
to the listed assets as of Competition Day.
For the purpose of establishing the SCRC, Stranded Costs will be divided into
three parts, as described below. Part 1 will be the RRB Charge, and is the
source of payment for Rate Reduction Bonds. Therefore, the right to receive
all collections in respect of the Part 1 charge will be sold to the Special
Purpose Securitization Entity (see Section XIII). Part 1 is expected to be
billed until the expected maturity date, which is 12 years from the date of
issuance of RRBs, but, in certain circumstances described herein, may be
billed until the legal maturity date of the RRBs as described more fully
below. Part 2 will continue for as long as there are Stranded Cost expense
components in that part for which PSNH is responsible for payment. Part 3
contains other miscellaneous Stranded Costs, and recovery of Part 3 Stranded
Costs by PSNH is time bounded and full recovery of such costs is not
guaranteed to PSNH.
The SCRC shall be a non-bypassable charge pursuant to RSA 374-F:3 and RSA
Chapter 369-B. All currently existing opportunities shall be continued for
retail customers to generate or acquire electricity for their own use, other
than through retail electric service, without an exit fee. The SCRC contained
in Delivery Service Rate B of PSNH's tariff is just and reasonable, and does
not create a charge similar to or have the same effect as an exit fee. In the
event of the municipalization of a portion of PSNH's Service Territory, the PUC
shall, in matters over which the Federal Energy Regulatory Commission does not
have jurisdiction, or has jurisdiction but chooses to grant jurisdiction to the
state, determine, to a just and reasonable extent, the consequential damages
such as stranded investment in generation, storage, or supply arrangements
resulting from the purchase of plant and property from PSNH and RRB costs,
and shall establish an appropriate recovery mechanism for such damages. Any
such damages shall be established, and shall be allocated between the RRB
charge and other rates and charges, in a just and reasonable manner. Any
municipality shall be allowed to initiate or continue the process of
establishment, acquisition and expansion of plants according to RSA Chapter
38 as it exists upon the date of this Agreement, as well as the provisions of
Chapter 249 of the Session Laws of 2000.
1. Part 1 - Securitized Assets
* Part 1 of the SCRC (the "RRB Charge") consists of the amounts required to
recover RRB Costs as more fully described in Section XIII. The proceeds from
securitization may be applied to the following assets: The difference between
North Atlantic Energy Corporation's book value of Seabrook, determined as of
Competition Day, and $100 million. This amount will be paid by PSNH to NAEC
on or before Competition Day to buy down the value of the Seabrook Power
Contract. This contract buy-down is subject to all required regulatory and
lender approvals.
* The book value of Millstone Unit 3 as of the date that PSNH begins to
separately account for its ownership of that unit pursuant to Section VIII(I)
of this Agreement.
* Necessary and prudent costs associated with issuance of and closing on the
securitization financing and any premiums associated with the retirement of
debt and preferred stock from these proceeds up to a maximum of $15 million,
such amount to include the first $700,000 of the costs of the office of the
State Treasurer related to reviewing and issuing the RRBs.
* A portion of the Acquisition Premium and FAS 109 costs related thereto,
which shall be measured as the difference between the proceeds of the RRBs
and the total of the preceding Part 1 costs.
The net book value of the assets that comprise Stranded Costs as of
Competition Day shall form the basis of the amounts to be recovered. Those
values as of the end of each month for calendar years 2000 and 2001, will be
agreed to by the Parties and expeditiously filed with the PUC. The values
shall be used to determine the levels of Part 1 and Part 3, with the exception
that any prudent capital additions or retirements at Seabrook and Millstone
Unit 3 shall be added or subtracted from the stated amount.
The Part 1 charge will be a discrete and segregated charge in order to meet
the requirements for the targeted Triple-A Rated securitization. Therefore,
all Part 1 collections will be allocated and remitted to the Special Purpose
Securitization Entity (described below in Section XIII). Cash collections of
Part 2 and Part 3 will not be made available to make payments on Rate
Reduction Bonds. Section XIII(D) of this Agreement discusses the relationship
between Part 1 collections and Parts 2 and 3 of the SCRC.
2. Part 2 - Nuclear Decommissioning Costs, IPP Costs and Going Forward Costs
Part 2 of the SCRC will initially recover ongoing expenses for nuclear
decommissioning (for Seabrook, Millstone Unit 3 and Vermont Yankee) and for
IPP costs. After the earlier of the Recovery End Date or the date that Non-
Securitized Stranded Costs are fully amortized, Part 2 will also be credited
with a return on the accumulated deferred income taxes at the Stipulated Rate
of ReturnTo the extent that PSNH is unable to divest any asset, entitlement,
or obligation, and the PUC has not exercised its authority to divest under
Section VIII(L), after the earlier of the Recovery End Date or the date that
the Non-Securitized Stranded Costs are fully amortized, such going forward
costs related to those assets, entitlements, or obligations shall thereafter
become Part 2 costs with continued recovery. Such costs shall exclude any
previously deferred amounts. The Part 2 amount to be recovered through the
SCRC each month will be the expenses incurred by PSNH for the items listed
above, less associated revenues and the revenue from the sale of the IPP
power on the wholesale market, adjusted by the prudent costs incurred by
PSNH to mitigate these IPP costs via buyouts, buydowns, or other methods.
Pursuant to Chapter 249 of the Session Laws of 2000, PSNH shall be allowed
to retain up to 20 percent of the savings resulting from such buyouts,
buydowns, or other methods of mitigating IPP costs, subject to order of
the PUC.
In the event that there is insufficient SCRC revenue to meet both Part 1 and
Part 2 SCRC requirements, the unrecovered Part 2 amounts will be deferred for
future Part 2 recovery with a return at the Stipulated Rate of Return.
3. Part 3 - Non-Securitized Stranded Costs
Part 3 of the SCRC will be Non-Securitized Stranded Costs not otherwise
included in Parts 1 or 2, above, offset by a return on related accumulated
deferred income taxes. Non-Securitized Stranded Costs will be recovered
through the SCRC in accordance with the time frame specified in the Risk
Sharing provision set forth below. Non-Securitized Stranded Costs to be
recovered will be the following:
* Any remaining amount of the Acquisition Premium on PSNH's books as of
Competition Day that has not been securitized.
* FAS 109 costs on PSNH's books as of Competition Day related to the
non-securitized portion of the Acquisition Premium.
* The value of unrecovered obligations for retired nuclear power plants
(Connecticut Yankee, Maine Yankee and Yankee Rowe) on PSNH's books as of
Competition Day.
* The balance on PSNH's books as of Competition Day of deferred costs
associated with Independent Power Producers.
* The balance on PSNH's books as of Competition Day of deferred retail FPPAC
costs.
* The value of the Vermont Yankee contract buyout payment.
* Necessary and prudent unamortized loss on reacquired debt and other costs
associated with the accelerated payoff of PSNH and/or NAEC debt, exclusive
of any amounts included in Part 1.
The balance of the Non-Securitized Stranded Costs will be reduced by the
following amounts:
* The net proceeds (sale price less book value less prudent sales expenses and
all associated taxes not otherwise provided for in this Agreement) from the
sales of PSNH's fossil and hydro assets as of the date that each sale closes.
(If the sale price is less than the book value, the balance of the
Non-Securitized Stranded Costs will be increased by the residual balance of
the fossil and hydro assets after subtracting the net proceeds received from
the sales of the assets.)
* The net proceeds from the sale of NAEC's ownership interest in the Seabrook
Nuclear Plant. (If the sale price is less than the book value, the balance of
the Non-Securitized Stranded Costs will be increased by the residual balance
after subtracting the net proceeds received from the sale of NAEC's ownership
interest.)
* $10 million upon transfer of PSNH's market-based wholesale contracts to an
affiliate as described in Section III, the "Write-Off" section of this
Agreement.
* Any net payment received by PSNH resulting from the termination of any
wholesale requirements contract other than the Amended Partial Requirements
Agreement with the New Hampshire Electric Cooperative, Inc.
* The present value of the incremental payments for the All-In Cost of Rate
Reduction Bonds if that cost exceeds the interest rate guarantee made by PSNH
(i.e., 6.25% if the Rate Reduction Bonds are issued on or before December 31,
1999; 7.25% if the Rate Reduction Bonds are issued during the time period
of January 1, 2000 through and including June 30, 2000). If the Rate
Reduction Bonds are issued on or after July 1, 2000, or if such Bonds do not
achieve a Triple-A Rating, this provision does not apply.
* All proceeds received from PSNH's entitlement to the Hydro Quebec
transmission line.
The Part 3 amount recovered through the SCRC each month for Non-Securitized
Stranded Costs will be equal to the amount of Non-Securitized Stranded Costs
amortized each month (assuming a seven year amortization schedule), plus a
return on the balance (net of related accumulated deferred income taxes) of
the Non-Securitized Stranded Costs, plus any underrecovery or any accelerated
amortization as described in Section V(B)(4), the Rate Calculation and
Reconciliation section below, subject to the provisions of Section V(C)
(Risk Sharing). The return applied to the balance of the Non-Securitized
Stranded Costs will be the Stipulated Rate of Return. Other expenses and
obligations recovered through or credited to Part 3 of the SCRC will be the
following:
* The revenue requirement associated with any generating asset, entitlement,
and purchased power obligation (other than Part 2 costs related to nuclear
decommissioning or IPP's) prior to the divestiture of such asset, entitlement
or obligation.
* The difference between the expense incurred for the purchase of power to
supply Transition Service and the revenue received from customers for
Transition
Service. However, PSNH shall absorb the first $7,000,000 of any such
difference during the 12 months following the Initial Transition Service
End Day.
* Any positive difference between the expense incurred for the purchase of
power to supply Default Service and the revenue received from customers for
such service.
* Return on the accumulated deferred income taxes associated with the
securitized assets at a rate equal to the Stipulated Rate of Return.
Other expenses and obligations will be reduced by the revenue from the sale
of power from any generating asset, entitlement or purchased power obligation
(other than IPP's) prior to the divestiture of such asset, entitlement or
obligation.
Part 3 of the SCRC will cease as of the earlier of (a) the Recovery End Date
described in Section V(C), the Risk Sharing section of this Agreement, or (b)
the date that the Non-Securitized Stranded Costs are fully amortized.
However, to the extent that PSNH is unable to divest any asset, entitlement
or obligation and the PUC has not exercised its authority to divest under
Section VIII(L), after the earlier of (a) or (b) above any such going forward
costs related to those assets, entitlements, or obligations shall thereafter
become Part 2 costs with continued recovery. Such costs shall exclude any
previously deferred amounts. In addition, at the earlier of (a) or (b) above,
the accumulated deferred income taxes associated with the securitized assets
and a return thereon, will become Part 2 credits.
4. Rate Calculation and Reconciliation
a. Prior to Recovery End Date
The overall average level of the SCRC will be 3.40 cents per kilowatt-hour for
the period from Competition Day until the earlier of the date that the
Non-Securitized Stranded Costs are fully amortized or the Recovery End Date
described in Section V(C), the Risk Sharing section of this Agreement. During
that time, PSNH will compare the amount to be recovered through Parts 1, 2 and
3 of the SCRC during each six-month period with the revenue received from the
billing of the SCRC. If the Part 3 amounts to be recovered exceed the amount
of revenue received through the billing of the SCRC, the difference will be
deferred with a return for possible future recovery as a Part 3 amount during
the next six-month period. The return will equal the Stipulated Rate of
Return. In no event shall such Part 3 deferral extend beyond the Recovery
End Date. If the Part 3 amounts to be recovered are less than the amount of
revenue received through the billing of the SCRC, the difference will be used
to accelerate the amortization of the Non-Securitized Stranded Costs, thereby
shortening the recovery period for such assets. Nothing described in this
paragraph will affect the RRB Charge or its True-Up Mechanism.
As described in Section XIII, "Securitization of Stranded Costs," the RRB
Charge may be increased or decreased pursuant to its True-Up Mechanism;
however, the total average SCRC will be 3.40 cents/kWh prior to the earlier
of the Recovery End Date or the date when the Non-Securitized Stranded Costs
have been fully amortized. Thus, prior to such date, any increase in the RRB
Charge will result in a decrease in recovery of Part 3. To the extent such
increase in the RRB Charge is greater than the amount to be collected via
Part 3, recovery of Part 2 will also be reduced, such that the total average
SCRC remains 3.40 cents/kWh. To the extent recovery of Part 1 is decreased
pursuant to the True-Up Mechanism prior to the Recovery End Date, recovery
of Part 3 will increase such that the total average SCRC remains 3.40
cents/kWh.
b. Upon Recovery End Date
Upon the Recovery End Date any remaining Part 3 Non-Securitized Stranded Cost
balances shall be written off.
c. After the Recovery End Date
After the earlier of the Recovery End Date or the date that the
Non-Securitized Stranded Costs are fully amortized, the SCRC will no longer be
capped at 3.40 Cent/kWh, but is expected to drop significantly, thus providing
additional customer savings. Thereafter, any increases or decreases in Part 1
pursuant to the True-Up Mechanism will result in corresponding increases or
decreases in the SCRC charged to customers.
After the earlier of the Recovery End Date or the date that the
Non-Securitized Stranded Costs are fully amortized, PSNH will calculate Part
2 to be billed upon PUC approval during each prospective six-month period.
Any difference between the amounts to be recovered through Part 2 during any
six-month period and the revenue received through the application of Part 2
during that period will be refunded or recovered with a return during the
subsequent six-month period by reducing or increasing Part 2 for the
subsequent six-month period. The return will be the Stipulated Rate of Return.
C. Risk Sharing
The recovery of Non-Securitized Stranded Costs in Part 3 of the SCRC described
above shall be subject to the following risk sharing provision. Specifically,
PSNH shall forego the right to recover all such Non-Securitized Stranded Costs
that remain unrecovered as of the Recovery End Date. The Recovery End Date
will initially be October 31, 2007, but shall be revised within 30 days
following the closing on the sale of all fossil/hydro assets described in
Section VIII ("Divestiture") by the following durations:
1) The Recovery End Date shall be 20 days earlier for each month beyond July
1, 2000 that Competition Day occurs.
2) For purposes of computing the Stranded Cost Recovery Charge in this
Agreement, the Parties have assumed that $360 million will be the net
proceeds realized from the sale of the fossil and hydro assets at auction.
After the latter of the fossil or hydro asset sales, the Recovery End Date
shall be adjusted to be 30 days earlier for every $10 million by which the
net sale proceeds of the fossil and hydro assets exceeds $360 million, or
made later by 30 days for every $10 million by which the net sale proceeds
of the fossil/hydro assets is less than $360 million. An adjustment of less
than 30 days will be made on a pro-rata basis for residual increments, or
decrements, less than $10 million.
3) For purposes of computing the Stranded Cost Recovery Charge, the Parties
have assigned a 7.25% All-In Cost to the RRBs. If the Rate Reduction Bonds
are issued prior to July 1, 2000, and achieve a Triple-A Rating, the Recovery
End Date shall be 20 days earlier for each 25 basis points (0.25 percentage
points) by which the All-In Cost of the Rate Reduction Bonds is less than
7.25%.
4) The Recovery End Date shall be adjusted for Transition Service pricing in
two groups: one for residential, General Delivery Service Rate G and outdoor
lighting customers and the second for all other customers, as follows:
a) During the period from Competition Day through the Initial Transition
Service End Day, the Recovery End Date for the two customer groups shall be
adjusted separately, based upon each group's kWh consumption of Transition
Service. The residential, General Delivery Service Rate G and outdoor
lighting customers' Recovery End Date shall be 30 days earlier for every $5.5
million of incremental revenue received from that group, such incremental
revenue to be determined by multiplying that group's total kWh of Transition
Service consumption for the period by 0.4 cents/kWh. The Recovery End Date
for all other customers shall be 30 days earlier for every $4.5 million of
incremental revenue received from that group, such incremental revenue to be
determined by multiplying that group's total kWh of Transition Service
consumption for the period by 0.4 cents/kWh. For each group, an adjustment
of less than 30 days will be made on a pro-rata basis for residual increments
of less than the amounts specified above.
b) During the first twelve-month period following the Initial Transition
Service End Day, the Recovery End Date applicable to residential, General
Delivery Service Rate G and outdoor lighting customers shall be 20 days later
for every 0.1 cents/kWh that the actual weighted average cost of Transition
Service exceeds the price of Transition Service for these customers by more
than 0.2 cents/kWh. During the second twelve-month period following the
Initial Transition Service End Day, the Recovery End Date applicable to
residential, General Delivery Service Rate G and outdoor lighting customers
shall be 20 days later for every 0.1 cents/kWh that the actual weighted
average cost of Transition Service exceeds the price of Transition Service
for these customers.
5) The provisions of this paragraph shall only apply after the Initial
Transition Service End Day. In the case of the output of nuclear and IPP
entitlements, the Recovery End Date shall be adjusted for the difference
between the wholesale market prices estimated for purposes of this Agreement
and (a) the actual wholesale price for the sale of output of such entitlements
prior to the closing of the sale of all fossil/hydro assets that are intended
to be sold at auction and (b) a proxy for the actual wholesale price for the
sale of the output of such entitlements after the closing of the sale of the
fossil/hydro assets. For nuclear and IPP entitlements, the proxy wholesale
price shall be determined based on the average price realized from the sale
(under the RFP process approved by the Connecticut Department of Public Utility
Control) of the output of The Connecticut Light and Power Company's and Western
Massachusetts Electric Company's shares of Millstone 2, Millstone 3 and
Seabrook, adjusted for differences in capacity factors. After the Initial
Delivery Charge Period, the proxy prices will be escalated by 3% per year. The
Recovery End Date will be adjusted for these factors as follows:
a) The Recovery End Date shall be 30 days earlier for every $10 million by
which the sum of the (a) actual revenue obtained for the period following the
Initial Transition Service End Day and before the closing of both the fossil
and hydro asset sales and (b) projected revenue, after such closing and as
defined below, received from the sale of power from PSNH's Independent Power
Producer ("IPP") entitlements for the period following the Initial Transition
Service End Day and ending on October 31, 2007 exceeds the estimated revenue,
or made later by 30 days for every $10 million by which the sum of such actual
and projected revenue is less than the estimated revenue. The estimated
revenue shall be computed as $171,272,000 plus the product of $98,700 times
the number of days following the Initial Transition Service End Day and ending
on December 31, 2002. An adjustment of less than 30 days will be made on a
pro-rata basis for residual increments of less than $10 million. The
projected revenue from the sale of power from IPP entitlements shall be
computed using the proxy wholesale market prices described above, and, in
order to translate the proxy wholesale price into a cents per kilowatt-hour
number, an annual IPP capacity factor of 95%, and the yearly megawatt-hour
values listed below. The values for the years 2001 or 2002, as applicable,
shall be pro-rated for the actual period following the Initial Transition
Service End Day through the end of that calendar year.
Year MWh
2001 1,126,000
2002 1,126,000
2003 1,119,000
2004 1,122,000
2005 1,095,000
2006 964,000
2007 608,300 Through Oct. 31, 2007
b) The Recovery End Date shall be 30 days earlier for every $10 million by
which the sum of the (a) actual revenue obtained following the Initial
Transition Service End Day and before the closing of both the fossil and hydro
asset sales and (b) projected revenue received from the sale of power from
PSNH's Seabrook Power Contract entitlement for the period following the Initial
Transition Service End Day and ending on December 31, 2003 exceeds the
estimated revenue, or made later by 30 days for every $10 million by which the
sum of such actual and projected revenue is less than the estimated revenue.
The estimated revenue shall be computed as $107,488,000 plus the product of
$263,400 times the number of days beginning after the Initial Transition
Service End Day and ending on December 31, 2002. An adjustment of less than
30 days will be made on a pro-rata basis for residual increments of less than
$10 million. The projected revenue from the sale of power from PSNH's
Seabrook entitlement shall be computed using the proxy wholesale market
prices described above, an annual Seabrook capacity factor of 82%, and the
yearly megawatt-hour values listed below. The value for the years 2001 or
2002, as applicable, shall be pro-rated for the actual period following the
Initial Transition Service End Day through the end of that calendar year.
Year MWh
2001 2,851,000
2002 2,852,000
2003 3,154,000
6) The Recovery End Date shall be 30 days earlier (or later) for each $50
million by which the amount of RRBs issued by PSNH pursuant hereto exceeds
(or is less than) $575 million.
D. Energy Charges
On and after Competition Day, except for Transition Service and Default Service
obligations established by this Agreement and obligations to purchase power
from IPPs, PSNH will no longer have any obligation to build, provide, plan for,
or buy energy, capacity, or other generation related services for its retail
customers. Following Competition Day, three options will be available to
customers for energy service: a Competitive Supplier of the customer's
choice, Transition Service, or Default Service. Transition Service will
be available for the time periods set forth in RSA Chapter 369-B for those
customers who have not chosen a Competitive Supplier, or as otherwise
provided below, thus providing stable and predictable prices during the
transition to a fully competitive market. Default Service will provide
a safety net and assure universal access for customers who are not receiving
energy from a Competitive Supplier and who are not eligible for Transition
Service.
1. Competitive Energy Service
On and after Competition Day, customers may be able to obtain even greater
rate reductions by choosing from among authorized Competitive Suppliers.
2. Transition Service
Transition Service will be available for the time periods set forth in RSA
Chapter 369-B for those customers who have not chosen a Competitive Supplier,
or as otherwise provided below, thus providing stable and predictable prices
during the transition to a fully competitive market. Transition Service will
be secured in accordance with the requirements of RSA 369-B, with the costs
of administering such acquisition to be considered an administrative cost of
Transition Service. Provisions under this Agreement regarding the sale of
output into the market from PSNH's generating plants and entitlements are
subject to the use of such power to provide Transition and Default Service
in accordance with the provisions of RSA Chapter 369-B. All authorized
energy suppliers, as limited by RSA Chapter 369-B, will be permitted to bid
to provide Transition Service. The possibility of dividing the Transition
Service market among the energy suppliers with the lowest bids will be
considered after bid receipt and analysis, in which case a subsequent round
of bidding, at the discretion of the PUC, may be used to assess its benefits.
Transition Service shall be procured in such time blocks as shall prove
efficient and effective after analysis of the bids is made. PSNH will offer
branding to the successful bidder(s), including use of name identification on
bills or bill inserts.
The retail price of Transition Service will be as set forth in RSA Chapter
369-B. If the price obtained through competitive bids is higher than the
Transition Service price, the excess will be deferred and collected through
the non-securitized portion of the SCRC, subject to the limitation on recovery
of any such deferral as set forth in RSA Chapter 369-B, and the Recovery End
Date shall be adjusted pursuant to Section V(C)(4).
Customers will be free to terminate Transition Service as of the end of any
billing cycle to purchase from a Competitive Supplier in the market, without
cost or penalty. PSNH shall be notified of such change by the Competitive
Supplier pursuant to the terms of PSNH's Tariff. PSNH will make customers
aware of their right to terminate Transition Service by prominently displaying
a message to that effect on each customer's bill.
An election to terminate Transition Service by customers served under Tariff
rates GV, LG or B will be final. After an election to terminate, such
customers will qualify for Default Service, but not Transition Service.
Remaining customers who choose to terminate Transition Service will be allowed
to return to Transition Service at any time during the first year following
Competition Day. Low-Income customers (as defined in Section V(E)(1), the
Low-Income Electric Assistance Program section of this Agreement) will be
allowed to return to Transition Service at any time during the Transition
Service period. At the end of the Transition Service period at least 75
percent of customers who have not selected a Competitive Supplier will be
assigned to one of the entities that have provided transition power and that
qualifies as a Competitive Supplier. These assignments will be based on the
ratio of transition power provided by each such supplier who is a Competitive
Supplier during the period. Any Transition Service customer subject to such
assignment shall be notified in advance of the assignment in a form and manner
determined by the PUC. Any customers not so assigned to such an entity that
has provided transition power shall be randomly assigned to other Competitive
Suppliers pursuant to RSA 369-B:3, IV,b,(1),(B),(ii). The administrative cost
of acquiring, billing and managing Transition Service will be recovered
through the Delivery Charge for all customers.
3. Default Service
Electricity is an essential service, and there is a risk in a competitive
market that some customers will find themselves unable to secure a Competitive
Supplier or they may temporarily be between suppliers. To assure universal
service and system integrity, Default Service will be available to customers
who are not receiving energy from a Competitive Supplier and who are not
eligible for Transition Service. Default Service shall be acquired in
accordance with RSA Chapter 369-B for the period of time that Transition
Service is available to any customer class; thereafter, auctions to procure
service for subsequent periods will be conducted at such times and on such
terms and conditions as the PUC may require. Default Service shall be
provided pursuant to terms and conditions established by the PUC. The
administrative cost to acquire, bill and manage Default Service will be
recovered as provided by statute. The price of Default Service shall be the
weighted average of all successful bids. However, during the period when
Transition Service is available, in no event shall the price of Default
Service to the customer be less than the Transition Service prices, unless
otherwise ordered by the PUC, and any differential will be used to defray
Non-Securitized Stranded Costs as provided in Part 3 of the SCRC.
E. System Benefits and Energy Consumption Tax
The System Benefits Charge will be a cents per kilowatt-hour charge designed
to fund PUC-approved public benefit programs, including but not necessarily
limited to the Low- Income Electric Assistance Program and the Energy
Efficiency Programs specified below. The initial System Benefits Charge will
be 0.2 Cent/kWh as required by RSA Chapter 369-B. The accounting for the
System Benefits Charge by PSNH shall be subject to the approval of the PUC
and RSA 374-F:3,VI and 374-F:4,VIII(b), as applicable. The System Benefits
Charge shall be applied equally to all classes of customers and to all
kilowatt-hours billed to customers taking delivery service from PSNH. The
Energy Consumption Tax shall be the amount specified by RSA 83-E:2.
1. The Low-Income Electric Assistance Program
The Parties recognize that electric service is essential, and that programs
and mechanisms that enable low-income residential customers to manage and
afford essential electricity requirements will be necessary, in accordance
with RSA 374-F:3,V(a). To accomplish this, PSNH agrees to implement a
"percentage of income" payment program on Competition Day, consistent with
the statewide low-income Electric Assistance Program proposed by the
Low-Income Working Group and approved by the PUC during oral deliberations on
May 10, 1999, as part of Docket No. DR 96-150.
The Low-Income Electric Assistance Program shall provide service to low-income
residential customers on the basis of an affordable percentage of the
customer's income. Individuals or families whose annual income is less than
150% of the federal poverty level shall be eligible for the low-income
program, subject to funding limitations and such eligibility requirements as
may be established under the PUC-approved guidelines of the Low-Income Working
Group. This program will be funded by a charge assessed uniformly on all
kilowatt-hours billed by PSNH as part of the System Benefits Charge.
If it appears that the statewide Low-Income Electric Assistance Program will
not be ready for implementation by Competition Day, PSNH shall file with the
PUC, and seek approval for an interim low-income program or discount rate to
be in place from Competition Day until the implementation of the statewide
program. The interim low-income program or rate will take effect on
Competition Day or upon such other date as may be specified by the PUC. This
interim low-income program or rate shall provide aggregate rate relief to
low-income customers that is reasonably equivalent to the percentage of income
payment program described above.
2. Energy Efficiency Programs
The Parties recognize that cost-effective energy conservation measures are an
important means to reduce energy usage and, in conjunction with lower rates,
to reduce customers' energy bills. Consistent with the legislative directive
at RSA 374-F:3,X that restructuring should include utility-sponsored energy
efficiency programs targeting cost-effective opportunities which may otherwise
be lost due to market barriers, the Parties understand that the PUC will decide
the appropriate level of future funding for energy efficiency, informed by
recommendations of the Energy Efficiency Working Group ("EEWG"). PSNH agrees
to support increased energy efficiency program budgets in the EEWG and before
the PUC, consistent with the System Benefits Charge figures set forth below.
Prior to Competition Day, PSNH will spend amounts ordered by the PUC for
energy efficiency and DSM programs, as established in Docket No. DR 98-174
(the 1999 PSNH Conservation and Load Management proceeding) and in any
subsequent proceeding. If, prior to Competition Day, the PUC has rendered a
decision on the recommendations of the EEWG, the Energy Efficiency Program
portion of the System Benefits Charge implemented on Competition Day shall
reflect the results of that decision. Any changes in the authorized
expenditures covered by this paragraph shall be subject to the rate adjustment
provisions for public policy changes set forth in Section V(F)(1) of this
Agreement.
F. Other Rate Issues
1. Changes in Nuclear Decommissioning and Public Policy Charges
Prior to Competition Day, any interested person may petition the PUC to adjust
PSNH's bundled rates to reflect changes in the Nuclear Decommissioning Charge
made after August 2, 1999 and/or any new level of public policy expenditures
ordered by the PUC after August 2, 1999. The other Parties to this Agreement
agree to support any such substantiated petition for an increase by PSNH.
2. Fuel and Purchased Power Adjustment Clause ("FPPAC")
The FPPAC rate will be frozen at the currently effective amount of 0.383
Cent/kWh and an FPPAC BA amount of 6.281 Cent/kWh until Competition Day,
except as provided for special contracts in Section VII. On Competition
Day, the FPPAC will be eliminated. Any unrecovered FPPAC balances as
determined by the PUC (including deferred FPPAC charges) will be eligible
for recovery as allowed under Part 3 of the SCRC. Inasmuch as the write-
off that PSNH has taken under this Agreement reflects adjustments to
historical FPPAC balances, the recovery of PSNH's FPPAC balance as of
August 2, 1999 shall not be subject to a prudence determination. However,
the recovery of any FPPAC accruals that occur after August 2, 1999 shall be
subject to the prudence standard of this Agreement.
3. Sharing Agreement.
The Sharing Agreement and the Capacity Transfer Agreements between PSNH and
the NU initial system will be terminated, effective as of December 31, 1999,
with no financial compensation due either party, except for capacity and
transmission payments for November and December, 1999, which are estimated
to be $8.4 million, and final reconciliation as determined pursuant to FERC
contract requirements for amounts due with respect to entitlements or
transactions occurring before this termination date.
4. The Rate Agreement and the Seabrook Power Contract.
As a condition precedent to Competition Day, NU must have obtained the consent
of the New Hampshire Attorney General, and all other necessary regulatory and
lender approvals, to cancel the November 22, 1989 Rate Agreement between NU
and the State and the November 22, 1989 Seabrook Power Contract between PSNH
and NAEC. The Attorney General hereby consents to such cancellations,
contingent on implementation of this Agreement.
G. Avoided Costs for IPPs
PSNH's responsibilities and avoided cost rates on and after Competition
Day for short-term purchases of IPP power pursuant to the federal Public
Utility Regulatory Policies Act and the New Hampshire Limited Electrical
Energy Producers Act shall be equal to the payments received by PSNH for sales
into the ISO-New England power exchange, adjusted for line losses, wheeling
costs, and administrative costs. This Agreement is not intended to impair
existing rate orders or contracts.
H. Termination of Pilot Program
To allow PSNH to prepare for the implementation of this Agreement, PSNH's
participation in the New Hampshire Retail Competition Pilot Program (Docket
No. DR 95-250) shall terminate as of pilot customer meter readings during the
month following receipt of a Final Order.
VI. TRANSMISSION AND DISTRIBUTION ISSUES
A. Classification of transmission and distribution facilities
PSNH has functionally classified its Transmission and Distribution using a
similar method to that proposed by PSNH in PUC Docket No. DR97-059. The
proposed allocations are subject to PUC approval. The Parties agree that
the allocations satisfy the FERC 7 Factor Test. The line of demarcation
between Transmission and Distribution is at the high side of the facilities
that interconnect with facilities rated 69 kV and above and that step-down
to facilities rated at or below 34.5 kV. Following PUC approval, PSNH shall
file and the Parties shall support a notification of such reclassification
with FERC.
To the maximum extent allowed by federal law, non-discriminatory, open access
to PSNH's transmission system shall be available to customers, electricity
suppliers, marketers, aggregators, and municipal electric utilities, with
charges based only on rates set by federal regulations, plus the actual cost
of service for any services not subject to federal price regulation plus, for
retail customers, applicable stranded cost recovery charges, RRB charges,
systems benefit charges, and taxes.
B. White Lake Power Plant
Pursuant to RSA 374-F:3,III, the White Lake Combustion Turbine plant will be
retained by PSNH, and run as needed to maintain reliability and stability on
PSNH's electrical delivery system. Any energy produced by this plant and the
capacity represented by this plant will be sold on the wholesale market or
sold to the New England Independent System Operator ("ISO") at the ISO market
clearing prices in a prudent manner designed to maximize net revenues. The
cost and revenue associated with this plant shall be reflected in the
determination of PSNH's Delivery Charge.
In the event the White Lake power plant is rendered inoperable, the Parties
agree that PSNH shall have the right, subject to PUC approval, to either
repair or replace the unit with another unit of similar capabilities or seek
to modify, upgrade or construct new facilities on the PSNH Transmission and
Distribution system in order to maintain system integrity, if prudent and
consistent with least-cost planning principles. PSNH may, at its discretion,
initiate a request for the siting of a new merchant generator in this
geographical area to support the reliability needs of the PSNH's
electrical system.
VII. SPECIAL CONTRACT, ECONOMIC DEVELOPMENT AND BUSINESS RETENTION CUSTOMERS
As of Competition Day, PSNH will no longer be a retail energy supplier.
Accordingly, it will be necessary as of that date to modify the special
contracts it has with certain customers for the supply of electric energy.
To accomplish this end, all customers served under special contracts in
existence as of Competition Day may elect one of the following three options.
Customers will be informed by PSNH of their option rights at least 60 days
prior to Competition Day. To the extent practicable, Economic Development
and Business Retention customers shall have the same options.
Option 1. The customer may retain the special contract. The
prices will be dictated by the special contract, and the customer will
receive energy under Transition Service and thereafter Default Service with
no additional payments for energy. If the customer's special contract refers
to the terms "FPPAC" and "FPPAC BA," those terms will equal the values
established in Order No 23,139 in Docket No. DR 98-139 of 0.383 cents per
kilowatt-hour for FPPAC and 4.955 cents per kilowatt-hour for FPPAC BA. All
electrical power must be delivered through the PSNH meter except for any
self-generation or co-generation currently permitted under terms of the
customer's special contract; or
Option 2. The customer may have the special contract partially
unbundled. The energy charges under the contract will be reduced by 4.4
cents per kilowatt-hour. The customer may contract with and receive power
from any Competitive Supplier for the remaining term of the special contract.
All other provisions of the special contract shall remain in effect except
for the provision for PSNH as sole supplier. All electrical power must be
delivered through the PSNH meter except for any self-generation or co-
generation currently permitted under the terms of the customer's special
contract. Once this Option 2 is elected, the customer may not return to
Option 1; or
Option 3. Provided there is a termination or cancellation clause
in the special contract, the customer may at any time cancel the remainder of
the special contract and pay whatever termination charges are provided in the
contract. Upon termination the customer will receive market energy and take
other services under tariffed rates, as any other similarly situated
customer. The proceeds of all termination charge payments will be used to
offset Stranded Costs.
If a special contract customer makes no election on or before
Competition Day, Option 1, above, will be the terms under which the customer
will be served. Upon termination by the expiration of the special contract
term or by the exercise of any termination provision of the special contract,
the customer will receive market energy and take other services under Tariff
rates.
A portion of the revenue received from special contract, ED and BR
customers will contribute to the payment of Rate Reduction Bonds. Such
portion shall be calculated in a manner similar to the determination of RRB
cost recovery for Tariff customers. Any revenue from those customers in
excess of the sum of the RRB Charge, the System Benefits Charge, the Energy
Consumption Tax, the overall average Delivery Charge, and the Transition
Service charge (if applicable) shall be applied to the recovery of Parts 2
and 3 of the SCRC.
VIII. DIVESTITURE
A. General
PSNH will divest itself of its power generation assets and power purchase
agreements as a result of this Agreement. This divestiture will take place
through several processes including the sale of its existing power generation
facilities at auction. This is in keeping with other divestitures that have
been accomplished throughout New England as restructuring has taken place.
The goals of the asset auctions are to maximize the net proceeds realized
from the sale in order to mitigate Stranded Costs, to provide a market-based
determination of Stranded Costs, and to help establish a competitive energy
market, while at the same time providing certain employee protections as set
forth herein.
It is likely that a time lag will exist between Competition Day, when
customers are free to choose their own Competitive Supplier, and the actual
closing on the sale of any or all of the power generation assets and power
purchase agreements. During this period, the power produced by these assets
and obtained from the power purchase agreements will be used to provide
Transition Service and/or Default Service pursuant to RSA Chapter 369-B or
sold in the marketplace in accordance with Section IX, the "Marketing of
Energy" section of this Agreement.
The sale of generating assets will be administered by the PUC pursuant to RSA
Chapter 369-B.
B. Timing and Details of the Fossil/Hydro Auctions
The fossil and hydro auction processes will consist of an initial non-binding
bid phase ("First Round") during which time interested parties may bid for
the entire portfolio or specified subsets. In the First Round, interested
parties will be given access to the data room, invited to ask preliminary
questions, and conduct initial due diligence. Following the First Round, a
group of the most qualified bidders will be selected and offered the
opportunity to participate in the Second Round of bidding. During the Second
Round, these bidders will be given the opportunity to conduct detailed due
diligence, ask detailed questions, participate in management interviews,
visit the principal sites and submit binding bids. At the time of the
initiation of the Second Round of bidding, the selected participants will be
advised as to any mandatory groupings of the assets, on which they will be
required to bid. The decision to group assets for final bidding will be
based upon the results of the First Round of bids and other information that
is known immediately prior to the Second Round.
As described in Section VIII(E) of this Agreement, municipalities which have
expressed interest in purchasing hydroelectric generating assets, and which
have not reached satisfactory terms with PSNH to purchase such assets in
private sales outside the auction process, will be included in the Second
Round bidding process.
Following receipt of the binding Second Round bids, PSNH may, with PUC
oversight, elect to conduct an additional round of bidding, in real-time,
including selected finalists, to further improve the prices that will be
realized by PSNH and to improve the terms and conditions of the sale.
Pursuant to RSA Chapter 369-B, affiliates or subsidiaries of NU and
Consolidated Edison, Inc. may not bid on PSNH's generating assets. A secure
internet web site will be used to provide data room information and
transaction documents related to the sale to interested parties and a
designated financial advisor will serve as the intermediary for all
communications between bidders and PSNH throughout the bidding process.
The divestiture of PSNH's fossil assets shall be separated from the sale of
its hydro assets. The divestiture of the fossil assets shall occur first and
the sale of the hydro assets shall occur between six months and one year
following Competition Day to accommodate the special timing needs of
municipalities. PSNH acknowledges that the conduct of the auction is subject
to administration by the PUC, and that the personnel designated by the PUC to
assist in such administration will have the right and opportunity to inquire
and consult with PSNH on any aspect of the auction process, on a timely
basis.
C. Facility Descriptions
The PSNH fossil/hydro generating assets to be divested via auction are
described in Appendix G.
D. Approvals
The following approvals have been identified as being required prior to the
closing of any sale, resulting from the fossil/hydro auction or other sale
process:
1. Federal
Federal approvals will be required from FERC for the transfer to the buyer of
any jurisdictional facilities, the jurisdictional hydroelectric projects and
FERC licenses, and the Interconnection and Operation Agreement.
Securities and Exchange Commission ("SEC") approval will be required because
PSNH is a wholly-owned subsidiary of Northeast Utilities, a registered
holding company under the Public Utility Company Holding Company Act of 1935
may be required.
The pre-merger notification requirements of the Hart-Scott-Rodino Act will
require PSNH and the buyer to file notification regarding the intended sale.
2. State
In addition to approvals required from the PUC, the following State approvals
will also be required:
Approval will be required by the Connecticut Department of Public Utility
Control under Conn. Gen. Stat. Section 16-43 for the sale of any utility
asset by PSNH.
Approval will be required by the Vermont Public Service Board under Vt.
Stat. tit. 30, Section 109 for the sale of PSNH's generating plant located in
Canaan, Vermont.
Approval may be required from the Maine Public Utilities Commission under Me.
Rev. Stat. tit. 35-A, Section 1101 for the sale of PSNH's minority interest
in the Wyman 4 generating station located in Maine.
Approvals and appropriate findings from New Hampshire, Massachusetts and
Connecticut regulators under section 32(c) of the Public Utility Holding
Company Act of 1935.
3. Other
The Sale may require prior consent of certain lenders under PSNH's existing
credit agreements. In addition, the sale may require additional regulatory
approvals that will be based on the identity and regulatory requirements
applicable to the selected buyer(s) of the divested assets. PSNH will
diligently seek to obtain all necessary approvals.
E. Municipal Interest in Purchasing Hydroelectric Generating Assets
Prior to the commencement of the hydro asset auction, PSNH may enter into
agreements for the sale of hydroelectric generating assets to any interested
municipality, subject to PUC approval. Any such assets sold in this manner
will be excluded from the hydro auction. If no such agreements are reached,
all interested municipalities will be able to participate in the auction
process, subject to the same confidentiality, financial qualification and
other requirements that will be imposed on non-municipal participants in the
auction. A municipality may also petition the PUC for a valuation of a
hydroelectric generating asset pursuant to Chapter 249, Section 5 of the
Session Laws of 2000.
It will be necessary that any arrangements with municipalities for purchase
of a hydroelectric asset satisfy the following requirements:
1. In order to be considered, the proposal from the municipality must
conform to the following offer criteria:
(a) the offer must be for a specific purchase price, not subject to
qualification, and payable in full at closing.
(b) the offer must clearly demonstrate the existence of adequate funding
in place, or binding commitment to provide such funding at closing,
sufficient to pay the price in full at closing.
(c) the offer must be to purchase the same hydroelectric generating
asset, adjacent lands, grant the same employment protections and benefits and
other requirements as PSNH is proposing to establish in the fossil and hydro
auctions.
(d) the offer must not contain any major contingencies other than (i)
approval of the price term by the PUC, and (ii) for FERC licensed facilities,
approval by FERC of the transfer of the hydro license to the buyer.
2. PSNH will have the absolute right to reject any offer which does not
promise to meet or exceed the price which PSNH could reasonably anticipate
receiving for the asset if the asset were to be sold as part of the auction
process.
F. Hydro Quebec
The purchase and sale of electricity from Hydro-Quebec ("HQ") is part of a
series of agreements among HQ and certain New England utilities
(collectively, the "HQ Participants") governing the interconnection and sale
of energy between NEPOOL and the HQ power systems. PSNH is a HQ Participant.
The purchase and sale between the HQ Participants and HQ is governed by the
following agreements:
1. HQ Phase II Energy Contract or Firm Energy Contract
This contract, dated October 14, 1985, requires NEPOOL members to purchase
7,000 GWh of energy from HQ each year through August 2000. In the event that
this allotment has not been fulfilled, the contract may be extended until
August 2004 to allow NEPOOL members to meet their energy purchase obligation.
This contract enables PSNH to buy firm energy utilizing its entitlement in
the transmission facility through August 2000. Based on PSNH's firm
transmission facility entitlements, its purchase entitlement under this
agreement is on average 140 MW. Purchases of energy through this entitlement
are based on the Average Fossil Fuel Cost index, which has reflected regional
energy market values.
2. HQ Energy Banking Agreement
This agreement, executed on March 21, 1983, allows NEPOOL participants to
deliver energy to HQ in periods of low NEPOOL incremental cost and receive it
back (less any losses) in periods of high incremental cost. The energy
banking agreement expires in October 2001.
3. HQ Support Agreements
The participating New England utilities, including PSNH, also share in the
cost of service associated with the New England HQ transmission facilities,
as specified in the HQ support agreements. The agreements to which PSNH is a
party include: (1) Terminal Facility Support Agreement; (2) Vermont
Transmission Line Support Agreement; (3) New Hampshire DC Facilities Support
Agreement; (4) Massachusetts DC Facilities Support Agreement; and (5) New
England Power AC Facilities Support Agreements. The first two agreements
were executed on December 1981 and are scheduled to terminate on the same
date as Phase II support agreements. The remaining three agreements were
executed on June 1, 1985, extend 30 years from the date of initial payments,
and are scheduled to terminate on October 31, 2019. These agreements may be
extended for an additional 20 years beyond the scheduled termination date.
The annual cost of these support payments is approximately $10 million for
PSNH. Because support payments are based on cost of service, they may
fluctuate from year to year.
G. Wyman Unit 4
PSNH may sell its ownership interest in Wyman Unit 4, located in Yarmouth,
Maine, outside of the auction process. Should there not be an executed
purchase and sales agreement for the sale of PSNH's ownership interest in
Wyman Unit 4 prior to there being a Final Order approving this Agreement,
then that ownership interest will be included in the fossil asset auction.
H. Other Potential Generation Sites
PSNH has identified three parcels of land that may have significant potential
for use as generation sites. These sites have been previously disclosed
within PSNH's 1996 Long-Range Plans for Bulk Power Supply Facilities filings.
These sites are the Rollins Farm site in Newington, NH; the "Ball Field"
adjacent to Merrimack Station in Bow, NH; and the Garvins Falls Road site in
Concord, NH.
PSNH will develop a sales strategy for soliciting interest and selling these
properties no later than 30 days following the selection of a winning bidder
or bidders in the later of the fossil and hydro asset auctions. The sales
strategy will include a determination of the highest and best use for the
properties, which will determine the maximized values and identify the
appropriate target markets for these properties. The City of Concord shall
be able to provide input in the development of the auction criteria for the
Garvins Falls Road site. At the time that the sales process begins, PSNH
will identify prospective purchasers, including all potential bidders in the
initial solicitation of interest in the fossil and hydro auctions, as well as
other parties who indicate an interest in these properties.
For parcels of land that are accounted for below-the-line, PSNH shall apply
50% of the amount by which the net proceeds exceed the net book value as a
credit against Stranded Costs and may retain the balance of such amount for
the benefit of its shareholder. For any parcels of land that are accounted
for above-the-line, 100% of the net proceeds shall be used as a credit
against Stranded Costs.
I. Millstone 3
On or before Competition Day PSNH will separately account for its 2.8475%
ownership share of Millstone 3 such that the costs and revenues of such
ownership do not impact PSNH's retail customers. The amount of PSNH's net
book investment in Millstone 3 immediately prior to such separate accounting
will be eligible for securitization, the cost of which will be recoverable
from PSNH's customers via Part 1 of the SCRC. If PSNH's share of Millstone 3
is sold or auctioned after such separate accounting , any net proceeds may be
paid as a dividend to PSNH's shareholder and PSNH's customers shall have no
claim to any such proceeds.
Subsequent to such separate accounting, PSNH shall continue to be responsible
for funding its pro rata share of the site-specific decommissioning cost
estimate, calculated on the basis of fully funding the decommissioning trust
by December 31, 2026. PSNH may enter into a contract to provide for the
payment of these nuclear decommissioning costs, with full recovery of the
costs of that contract being provided from PSNH's customers via Part 2 of the
SCRC. PSNH's obligation thereunder may be assignable to any future owner of
such share of Millstone 3. PSNH's customers shall have no responsibility for
increases in decommissioning funding above the amount calculated based upon
the foregoing payment schedule at Competition Day.
If for any reason the separate accounting for PSNH's share of Millstone 3 is
delayed beyond Competition Day, beginning on Competition Day and continuing
until such time as PSNH's ownership share of Millstone 3 is so transferred,
its output will be sold into the market pursuant to Section IX and all net
proceeds will be applied to Stranded Costs.
J. Vermont Yankee
PSNH is a 4.0% shareholder and sponsor company of the Vermont Yankee
Nuclear Power Corporation ("Vermont Yankee"), a Vermont corporation that owns
and operates a nuclear generating unit ("Unit") having a net capability of
approximately 510 megawatts electric, at a site in Vernon, Vermont. Pursuant
to a Power Contract dated as of February 1, 1968, as amended, and an
Additional Power Contract, dated as of February 1, 1984, each of which have
been approved by the Federal Energy Regulatory Commission, PSNH is entitled
to its pro rata share of the net capacity and electrical output during the
Unit's operating life and is obligated to pay its respective entitlement
percentage of Vermont Yankee's cost of service, including future
decommissioning costs.
PSNH, in conjunction with the other sponsor companies, is seeking to cause
Vermont Yankee to sell via private negotiations the Unit and related assets,
including the decommissioning trust. The terms of any such sale will be set
forth in a definitive agreement that provides for a closing that is subject
to receipt of all required regulatory approvals, including that of the PUC.
In such a transaction, PSNH may be obligated to prefund or fund its share of
the future decommissioning costs of the Unit, with full recovery of such
decommissioning costs from PSNH's customers via Part 2 of the SCRC. PSNH
agrees to exercise reasonable efforts to negotiate the buyout or buydown of
any contractual obligations that survive the sale of the Unit. If approved
by the PUC, PSNH shall be entitled to full recovery of such buyout or buydown
payments (exclusive of the decommissioning costs recoverable under Part 2 of
the SCRC) from PSNH's customers via Part 3 of the SCRC. Further, PSNH agrees
to pursue sales terms that limit its responsibility to no more than its pro
rata share of the site-specific decommissioning cost estimate that exists at
the time of closing and that make any future changes to the estimate the
express responsibility of the buyer.
Unless otherwise ordered by the PUC, if the above transaction does not close,
PSNH will offer for sale through a public auction process its interest in
Vermont Yankee, including its associated contractual interests and
obligations. Any sale pursuant to such auction process shall be subject to a
confidential minimum price condition in an amount that will be established,
in advance, by the PUC and designed to stimulate participation in the auction
and to maximize proceeds. PSNH will be responsible for conducting the public
auction, and the PUC shall oversee the process and approve any resulting
transaction prior to the closing. Such transaction shall also be subject to
the receipt of any other necessary regulatory and lender approvals.
If for any reason PSNH continues to have power entitlements from Vermont
Yankee, beginning on Competition Day and continuing until such time as PSNH's
entitlements to power from Vermont Yankee end, such entitlements will be sold
in the marketplace in accordance with Section IX, the "Marketing of Energy"
section of this Agreement.
K. Seabrook
PSNH's overmarket obligations under the Seabrook Power Contract with North
Atlantic Energy Corporation ("NAEC") will be securitized and the costs
thereof recovered from PSNH's customers under Part 1 of the SCRC. PSNH will
use such proceeds of securitization to restructure the Seabrook Power
Contract effective as of Competition Day, subject to necessary regulatory
approvals, to provide for the buydown of the value of the Seabrook asset to
$100 million, thereby reducing PSNH's monthly charges under the contract.
NAEC may, subject to PUC approval, apply the restructuring payments it
receives from PSNH to repay capital in a manner designed to most efficiently
reduce its costs.
Subsequent to Competition Day, NAEC will seek PUC approval of a definitive
plan to sell via public auction its share of Seabrook, with such sale to
occur no later than December 31, 2003. The public auction shall be subject
to PUC administration and to the requirements, if any, of the Seabrook Joint
Owners Agreement. NAEC will submit a plan for the sale to the PUC. The PUC
shall determine prior to the auction a confidential minimum bid for this
sale, designed to stimulate participation in the auction and to maximize
proceeds. NAEC shall make all reasonable efforts to include minority
ownership shares (including that of The Connecticut Light and Power Company)
in the sale of Seabrook, so that a controlling interest may be offered.
Concurrent auctions, including ones that may be subject to regulatory
oversight other than by the PUC, may be required to aggregate a controlling
shares.
Subject to approval of FERC, on Competition Day NAEC will lower its overall
ROE to 7%, but in the event that the PUC either rejects a proposed sale of
Seabrook, or fails to act on such application within 180 days after NAEC's
proposed sale application is filed with the PUC, NAEC's return on equity
shall be increased from 7 percent to 150 basis points more than the average
10-year Treasury bond yield for the preceding 6 months, but not less than 7
percent nor more than 11 percent, and then readjusted accordingly at the end
of every 6 month period. The increase in ROE is only applicable if the
failure of the sale is through no fault of NU or PSNH.
Upon a successful sale of NAEC's share of Seabrook, the existing Seabrook
Power Contract between PSNH and NAEC shall be terminated. However,
subsequent to such sale, PSNH shall continue to be responsible for funding
NAEC's former ownership share of decommissioning liability, calculated on the
basis of full funding by December 31, 2015, using an estimated
decommissioning date of 2015 or as otherwise determined by the Nuclear
Decommissioning Finance Committee. PSNH may enter into a new contract to
provide for the payment of Seabrook nuclear decommissioning costs, with full
recovery of the costs of that contract to be recoverable from PSNH's
customers via Part 2 of the SCRC. Under no circumstances will PSNH's
customers have any responsibility for increases in decommissioning funding
above the amount calculated based upon the foregoing payment schedule as of
the sale date.
Beginning on Competition Day and continuing until such time as NAEC's
ownership share of Seabrook is sold and the closing on such sale occurs, its
output will be sold into the market pursuant to Section IX and all net
proceeds will be applied to Stranded Costs.
L. Failed Auction
PSNH will make every reasonable effort to assure that a "failed auction" does
not occur, resulting in some or all of its fossil/hydro generating stations,
Seabrook, or Vermont Yankee not being sold. Steps to minimize the risk of a
failed auction include the bundling of various assets as "must bid" groupings
at the commencement of the Second Round of the auction process, timing
requirements placed upon municipalities as described in Section VIII(E), and
dedicated marketing of the assets throughout the auction process.
Should assets be left unsold as a result of the auction process, the PUC
shall have the authority to order the divestiture of the asset or obligation.
This may be accomplished by awarding the asset, entitlement, or obligation to
the highest bidder; requiring a PSNH affiliate to pay the minimum auction
price in the case of Seabrook or Vermont Yankee; requiring a PSNH affiliate
to pay the net book value for fossil/hydro generating stations; conducting an
absolute auction; or by such other means as the PUC deems appropriate. If
there is no final sale, PSNH will retain the assets, entitlements, or
obligations and bid their output into the market with the net of costs and
revenues included in Part 2 of the SCRC after the earlier of the Recovery End
Date or the date that the Non-Securitized Stranded Costs are fully amortized.
IX. MARKETING OF ENERGY
A. Prudent Operation of PSNH Generating Assets
Notwithstanding any other provisions of this Agreement, PSNH will be
responsible for prudently operating its fossil/hydro generating assets, and
for prudently managing the generation-related entitlements and purchase
obligations in which it retains an interest until such time as they are sold
or transferred to another entity, or a purchase obligation terminates.
B. Marketing of PSNH Power
1. Fossil Steam, Hydroelectric, Internal Combustion and Nuclear Ownership,
Entitlements or Purchase Obligations
Notwithstanding any other provision of this Agreement, PSNH will be
responsible for the prudent marketing of the output of any generating assets,
entitlements, or purchase obligations which it owns or in which it retains an
interest. Revenues from these sales will include the full capacity and
energy revenue and the revenue from ancillary services related to PSNH's
generating stations and entitlements, and the revenues from the resale of
power purchased under purchase obligations shall include the full revenue
derived from the sale of energy, capacity or other products. All revenue
from these sales shall be used to reduce Non-Securitized Stranded Costs in
the order and manner prescribed in the Stranded Cost Recovery Charge section
of this Agreement.
2. Purchases from Qualifying Facilities ("IPPs") at Short Term Avoided Cost
Rates
For so long as PSNH is required to purchase the output from IPPs under short
term avoided cost rates, it shall be deemed prudent for PSNH to sell or bid
IPP power into the pool at the ISO New England market clearing price.
3. Purchases from Qualifying Facilities ("IPPs") under Long-Term Contracts
or PUC-Approved, Long-Term Rate Orders
PSNH will auction its power obtained from IPPs under long-term contracts or
under PUC approved long-term rate orders. Said auctions will be conducted
under PUC oversight and will occur no more often than once every six months.
The auctions may include all IPPs under long-term contracts and long-term
rate orders or the auctions may include combinations thereof. PSNH may
establish reasonable minimum bids for said auctions. If the actual bids
submitted in these auctions do not meet or exceed PSNH's minimum bids or, for
good reason, some IPPs are not included in the auction, PSNH may sell the
output from these IPPs into the pool at a price no less than the ISO New
England market clearing price until the next semiannual auction. The PUC
retains jurisdiction to determine whether the minimum bid and/or the decision
to exclude certain IPPs from the auction was prudent. Revenues derived from
the marketing of power purchased from IPPs under long-term avoided cost rate
orders and long-term contracts shall be included as a credit to Part 2 of the
SCRC.
C. Procedure for Review of Plant Operation and Marketing of Power
PSNH shall annually file a report and such other information as the PUC shall
require for review by the PUC supporting PSNH's plant operations and the
results of the sale of the output from PSNH's plants, entitlements and
purchase obligations. Such filings shall be made on a time schedule to be
determined by the PUC.
X. EMPLOYEE PROTECTION
As part of the plan to divest generating assets, certain commitments have
been made to represented and non-represented employees. PSNH believes that
those commitments are comparable to commitments made by other New England
utilities that have divested their generation. Such commitments have been
made to PSNH's fossil/hydro employees and to North Atlantic Energy Service
Corporation's ("NAESCO") nuclear employees.
A. PSNH Fossil/Hydro Represented Employees
PSNH is a party to a Collective Bargaining Agreement ("CBA") with the
International Brotherhood of Electrical Workers ("IBEW"), Local 1837 in New
Hampshire. The purchaser will be required to assume PSNH's obligations under
the IBEW-PSNH Fossil/Hydro CBA at the closing of the asset sale. PSNH has
also agreed to provide certain employment protections for non-represented
employees, which the purchaser will also be obligated to assume at the
closing. In each case, the employee commitments to be undertaken by the
purchaser will also be binding upon any successor or assigns or any other
entity acquirer of the purchaser. Costs associated with subsequent workforce
restructuring activities will be borne solely by the purchaser.
IBEW Local No. 1837 represents the bargaining unit employees serving
fossil/hydro, including PSNH Fossil/Hydro Engineering and Operations ("FHEO")
Stores and Production Maintenance. The purchaser will be required to assume
and perform the CBA in the form in place on the closing date. The current
agreement with the IBEW local was effective as of March 21, 1999 and is
expected to expire on May 31, 2002. Key provisions of the CBA include a 3
year wage and benefits package, a memorandum of understanding dated March 12,
1999 regarding the separation of the FHEO agreement from the larger PSNH-wide
Retail Business Group agreement, and an addendum to the agreement covering
issues related to the sale and subsequent transfer of fossil/hydro assets to
a purchaser.
B. NAESCO Represented Employees
NAEC will require that any purchaser of a controlling interest in the
facility provide certain assurances to employees at the time of closing.
Specifically, the buyer will commit to become a party to and honor the
collective bargaining agreement with Local Union Number 555 of the Utility
Workers Union of America that is in effect at the time of closing.
Further, NAEC will propose to require that the buyer offer continued
employment for a period of twelve months (except as describe below) following
the closing to persons who were employed in represented positions during the
three months prior to the closing. In addition, NAEC will work with union
leadership on other negotiable benefits similar to those offered to non-
represented employees.
C. PSNH and NAESCO Non-Represented Employees
The purchaser will be required to offer all non-represented fossil/hydro and
nuclear employees a minimum of twelve months of employment (except as
describe below) following the closing at a level of wages and benefits in the
aggregate not less than such employees are receiving immediately prior to the
closing. The purchaser will also be required to provide out-placement
assistance workshops and tuition reimbursement of up to $3,000 per employee
for job-related education courses or training to non-represented employees
whose employment is involuntarily terminated during the six months following
the twelve month employment period.
If the employment of non-represented employees is terminated during the first
twelve months of employment with the purchaser, for reasons other than cause,
those employees shall be entitled to a severance benefit from the purchaser.
The severance benefit shall include but not be limited to; out-placement
assistance workshops, a lump sum $3,000 payment for retraining assistance; a
one-time payment equal to six months of company contributions for health care
for the employee and the employee's family members covered under the
Northeast Utilities Service Company group insurance plan at the time of
termination; access to an Employee Assistance Program equivalent to that
offered to PSNH/NAESCO employees, for a period consistent with the term of
the health benefits. Additionally, the purchaser shall provide a cash
severance benefit which is the greater of either a) the remainder of pay and
benefits due the employee as a result of the minimum one-year employment
clause or b) a severance payment calculated at two weeks of straight time pay
for each full year of continuous credited service up to a maximum of 52 weeks
of pay, with a minimum of 4 weeks pay.
D. Retirement Benefits for Represented and Non-Represented Employees of
PSNH or NAESCO
1. Pension
The purchaser will be obligated to provide a defined benefit plan that
provides at least a minimum level of pension benefits to any of the
PSNH/NAESCO employees who are employed by the purchaser as of the closing and
subsequently leave employment with the purchaser or subsequent purchasers.
The minimum level of pension benefits that the purchaser will be obligated to
provide will be calculated using the pension benefit formula applicable to
the employee under the PSNH/NAESCO plans as of the closing. The purchaser's
obligation with regards to this pension benefit will be calculated as the
difference between (a) the employee's total pension benefit as calculated
utilizing the pension benefit under PSNH's/NAESCO's plan applicable to the
employee as of the closing, the employee's final average earnings (as so
defined in such plan) with purchaser, and the employee's total years of
service with PSNH and/or NAESCO and the purchaser and, (b) the pension
benefit the employee receives from PSNH or NAESCO, (or any successor or
assign). The PSNH/NAESCO portion of the employee's pension benefit will be
calculated by PSNH/NAESCO as of the closing, based upon the pension benefit
formula, years of credited service and final average earnings applicable to
the employee as of the closing.
2. Pension Rule 85
Effective January 1, 2000, PSNH and NAESCO employees are eligible to receive
full pension benefits beginning at age 55 if they have combined age and years
of service totaling at least 85 (the "Rule of 85").
3. Pension Plan Modification
Any employee who is age 50 to 54 on the date of the announcement of the
winning bidder(s) and whose age plus credited years of service equals or
exceeds 65 years and who is subsequently involuntarily separated from
employment by the purchaser, will be eligible for the following additional
retirement benefits: 1) retiree life insurance equivalent to that provided to
NU system retirees, beginning at separation; 2) continuation of health care
benefits at COBRA rates until age 55, after which retiree health care
benefits and contributions apply; and 3) the option to begin pension payments
before age 55.
An employee eligible to begin receiving pension benefits before age 55 will
be entitled to receive the following percentages of the total pension benefit
to which the employee would be entitled at or after age 55:
Employee Benefits Eligibility
Age when benefits begin Percent of accrued age 65 benefit
55 75%
54 71%
53 67%
52 63%
51 59%
50 55%
4. Pension Benefits - General
The pension benefit must be guaranteed and protected from forfeiture to the
same extent as any ERISA retirement plan benefit. If such benefit should be
subject to Social Security or Medicare taxes that do not apply to ERISA
retirement plan benefits, such benefits will be grossed up to offset any
additional tax liability to the employee.
5. Vesting and Years of Credited Service
The purchaser will apply each employee's prior service with the NU system
companies and service recognition/credited service which was recognized by NU
towards any eligibility, vesting or other waiting period requirements under
the purchaser's employee benefit plans (including, but not limited to,
pension benefits, life insurance, health care benefits, and vacation and sick
time), will waive any pre-existing medical condition provisions under the
purchaser's health care plans in which the employees participate, and will
give the employees credit for any moneys paid toward the annual deductible
under such plans as of the closing. All employees who are vested in the NU
plans as of the closing shall be vested as of the closing in the purchaser's
plans.
E. Fossil/Hydro and Nuclear Employees generally
PSNH and NAESCO will consider offering an early retirement program to all
eligible fossil/hydro and nuclear personnel. The cost of this program will
be the responsibility of PSNH.
F. PSNH Retail Business Group (T&D Company) commitments to Union Workers
PSNH will honor all existing collective bargaining agreements for non-
fossil/hydro employees, including T&D employees.
XI. CODE OF CONDUCT
In PUC Order No 22,875 issued in Docket No. DR 96-150 dated March 20, 1998,
the PUC permitted retail-marketing companies affiliated with jurisdictional
utilities to compete for retail customers in their affiliated distribution
utility's Service Territory, subject to an appropriate Code of Conduct to
protect against anti-competitive behavior. In that same order, the PUC
stated that, prior to the final implementation of a Code of Conduct, the
equivalent Code of Conduct enacted in California should govern. The
California Code is set out in Appendix I. PSNH agrees to abide by the
California Code, as interpreted by the "New Hampshire Affiliate Transaction
Rules Applicable to PSNH and NU" attached hereto as Appendix H until such
time as the PUC adopts a New Hampshire Code of Conduct. The Parties will
recommend that the Code of Conduct to be adopted by the PUC address issues
such as, but not limited to, physical separation, restrictions on common
management or directors, contractual or financial relationships and
preferential treatment.
Regardless of the final PUC order implementing a New Hampshire Code of
Conduct, PSNH agrees: that it will not use its utility status to favor any
affiliated companies, that any customer and/or marketing data provided to any
affiliated company will be simultaneously provided to all other Competitive
Suppliers, that its generating and marketing affiliates will not share office
space or personnel, that its marketing affiliates will not use the name
Public Service of New Hampshire or any similar name, that its affiliates may
not otherwise trade on the name or status of PSNH in marketing efforts, that
its affiliates' books and accounts will be open to inspection by the PUC in
accordance with the provisions of paragraph 11 of Appendix H of this
Agreement, and that it and NU will cooperate to establish market power
measurements and benchmarks that will be effective to monitor how the ISO-NE
power marketplace is operating. The Parties agree to recommend that
resolution of disputes under any market power provisions adopted by the PUC
should be performed in a manner consistent with the arbitration procedures
now in place under the Telecommunications Act of 1996.
XII. EXEMPT WHOLESALE GENERATOR STATUS
Should any entity to whom PSNH sells its generating assets, including any
affiliate of PSNH, be qualified to seek Exempt Wholesale Generator status
under Section 32 of the Public Utility Holding Company Act of 1935 and other
federal law, rules and regulations, the Parties agree that they will support
the purchaser's efforts to obtain any necessary approvals and findings from
the PUC.
XIII. SECURITIZATION OF STRANDED COSTS
A. Role of Securitization in Settlement
The Parties recognize that securitization is a useful tool for lowering
customers' bills and maximizing customer benefits. The issuance of RRBs will
allow PSNH to reduce its cost of capital, thereby significantly reducing
rates for customers. Securitization is expected to account for a material
portion of the 15.3% average rate reduction that will be achieved when this
Agreement is implemented. The Parties acknowledge that securitization of
Stranded Costs is a pivotal element of the settlement, and that passage of
acceptable legislation and the successful completion of the proposed bond
issue are conditions to implementing this Agreement.
B. Legislation
Securitization of Stranded Costs may be considered by the PUC under Chapter
289 of the Session Laws of 1999, section 3 and Chapter 249 of the Session
Laws of 2000. The Parties hereby commit to make all reasonable efforts to
issue the RRBs as expeditiously as possible.
Such legislation authorizes, among other things, the creation by the PUC of
an irrevocable property right to bill and collect nonbypassable RRB Charges
in amounts sufficient to recover RRB Costs associated with the RRBs. Such
irrevocable property right will be referred to as "RRB Property."
Pursuant to RSA Chapter 369-B, the State of New Hampshire has pledged ,
contracted, and agreed that neither the State nor any agency thereof,
including the PUC, will limit or alter the RRB Charge, securitized Stranded
Costs, RRB Property, or the finance order and all rights thereunder, until
the RRBs and any interest, fees and expenses associated therewith are fully
discharged, unless adequate provision is made for the protection of the
owners or holders. The legislation also provides that RRB Property may be
sold in a true sale transaction to a SPSE in order to facilitate the issuance
of RRBs and directs the PUC to adjust the RRB Charges periodically in order
to ensure the timely recovery of RRB Costs (see the description of the True-
Up Mechanism herein).
The RRB Charges will be non-bypassable pursuant to RSA 374-F:3 and RSA
Chapter 369-B, and as provided in Section V(B).
C. PUC Order
Securitization will require the prior approval by the PUC in the form of a
finance order which includes the transaction description, certain findings,
orders and approvals. PSNH will request findings that will maximize the
likelihood of achieving a Triple-A Rating on the RRBs and the marketability
of the RRB issuance.
The PUC will be requested, among other things, to: (i) approve the issuance
of RRBs in an amount consistent with RSA Chapter 369-B, (ii) approve the
organization and capitalization of the SPSE to which the RRB Property will be
sold, (iii) establish the RRB Property and the RRB Charge, (iv) provide for
the periodic adjustment of the RRB Charge via the True-Up Mechanism described
herein, (v) approve the general structure and terms of the RRBs (as
summarized below), (vi) approve the servicing of the RRB Charge by PSNH, as
provided in Section XIII.D.3, as the initial servicer for the RRB Property
(the "Servicer"), or any successor Servicer, under a servicing agreement (the
"Servicing Agreement") and (vii) declare the finance order irrevocable
pursuant to the legislation.
D. RRB Transaction Overview
The finance order sought by PSNH will, among other things, require approval
of the following aspects of the RRB transaction, finding that they are
consistent with achieving the highest rating and therefore the lowest cost on
the RRBs.
1. Sale of RRB Property
a. PSNH will form a bankruptcy-remote, wholly owned SPSE.
b. PSNH will capitalize the SPSE in an amount anticipated to be at
least 0.50% of the initial principal balance of RRBs. These funds will be
deposited in the Capital Subaccount (see Section XIII(D)(5)(b)). This
capitalization is required in order that PSNH may treat the RRB issuance by
the SPSE as debt for tax purposes.
c. An overcollateralization subaccount will be established up to the
level required to achieve the highest credit rating. The amount will be
finalized prior to the issuance of the RRBs and will depend primarily on
rating agency requirements and tax considerations. Collections of RRB
Charges with respect to overcollateralization will be deposited in the
Overcollateralization Subaccount such that the amount therein will accumulate
over time in accordance with a schedule set forth at issuance (see Section
XIII(D)(5)(c)).
d. PSNH will sell the RRB Property to the SPSE in a transaction which
will be intended and treated as a legal true sale and absolute transfer to
the SPSE. A true sale of RRB Property to a bankruptcy-remote SPSE provides
that, in the event of a PSNH bankruptcy, the RRB Property owned by the SPSE
will not become a part of the PSNH bankruptcy estate and PSNH creditors will
have no recourse to the RRB Property or RRB Charges.
2. Issuance of RRBs
a. The SPSE will issue RRBs in one or more series, each of which may be
offered in one or more classes having a different principal amount, term,
interest rate and amortization schedule, and reasonably consistent with the
forecast amortization schedule contained in Appendix D. To the extent
allowed by the PUC in the financing order, the form, term, interest rate
(whether fixed or variable), repayment schedule, classes, number and
determination of credit ratings and other characteristics of RRBs will be
determined at the time of pricing based on then-current market conditions, in
order to achieve the all-in lowest cost financing possible. Under certain
circumstances, the RRBs may be subject to call provisions and may be
refinanced through a subsequent issuance of RRBs to the extent such
refinancing would result in a lower interest cost associated with the RRBs
refinanced. At least 3 business days in advance of RRB issuance, PSNH will
make an informational filing with the PUC consisting of an "Issuance Advice
Letter" setting forth the final terms of the RRBs.
b. RRBs will be non-recourse to PSNH and its assets and will not be
secured by a pledge of the general credit, full faith or taxing power of the
State of New Hampshire or any agency or subdivision of the State of New
Hampshire.
c. The targeted rating on the RRBs will be Triple-A.
d. The RRB Charge is anticipated to be billed until the expected maturity
date of the RRBs, which is 12 years from their date of issuance. However, to
the extent the RRBs have not been fully amortized by such date, the RRB
Charge may continue to be billed until the RRBs are fully amortized and all
costs related thereto have been paid; provided, however, that in no event
will the RRB Charge be billed beyond the legal maturity date of the RRBs
which will not be longer than 14 years from their date of issuance.
e. RRBs will be secured by all of the assets of the SPSE, including without
limitation (i) the RRB Property, (ii) the rights of the SPSE under all
transaction documents such as the purchase agreement by which the SPSE
acquires all rights in the RRB Property (and including any swap agreements in
place with respect to floating rate RRBs), (iii) the Servicing Agreement by
which PSNH, or any successor servicer, acts as Servicer for the RRB Property,
(iv) the Collection Account (as summarized below), (v) certain investment
earnings on amounts held by the SPSE and (vi) the capital of the SPSE.
f. RRBs will be repaid through the collection of the RRB Charge as
described in Section V(B).
g. The RRB Charges will be non-bypassable as provided in Section V(B).
3. Servicing of RRBs
a. On behalf of the SPSE, PSNH will initially act as the Servicer for
the RRB Property, and PSNH, or any successor Servicer, will be responsible
for calculating, billing, collecting, and remitting the RRB Charge.
b. In consideration for its servicing responsibilities, PSNH or any
successor Servicer will receive a periodic servicing fee which will be
recovered through the RRB Charge. In the event of a failure of any customer
to pay the RRB Charge, PSNH, as Servicer, or any utility successor to PSNH,
is authorized to disconnect service to such customer to the same extent that
a public utility may, under applicable law and regulations, disconnect
service to a customer who fails to pay any charge. If PSNH is replaced as
Servicer due to its imprudence, the PUC may consider such lost periodic
servicing fees when determining new delivery rates.
c. In the event that the PUC decides to allow billing, collection, and
remittance of RRB Charges by a third party supplier within the PSNH Service
Territory, such authorization must be consistent with the rating agencies'
requirements necessary for the RRBs to receive and maintain the targeted
Triple-A Rating.
d. PSNH or any successor Servicer will periodically remit (as
frequently as required by the rating agencies) collections of RRB Charges to
the SPSE. The SPSE will use the RRB Charge remittances to make payments of
interest, principal, fees and expenses on the RRBs and to fund certain credit
enhancement reserves (the application of such remittances is described
further herein). PSNH may be required to obtain a letter of credit or other
credit enhancement to protect against any cash collection losses resulting
from the temporary commingling of funds.
e. Depending upon the capability of PSNH's systems at the time of
issuance, PSNH may utilize some type of estimation methodology to determine
the amount of RRB Charges to remit to the SPSE; provided, however, that PSNH
will remain liable to remit the amount of RRB Charges that it actually
collects.
4. RRB Charge
a. The RRB Charge will be established at levels intended to provide for
the full recovery of RRB Costs, based upon assumptions including sales
forecasts, payment and charge-off patterns, and lags between SCRC billing and
collection by the Servicer.
b. So that the RRB Charge may recover interest payments on the RRBs, it will
be calculated to reflect the coupon on the RRBs as determined by market
conditions at the time of issuance. If the RRBs are Triple-A Rated and are
issued prior to December 31, 1999, the coupon rate on the RRBs will be
determined by market conditions at the time of pricing, but PSNH guarantees
an All-In Cost of 6.25%. If the RRBs are Triple-A Rated and are issued
between January 1, 2000 and July 1, 2000, the coupon rate on the RRBs will be
determined by market conditions at the time of pricing but PSNH guarantees an
All-In Cost of 7.25%, (see Section V(B)(3) above).
c. The RRB Charge will be billed so long as RRBs are outstanding, but
in no event after the legal final maturity.
5. Credit Enhancement; Overcollateralization and True-Up Mechanism
a. In order for the RRBs to receive a Triple-A rating, the exposure to
losses due to, among other things, shortfalls in projected sales of energy,
longer-than-expected delays in bill collections, and higher-than-estimated
uncollectable accounts must be minimized. This will be accomplished with
various forms of credit enhancement described in the finance order, including
the various components of the Collection Account and the True-Up Mechanism
described below.
b. The RRB Charge collections will be deposited into an interest bearing
Collection Account, which will consist of a General Subaccount (which will
hold the collections with respect to principal, interest, fees, and expenses)
and at least three other interest bearing subaccounts: the
Overcollateralization Subaccount (which will hold collections with respect to
Overcollateralization (see Section XIII(D)(1)(c)), the Capital Subaccount
(which will hold PSNH's initial capital contribution to the SPSE) and the
Reserve Subaccount (which will hold any excess collections of RRB Charge as
described below). RRB Charge collections in excess of scheduled payments of
interest, principal, fees and expenses on RRBs will be allocated to: (i) the
Capital Subaccount to the extent the amount therein has been reduced to below
the initial capital contribution, (ii) the Overcollateralization Subaccount
up to the required level set forth for such date at issuance by the rating
agencies and (iii) the Reserve Subaccount any remaining amounts. To the
extent that RRB Charges are insufficient to make scheduled payments of
interest, principal, fees and expenses on RRBs during any period, the
accounts will be drawn upon in the following order (i) the Reserve
Subaccount, (ii) the Overcollateralization Subaccount and (iii) the Capital
Subaccount.
c. The RRB Charge will be calculated (both initially and as a result of the
True-Up Mechanism) to recover an amount in excess of the amounts needed to
make payments of principal, interest, fees and expenses on RRBs (such excess,
"Overcollateralization"). The actual amount of Overcollateralization
required to achieve the highest credit rating will be finalized prior to the
issuance of the RRBs and will depend primarily on rating agency requirements
and tax considerations. The Overcollateralization will be collected over
time and deposited to the Overcollateralization Subaccount such that the
amount therein will accumulate over time in accordance with a schedule set
forth at issuance.
d. The RRB Charge will be adjusted up or down pursuant to the True-Up
Mechanism in accordance with the specific methodology described in the
finance order. At the times specified in the order and as approved by the
PUC, an RRB Charge adjustment will be requested such that, during the period
for which that RRB Charge will be billed, RRB Charge collections will be
sufficient to: (i) pay principal and interest on the RRBs in accordance with
the expected amortization schedule, (ii) pay fees and expenses related to
RRBs, (iii) maintain the Overcollateralization Subaccount balance at the
required levels and (iv) restore the capital contribution to the Capital
Subaccount to the extent it has been drawn upon to make payments on RRBs, and
(v) reduce the balance in the Reserve Subaccount to zero. When PSNH
anticipates that the Recovery End Date will occur in six months, it may, at
its option, initiate monthly True-Up Mechanism reconciliations. Similarly,
during the twelve months prior to the expected maturity date and thereafter
until the legal maturity date, PSNH may, at its option, initiate quarterly or
monthly True-Up Mechanism reconciliations. When the RRBs are paid off, any
balances in the Overcollateralization and Reserve will be used to reduce the
Part 2 Stranded Costs.
E. Use of Proceeds
The SPSE will transfer the proceeds it received from the issuance of the RRBs
to PSNH as consideration for the RRB Property. PSNH may use the proceeds of
securitization in such manner as the PUC shall approve in the finance order.
F. State Oversight
The New Hampshire State Treasurer, or other State official designated by the
State Treasurer, shall have oversight over the terms and conditions of the
RRB issue, including but not limited to tax aspects and such other
arrangements to which the Parties may mutually agree, to assure that PSNH
exercises fiscal prudence, and achieves the lowest overall cost for the RRBs.
XIV. OTHER PSNH COMMITMENTS
A. Bankruptcy of NU or Other Affiliates
PSNH and NU agree to take all possible steps to insure that the State, acting
on behalf of PSNH's customers, will be entitled to participate as a party in
any bankruptcy of NU, PSNH or any current or future affiliate during the term
in which any Rate Reduction Bonds remain outstanding.
B. Dividend
Except for the issuance of a dividend pursuant to 2000 N.H. Laws 249:8, PSNH
agrees that it will not make dividend payments to its parent, NU, until the
earliest of the date that the write-off associated with this Agreement has
been taken; or the date that this Agreement is either terminated pursuant to
Section XVI or disapproved by the PUC.
C. Sale of PSNH or NU
If PSNH's T&D assets are sold within five years of Competition Day, for a
premium above 1.5 times the net book value of those assets, less liabilities
and obligations assumed by the purchaser ("Excess Premium"), 1/3 of the
Excess Premium will be credited to Non-Securitized Stranded Costs. If NU
itself is acquired or otherwise sold or merged during that same time period,
it agrees that notwithstanding any contrary provision of law, the merger,
acquisition or sale shall be subject to the jurisdiction of the PUC under RSA
Chapters 369, 374, 378 or other relevant provisions, and that the merger,
acquisition or sale shall be approved only if it be shown to be in the public
interest. A merger of NU that is subject to this section shall not include
acquisitions by NU of other entities.
XV. PROCEEDINGS TO BE TERMINATED UPON IMPLEMENTATION OF SETTLEMENT
A. Federal Court Litigation
On Competition Day, PSNH agrees to dismiss with prejudice the suit it brought
in Federal District Court on the issuance by the PUC of its February 28, 1997
Final Plan for restructuring (D.N.H. 97-97/ D.R.I. 97-121). Due to the fact
that there are other utility plaintiffs involved in the litigation, the
Parties understand that the case may not be dismissed in its entirety.
B. Public Utilities Commission Proceedings
PSNH has sought to stay the following proceedings during the pendency of the
approval process for this Agreement, and those proceedings shall be dismissed
with prejudice upon PUC approval and adoption of legislation authorizing
implementation of the Agreement.
1. DR 96-148
This proceeding was brought by the PUC to determine whether PSNH had used its
'best efforts' to negotiate with IPPs.
2. DR 96-149
This proceeding was brought by the PUC to investigate whether FERC's "light
loading" rules applied to PSNH's purchases from IPPs.
3. DR 96-424
This proceeding was brought to explore whether a commercial customer should
be able to self generate without any obligation to support system costs.
4. DR 97-014 and DR 98-014
These proceedings were brought to consider PSNH's recovery of fuel and
purchased power expenses.
5. DR 97-059
This proceeding was brought to determine new base rates for PSNH.
6. DE 97-167
This proceeding was brought to investigate whether PSNH should have joined
the suit brought by other utilities against NU to recover losses alleged to
have resulted from NU's management of Millstone 3.
7. DF 97-185
This proceeding was brought to allow the PUC to conduct a management audit of
PSNH in relation to the ongoing rate case.
8. DR 98-006 and DR 98-071
These proceedings were brought to evaluate the Least Cost Integrated Resource
Plan ("LCIRP") filing by PSNH.
9. DSF 99-066 and DE 00-092
These proceedings were brought to complete the annual reviews of PSNH's
proposed bulk power projects.
XVI. CONDITIONS FOR IMPLEMENTING THE SETTLEMENT
All conditions set forth in this section must be met to the satisfaction of
all Parties as a condition precedent to implementation of this Agreement, and
the Parties hereby agree to take all reasonable measures to ensure
fulfillment of these conditions. The failure of any of these conditions to
be fulfilled will result in termination of the Agreement, subject to the
provisions of Section XVII(D).
A. The PUC must approve this Agreement by a Final Order, without condition
or modification, unless otherwise agreed to by the Parties as provided in
Section XVII(D).
B. PSNH and NAEC must receive approval from the appropriate lenders pursuant
to existing credit agreements.
C. Legislation must be enacted allowing the securitization of assets
and the issuance of Rate Reduction Bonds in a manner fully consistent with
the terms of this Agreement. This condition has been met by the enactment of
Chapter 249 of the Session Laws of 2000.
D. PSNH must close on the issuance of the Rate Reduction Bonds.
E. PSNH must have entered into agreements to sell power from any remaining
entitlements; or there must be an arrangement in place for PSNH to sell such
entitlements into the wholesale market.
F. All necessary final approvals, without condition or modification, for
other jurisdictional matters must be obtained, as required, from the Federal
Energy Regulatory Commission, the Securities and Exchange Commission, the
Nuclear Regulatory Commission, and the Connecticut Department of Public
Utility Control.
XVII. MISCELLANEOUS
A. Applicable Law
This Agreement shall be governed by the laws of the State of New Hampshire.
The Parties agree that any disputes regarding this Agreement will be subject
to the jurisdiction of the PUC and the appellate jurisdiction of the New
Hampshire Supreme Court.
B. Successors and Assigns
The rights conferred and obligations imposed on the Parties to this Agreement
shall be binding on or inure to the benefit of their successors in interest
or assignees as if such successor or assignee was itself a Signatory hereto.
C. Entire Agreement
This Agreement contains the entire agreement among the Parties respecting the
subject matter herein and supersedes all prior agreements and understandings
between them, including the Memorandum of Understanding among the Parties
dated June 14, 1999. The agreements contained herein are interdependent and
not severable, and they shall not be binding upon, or deemed to represent
positions of, the Parties if they are not approved in full and without
modification or condition by the Commission subject to subsection D of this
section, below.
D. General Provisions
If the PUC does not approve this Agreement in its entirety and without
modification or condition, the Parties shall have an opportunity to amend or
terminate this Agreement. If terminated, this Agreement shall be deemed
withdrawn and shall not constitute a part of the record in any proceeding or
be used for any purpose.
This Agreement is the product of settlement negotiations. The content of
those negotiations shall be privileged and all offers of settlement shall be
without prejudice to the position of any party or participant presenting such
offer.
Acceptance of this Agreement by the PUC shall not be deemed to restrain the
PUC's exercise of its authority to promulgate future orders, regulations or
rules which resolve similar matters affecting other parties in a different
fashion.
The PUC's approval of this Agreement shall endure so long as necessary to
fulfill the express objectives of this Agreement, as supplemented by Chapter
249 of the Session Laws of 2000.
The approvals contemplated by this Agreement shall not be construed as
requiring the PUC to relinquish its authority to develop new policies and
issue orders or to initiate investigations when it deems such actions are in
the public good.
As described below, this Settlement Agreement does not affect the
jurisdiction of the PUC. To the extent that there is a dispute among parties
in Docket No. DR 96-150 regarding the jurisdiction of the PUC and the FERC
over the determination and recovery of Stranded Costs caused by state-
mandated retail access policies, the Parties intend that nothing in this
Settlement Agreement should resolve that dispute, affect the authority of
either regulatory body over this issue, or limit the ability of the Parties
to raise arguments or defenses relating to this jurisdictional issue.
Notwithstanding any other provision of this Agreement, no provision herein
shall be deemed to determine this jurisdictional issue. Accordingly, the
Parties view this Agreement as a negotiated resolution of the issues
presented by the restructuring of PSNH in the context of the PUC's electric
utility restructuring proceeding.
The Parties agree to support this Agreement before the PUC and in any related
legal proceedings or legislative inquiries or hearings, and to take all such
action as is necessary to secure approval and implementation of the
provisions of this Agreement.(c) NUSCO, 1999
Signed this 2nd day of August, 1999
/s/ /s/
Jeanne Shaheen Michael G. Morris
Governor of the State of New Hampshire Chairman, President and Chief
State House Executive Officer
Concord, NH 03301 Northeast Utilities
107 Selden Street
Berlin, CT 06037
/s/ /s/
Philip T. McLaughlin William T. Frain, Jr.
Attorney General President and Chief Operating Officer
of the State of New Hampshire Public Service Company of New
33 Capitol Street Hampshire
Concord, NH 03301 1000 Elm Street
P.O. Box 330
Manchester, NH 03105
/s/
Thomas B. Getz
Executive Director and Secretary
New Hampshire Public Utilities Commission
8 Old Suncook Road
Concord, NH 03301
/s/
Deborah J. Schachter
Director
Governor's Office of Energy and Community Services
57 Regional Drive
Concord, NH 03301
APPENDIX A - SUMMARY OF PROPOSED RATES
Public Service Company of New Hampshire
Current and Target Revenue by Class
Total Revenue
Billed
KWH Current
Rate Class Sales (1) Rates (2) Target (3)
Residential Service 2,294,071,493 $333,425,361 $277,903,821
General Service 1,421,780,341 182,776,854 156,466,927
Primary General Service 1,219,154,700 133,906,224 114,783,415
Large General Service 559,072,437 57,205,610 49,874,852
Outdoor Lighting Service 40,858,107 10,553,509 8,980,203
Total Retail 5,534,937,078 $717,867,558 $608,009,218
Revenue, Cent/kWh
Current Percentage
Rate Class Rates Target Decrease
Residential Service 14.534 12.114 16.7%
General Service 12.855 11.005 14.4%
Primary General Service 10.984 9.415 14.3%
Large General Service 10.232 8.921 12.8%
Outdoor Lighting Service 25.830 21.979 14.9%
Total Retail 12.970 10.985 15.3%
Note: all amounts are based on the 9/98 test year as proformed, excluding
special pricing.
(1) Sales for the Outdoor Lighting class have been recalculated based on the
new kWh amounts shown in the Delivery Service Tariff.
(2) Represents revenues for the 9/98 test year, proformed to the level of
Tariff 38 (temporary) base rates with an FPPAC rate of 0.383 Cent/kWh.
(3) Includes a Transition Service energy charge of 4.400 Cent/kWh.
APPENDIX B - ENVIRONMENTAL RESERVE FUND IDENTIFIED SITES
Messer Street former Manufactured Gas Plant ("MGP") (Laconia, NH)
Keene former MGP (Keene, NH)
Nashua former MGP (Nashua, NH)
Dover former MGP (Dover, NH)
Franklin former MGP (Franklin, NH)
Calcutt Landfill (Dover, NH)
Coakley Landfill Superfund Site (Greenland & North Hampton, NH)
Port Refinery Superfund Site (Ryebrook, NY)
Portland - Bangor Disposal Site (Portland, ME)
Manchester Steam former Generating Plant (Manchester, NH)
Cocheco former Generating Plant (Dover, NH)
Seabrook Station former Landfill (Hampton, NH)
APPENDIX C - ESTIMATED BALANCE OF THE ASSETS AS OF JUNE 30, 2000
(Millions of Dollars)
06/30/00 06/30/00 06/30/00
Book Market Strandable
Balance Value Assets
Seabrook Over-Market Generation Assets 594 100 494
MP3 Over-Market Generation assets 82 0 82
Fossil Over-Market Generation assets(12/00) 178 290 -112
Hydro Over-Market Generation assets(12/01) 24 70 -46
Seabrook Deferred Return - NAEC 90 0 90
Seabrook Deferred Return - PSNH 15 0 15
Acquisition Premiums 310 0 310
Acquisition Premiums - F109 185 0 185
Unrecovered Obligation - YAEC, CY, MY 50 0 50
Deferred SPP Costs 102 0 102
Deferred FPPAC Costs 107 0 107
Deferred VY Contract Termination Payments 0 -9 9
Deferred IPP Contract Termination Payments 0 0 0
Market Value of Wholesale Power Contracts 0 10 -10
Reserves for NHEC Settlement -24 0 -24
Deferred NOx Allowance Credits (12/00) -5 0 -5
Deferred FAS 109 Regulatory Liability 0 0 0
Unamortized Loss of Reacq. Debt (6/00) 3 0 23
Unamortized Loss on Reacq. Debt (12/00) 0 0 11
Unamortized Loss on Reacq. Debt (12/01) 0 0 3
Total Assets 1711 461 1284
(Millions of Dollars)
2000 06/30/00
Written-Off Securitized
Seabrook Over-Market Generation Assets 0 494
MP3 Over-Market Generation assets 0 64
Fossil Over-Market Generation assets(12/00) 0 0
Hydro Over-Market Generation assets(12/01) 0 0
Seabrook Deferred Return - NAEC 90 0
Seabrook Deferred Return - PSNH 15 0
Acquisition Premiums 162 0
Acquisition Premiums - F109 97 0
Unrecovered Obligation - YAEC, CY, MY 0 0
Deferred SPP Costs 0 0
Deferred FPPAC Costs 0 0
Deferred VY Contract Termination Payments 0 0
Deferred IPP Contract Termination Payments 0 0
Market Value of Wholesale Power Contracts 0 0
Reserves for NHEC Settlement 0 0
Deferred NOx Allowance Credits (12/00) 0 0
Deferred FAS 109 Regulatory Liability 0 0
Unamortized Loss of Reacq. Debt (6/00) 1 17
Unamortized Loss on Reacq. Debt (12/00) 0 0
Unamortized Loss on Reacq. Debt (12/01) 0 0
Total Assets 364 575
(Millions of Dollars)
Amort.
Amortized Years
Seabrook Over-Market Generation Assets 0 12
MP3 Over-Market Generation assets 18 12
Fossil Over-Market Generation assets(12/00) -112 12
Hydro Over-Market Generation assets(12/01) -46
Seabrook Deferred Return - NAEC 0
Seabrook Deferred Return - PSNH 0
Acquisition Premiums 148 12
Acquisition Premiums - F109 88 12
Unrecovered Obligation - YAEC, CY, MY 50 8
Deferred SPP Costs 102 12
Deferred FPPAC Costs 107 12
Deferred VY Contract Termination Payments 9 12
Deferred IPP Contract Termination Payments 0 12
Market Value of Wholesale Power Contracts -10 1
Reserves for NHEC Settlement -24
Deferred NOx Allowance Credits (12/00) -5
Deferred FAS 109 Regulatory Liability 0
Unamortized Loss of Reacq. Debt (6/00) 5 12
Unamortized Loss on Reacq. Debt (12/00) 11
Unamortized Loss on Reacq. Debt (12/01) 3
Total Assets 345
APPENDIX D - FORECAST AMORTIZATION SCHEDULE
APPENDIX D - FORECAST AMORTIZATION SCHEDULE FOR STRANDABLE ASSETS
(Thousands of Dollars)
Year Ending 12/31:
06/30/00 7/00-12/00
Seabrook Over-Market Generation Assets
Securitized - 13,171
MP-3 Over-Market Generation Assets
Securitized - 1,703
Amortized - 762
Fossil Over-Market Generation Assets(12/00) - -
Hydro Over-Market Generation Assets(12/01)
Seabrook Deferred Return - NAEC
Written-off 89,892 -
Seabrook Deferred Return - PSNH
Written-off 15,169 -
Acquisition Premiums
Written-off 161,963 -
Securitized - -
Amortized 6,178
Acquisition Premiums - F109
Written-off 96,788 -
Securitized - -
Amortized - 3,692
Unrecovered Obligation - YAEC, CY, MY - 3,538
Deferred DOE Assessment - 9
Deferred SPP Costs - 4,240
Deferred FPPAC Costs - 4,458
VY Contract Termination Payment - 392
Market Value of Wholesale Power Contracts - (417)
Reserves for NHEC Settlement - (1,008)
Deferred NOx Allowance Credits - -
Unamort. Loss on Reacq. Debt - Exist - 124
Unamort. Loss on Reacq. Debt - 6/00 - 90
Unamort. Loss on Reacq. Debt - 12/00 - -
Unamort. Loss on Reacq. Debt - 12/01 - -
Financing Costs - 6/00
Written-off 599 0
Securitized - 453
Total 364,411 37,386
Total Write-Off 364,411 -
Total Securitized - 15,327
Total Amortization - 22,059
Total 364,411 37,386
Balance of Total Stranded Assets 920,271 882,886
Securitization: 06/30/00 2000
Total Payment 35,941
Interest Payment (at 7.25%) 20,614
Principal Payment 15,327
Principal Balance EOY 575,000 559,673
(Thousands of Dollars)
Year Ending 12/31:
2001 2002
Seabrook Over-Market Generation Assets
Securitized 27,812 29,897
MP-3 Over-Market Generation Assets
Securitized 3,597 3,867
Amortized 1,524 1,524
Fossil Over-Market Generation Assets(12/00) (9,781) (9,781)
Hydro Over-Market Generation Assets(12/01) - (4,401)
Seabrook Deferred Return - NAEC
Written-off - -
Seabrook Deferred Return - PSNH
Written-off - -
Acquisition Premiums
Written-off - -
Securitized - -
Amortized 12,356 12,356
Acquisition Premiums - F109
Written-off - -
Securitized - -
Amortized 7,384 7,384
Unrecovered Obligation - YAEC, CY, MY 7,048 6,901
Deferred DOE Assessment 18 18
Deferred SPP Costs - 8,481 8,481
Deferred FPPAC Costs 8,917 8,917
VY Contract Termination Payment 783 783
Market Value of Wholesale Power Contracts (833) (833)
Reserves for NHEC Settlement (2,017) (2,017)
Deferred NOx Allowance Credits (391) (391)
Unamort. Loss on Reacq. Debt - Exist 249 249
Unamort. Loss on Reacq. Debt - 6/00 181 181
Unamort. Loss on Reacq. Debt - 12/00 953 953
Unamort. Loss on Reacq. Debt - 12/01 - 248
Financing Costs - 6/00
Written-off - -
Securitized 957 1,029
Total 67,235 65,361
Total Write-Off - -
Total Securitized 32,366 34,792
Total Amortization 34,869 30,569
Total 67,235 65,361
Balance of Total Stranded Assets 815,651 750,290
Securitization: 2001 2002
Total Payment 71,881 71,881
Interest Payment (at 7.25%) 39,515 37,089
Principal Payment 32,366 34,792
Principal Balance EOY 527,307 492,515
(Thousands of Dollars)
Year Ending 12/31:
2003 2004
Seabrook Over-Market Generation Assets
Securitized 32,138 34,547
MP-3 Over-Market Generation Assets
Securitized 4,156 4,468
Amortized 1,524 1,524
Fossil Over-Market Generation Assets(12/00) (9,781) (9,781)
Hydro Over-Market Generation Assets(12/01) (4,401) (4,401)
Seabrook Deferred Return - NAEC
Written-off - -
Seabrook Deferred Return - PSNH
Written-off - -
Acquisition Premiums
Written-off - -
Securitized - -
Amortized 12,356 12,356
Acquisition Premiums - F109
Written-off - -
Securitized - -
Amortized 7,384 7,384
Unrecovered Obligation - YAEC, CY, MY 6,718 6,700
Deferred DOE Assessment 18 18
Deferred SPP Costs - 8,481 8,481
Deferred FPPAC Costs 8,917 8,917
VY Contract Termination Payment 783 783
Market Value of Wholesale Power Contracts (833) (833)
Reserves for NHEC Settlement (2,017) (2,017)
Deferred NOx Allowance Credits (391) (391)
Unamort. Loss on Reacq. Debt - Exist 249 249
Unamort. Loss on Reacq. Debt - 6/00 181 181
Unamort. Loss on Reacq. Debt - 12/00 953 953
Unamort. Loss on Reacq. Debt - 12/01 248 248
Financing Costs - 6/00
Written-off - -
Securitized 1,106 1,189
Total 67,786 70,572
Total Write-Off - -
Total Securitized 37,400 40,204
Total Amortization 30,386 30,368
Total 67,786 70,572
Balance of Total Stranded Assets 682,504 611,932
Securitization: 2003 2004
Total Payment 71,881 71,881
Interest Payment (at 7.25%) 34,481 31,677
Principal Payment 37,400 40,204
Principal Balance EOY 455,115 414,911
(Thousands of Dollars)
Year Ending 12/31:
2005 2006
Seabrook Over-Market Generation Assets
Securitized 37,136 39,921
MP-3 Over-Market Generation Assets
Securitized 4,803 5,163
Amortized 1,524 1,524
Fossil Over-Market Generation Assets(12/00) (9,781) (9,781)
Hydro Over-Market Generation Assets(12/01) (4,401) (4,401)
Seabrook Deferred Return - NAEC
Written-off - -
Seabrook Deferred Return - PSNH
Written-off - -
Acquisition Premiums
Written-off - -
Securitized - -
Amortized 12,356 12,356
Acquisition Premiums - F109
Written-off - -
Securitized - -
Amortized 7,384 7,384
Unrecovered Obligation - YAEC, CY, MY 6,229 5,992
Deferred DOE Assessment 18 18
Deferred SPP Costs - 8,481 8,481
Deferred FPPAC Costs 8,917 8,917
VY Contract Termination Payment 783 783
Market Value of Wholesale Power Contracts (833) (833)
Reserves for NHEC Settlement (2,017) (2,017)
Deferred NOx Allowance Credits (391) (391)
Unamort. Loss on Reacq. Debt - Exist 249 249
Unamort. Loss on Reacq. Debt - 6/00 181 181
Unamort. Loss on Reacq. Debt - 12/00 953 953
Unamort. Loss on Reacq. Debt - 12/01 248 248
Financing Costs - 6/00
Written-off - -
Securitized 1,278 1,374
Total 73,114 76,117
Total Write-Off - -
Total Securitized 43,217 46,457
Total Amortization 29,897 29,660
Total 73,114 76,117
Balance of Total Stranded Assets 538,818 462,701
Securitization: 2005 2006
Total Payment 71,881 71,881
Interest Payment (at 7.25%) 28,664 25,424
Principal Payment 43,217 46,457
Principal Balance EOY 371,694 325,237
(Thousands of Dollars)
Year Ending 12/31:
2007 2008
Seabrook Over-Market Generation Assets
Securitized 42,913 46,130
MP-3 Over-Market Generation Assets
Securitized 5,550 5,966
Amortized 1,524 1,524
Fossil Over-Market Generation Assets(12/00) (9,781) (9,781)
Hydro Over-Market Generation Assets(12/01) (4,401) (4,401)
Seabrook Deferred Return - NAEC
Written-off - -
Seabrook Deferred Return - PSNH
Written-off - -
Acquisition Premiums
Written-off - -
Securitized - -
Amortized 12,356 12,356
Acquisition Premiums - F109
Written-off - -
Securitized - -
Amortized 7,384 7,384
Unrecovered Obligation - YAEC, CY, MY 4,850 2,440
Deferred DOE Assessment 18 18
Deferred SPP Costs - 8,481 8,481
Deferred FPPAC Costs 8,917 8,917
VY Contract Termination Payment 783 783
Market Value of Wholesale Power Contracts (833) (833)
Reserves for NHEC Settlement (2,017) (2,017)
Deferred NOx Allowance Credits (391) (391)
Unamort. Loss on Reacq. Debt - Exist 249 249
Unamort. Loss on Reacq. Debt - 6/00 181 181
Unamort. Loss on Reacq. Debt - 12/00 953 953
Unamort. Loss on Reacq. Debt - 12/01 248 248
Financing Costs - 6/00
Written-off - -
Securitized 1,476 1,587
Total 78,457 79,791
Total Write-Off - -
Total Securitized 49,939 53,683
Total Amortization 28,518 26,108
Total 78,457 79,791
Balance of Total Stranded Assets 384,244 304,453
Securitization: 2007 2008
Total Payment 71,881 71,881
Interest Payment (at 7.25%) 21,942 18,198
Principal Payment 49,939 53,683
Principal Balance EOY 275,298 221,615
(Thousands of Dollars)
Year Ending 12/31:
2009 2010
Seabrook Over-Market Generation Assets
Securitized 49,588 53,304
MP-3 Over-Market Generation Assets
Securitized 6,413 6,894
Amortized 1,524 1,524
Fossil Over-Market Generation Assets(12/00) (9,781) (9,781)
Hydro Over-Market Generation Assets(12/01) (4,401) (4,401)
Seabrook Deferred Return - NAEC
Written-off - -
Seabrook Deferred Return - PSNH
Written-off - -
Acquisition Premiums
Written-off - -
Securitized - -
Amortized 12,356 12,356
Acquisition Premiums - F109
Written-off - -
Securitized - -
Amortized 7,384 7,384
Unrecovered Obligation - YAEC, CY, MY - -
Deferred DOE Assessment 18 18
Deferred SPP Costs - 8,481 8,481
Deferred FPPAC Costs 8,917 8,917
VY Contract Termination Payment 783 783
Market Value of Wholesale Power Contracts (833) (833)
Reserves for NHEC Settlement (2,017) (2,017)
Deferred NOx Allowance Credits (391) (391)
Unamort. Loss on Reacq. Debt - Exist 249 249
Unamort. Loss on Reacq. Debt - 6/00 181 181
Unamort. Loss on Reacq. Debt - 12/00 953 953
Unamort. Loss on Reacq. Debt - 12/01 248 248
Financing Costs - 6/00
Written-off - -
Securitized 1,706 1,834
Total 81,375 85,700
Total Write-Off - -
Total Securitized 57,707 62,032
Total Amortization 23,668 23,668
Total 81,375 85,700
Balance of Total Stranded Assets 223,078 137,378
Securitization: 2009 2010
Total Payment 71,881 71,881
Interest Payment (at 7.25%) 14,174 9,849
Principal Payment 57,707 62,032
Principal Balance EOY 163,908 101,876
(Thousands of Dollars)
Year Ending 12/31:
2011 2012
Seabrook Over-Market Generation Assets
Securitized 57,300 30,242
MP-3 Over-Market Generation Assets
Securitized 7,411 3,911
Amortized 1,524 762
Fossil Over-Market Generation Assets(12/00) (9,781) (4,891)
Hydro Over-Market Generation Assets(12/01) (4,401) (2,200)
Seabrook Deferred Return - NAEC
Written-off -
Seabrook Deferred Return - PSNH
Written-off -
Acquisition Premiums
Written-off -
Securitized - -
Amortized 12,356 6,178
Acquisition Premiums - F109
Written-off -
Securitized - -
Amortized 7,384 3,692
Unrecovered Obligation - YAEC, CY, MY - -
Deferred DOE Assessment 18 18
Deferred SPP Costs - 8,481 4,240
Deferred FPPAC Costs 8,917 4,458
VY Contract Termination Payment 783 392
Market Value of Wholesale Power Contracts (833) (417)
Reserves for NHEC Settlement (2,017) (1,008)
Deferred NOx Allowance Credits (391) (196)
Unamort. Loss on Reacq. Debt - Exist 249 124
Unamort. Loss on Reacq. Debt - 6/00 181 90
Unamort. Loss on Reacq. Debt - 12/00 953 476
Unamort. Loss on Reacq. Debt - 12/01 248 124
Financing Costs - 6/00
Written-off - -
Securitized 1,971 1,041
Total 90,350 47,028
Total Write-Off - -
Total Securitized 66,682 35,194
Total Amortization 23,668 11,834
Total 90,350 47,028
Balance of Total Stranded Assets 47,028
Securitization: 2011 2012
Total Payment 71,881 35,941
Interest Payment (at 7.25%) 5,199 747
Principal Payment 66,682 35,194
Principal Balance EOY 35,194 -
(Thousands of Dollars)
Year Ending 12/31:
2013 Total
Seabrook Over-Market Generation Assets
Securitized - 494,099
MP-3 Over-Market Generation Assets
Securitized - 63,901
Amortized 18,285
Fossil Over-Market Generation Assets(12/00) - (112,487)
Hydro Over-Market Generation Assets(12/01) (46,209)
Seabrook Deferred Return - NAEC -
Written-off 89,892
Seabrook Deferred Return - PSNH -
Written-off 15,169
Acquisition Premiums -
Written-off 161,963
Securitized - -
Amortized 148,269
Acquisition Premiums - F109
Written-off 96,788
Securitized - -
Amortized 88,603
Unrecovered Obligation - YAEC, CY, MY 50,416
Deferred DOE Assessment 215
Deferred SPP Costs - 101,771
Deferred FPPAC Costs - 107,000
VY Contract Termination Payment - 9,400
Market Value of Wholesale Power Contracts - (10,000)
Reserves for NHEC Settlement (24,200)
Deferred NOx Allowance Credits (4,500)
Unamort. Loss on Reacq. Debt - Exist - 2,982
Unamort. Loss on Reacq. Debt - 6/00 - 2,167
Unamort. Loss on Reacq. Debt - 12/00 10,955
Unamort. Loss on Reacq. Debt - 12/01 2,604
Financing Costs - 6/00
Written-off 599
Securitized - 17,000
Total - 1,284,682
Total Write-Off - 364,411
Total Securitized - 575,000
Total Amortization - 345,271
Total - 1,284,682
APPENDIX E - TRANSITION SERVICE / DEFAULT SERVICE PROTOCOL
Transition Service and Default Service shall be procured in accordance with
the provisions of RSA Chapter 369-B.
APPENDIX F - FOSSIL/HYDRO ASSET AUCTION
ILLUSTRATIVE TIMELINE AND SEQUENCE OF EVENTS FOR FOSSIL/HYDRO ASSET AUCTION:
Week
Beginning Action
4-Jan-00 Receive PUC approval of Agreement
10 Revise Descriptive Memorandum (DM) to conform to PUC
approval
17
24 Finalize revisions to DM
3-Feb-00 PUC Appeal Period concludes
7-Feb-00
14 Launch Auction with press release, invitations to
bid - Round 1 begins
21
28 Distribution of DM's complete
6-Mar-00 Schedule Data Room visits (if needed), respond to
bidder questions
13 Schedule Data Room visits (if needed), respond to
bidder questions
20 Schedule Data Room visits (if needed), respond to
bidder questions
27 Respond to Bidder Questions
3-Apr-00 Indicative bids due
10 Evaluate bids and select Round 2 participants
17 Round 2 Bidders notified and scheduled
24 Site visits and management presentations
1-May-00 Site visits and management presentations
8 Site visits and management presentations
15 Site visits and management presentations
22 Site visits and management presentations
29 Site visits and management presentations
5-Jun-00 Site visits and management presentations
12
19
26 Final bids due
3-Jul-00 Bids reviewed and winners selected
10 Asset Purchase Negotiations conducted
17 Winners announced
24
31 Start state and federal regulatory approval process
Prior to 12/31/2000 Complete Financial Closing on all transactions
PSNH reserves the right after consultation with the Commission, to alter or
modify this schedule as necessary, before or during the auction process to
best satisfy the goals of the auction.
APPENDIX G - DESCRIPTION OF PSNH FOSSIL/HYDRO ASSETS TO BE DIVESTED VIA
AUCTION
1. Thermal Facilities:
a. Merrimack Station
Merrimack Station is located south of the Garvins Falls Hydroelectric
Project, along the Merrimack River in Bow, New Hampshire.
Merrimack Station Generating Facilities:
Unit Load role Fuel Seasonal claimed Year
capability (winter) (MW) installed
Unit 1 Base load Coal 122.3 1960
Unit 2 Base load Coal 353.5 1968
CT-1 Peaking Jet 21.1 1968
CT-2 Peaking Jet 21.1 1969
Total 518.0
Merrimack Station is PSNH's prime base load facility with combined generating
capacity from the two coal-fired steam units and two jet fuel-fired
Combustion Turbine units of 518.0 MW. The two coal-fired units are operated
by personnel onsite 24 hours a day, seven days a week. While the units
operate in the base load role most of the time, they can be reduced in load
during off-peak hours. With this capability, these units can provide
capacity, energy and reserve products transacted at the ISO New England power
markets.
The two combustion turbine units mainly serve a peaking role, operating
during periods of highest seasonal peak demand or when generation is needed
quickly to maintain electrical system stability. These units typically serve
the capacity and reserve markets, and not the energy market. In addition to
these units, the Merrimack site includes numerous outbuildings, including the
Coal Unloading System and Coal Crusher House, office and storage facilities,
as well as a fly ash disposal area.
b. Newington Station
Newington Station is located on a site of more that 50 acres Thermal
Facility, along the banks of the Piscataqua River in Newington, New
Hampshire. The Newington and the Schiller Station are within a quarter mile
of each other, separated by a public road that ends at the Schiller plant.
The marine terminal and the bulk fuel oil storage, and oil transfer lines for
Newington Station are located on the Schiller site.
Newington Station Generating Facilities
Unit Load role Fuel Seasonal claimed Year
capability (winter) (MW) installed
Unit 1 Intermediate Oil and gas 415.0 1974
Newington Station is PSNH's prime intermediate load facility, operating as
required by the ISO to meet base, intermediate or peaking demand
requirements. It is the largest single unit in the fossil/hydro system with
capability of 415.0 maximum net MW.
Newington Station can burn a variety of fossil fuels including oil and
natural gas making it adaptable to changing fuel markets.
c. Schiller Station
The Schiller Station Thermal Plant is located east of the Newington Thermal
Facility, on the southerly shore of the Piscataqua River in Portsmouth, New
Hampshire. All of the #6 oil and coal for Schiller Station, all of the #6
oil for Newington Station, and ocean transported coal for Merrimack Station
is received by ship or barge at the main dock at Schiller Station.
Schiller Station Generating Facilities
Unit Load role Fuel Seasonal claimed Year
capability (winter) (MW) installed
Unit 4 Base/intermediate Coal or oil 48.0 1952
Unit 5 Base/intermediate Coal or oil 49.6 1955
Unit 6 Base/intermediate Coal or oil 49.0 1957
CT-1 Peaking Jet or gas 18.0 1970
Total 164.6
Schiller's steam units have historically served a base load or intermediate
load role for NEPOOL. The units have the capability of starting up and
shutting down daily if needed, but as experienced in 1997, can also
effectively serve in the base load role. Schiller's low cost of fuel and
deep water docks make it an attractive site for generation.
Completed in 1949, Schiller Station is PSNH's third largest generating plant.
The four generating units combine for a total output of 164.6 net MW. Units 4
and 5 were originally designed to burn coal, and did so for the first six
months of their operation. Both were then converted to burn oil as the
primary fuel. Unit 6 was designed to burn oil originally.
In 1984, Units 4,5 and 6 were converted to coal. Now all three units can
burn coal and/or oil as boiler fuel, making them adaptable to changing fuel
markets. In addition to the steam units, Schiller also has a separate
combustion turbine (CT-1) capable of producing 18 net MW. CT-1 is a jet
engine capable of burning either A V Jet Kero II or natural gas.
2. Hydro Facilities:
a. Smith Station
Smith Station is located on the Androscoggin River in Berlin, Coos County,
New Hampshire near the confluence of the Dead River and the Androscoggin
River. The Station operates one unit with a rated capacity of 14.2 MW.
Smith Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (MW) installed
Smith Run-of-river 14.2 1 1948
The project operates in a run-of-river mode. High capacity factors are
achieved at Smith Station due to large upstream reservoirs which maintain
consistent water flows to the station throughout the year. Pond level is
maintained within a narrow band by using a float control mechanism to control
generator output.
b. Gorham Station
Gorham Station is located on the Androscoggin River in the Town of Gorham,
Coos County, New Hampshire, near the confluence of the Peabody River and the
Androscoggin River. The unmanned Station operates four units with an
aggregate rated capacity of 2.1 MW.
Gorham Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (MW) installed
Gorham Run-of-river 2.1 4 1923
This run-of-river plant operates automatically as a base load station
generating power from any combination of its units to match river flows.
Gorham benefits from the same reservoir system that supplies water to the
upstream Smith Station. Gorham Station consists of a dam and adjacent canal
gatehouse, a power canal and a four-unit powerhouse. Limited ponding
capability exists. Gorham Station employs an automatic pond level control
system to maximize generator output and maintain pond level within a narrow
band.
c. Androscoggin Reservoir Company (ARCO)
Smith and Gorham Stations on the Androscoggin River receive headwater
benefits from the Union Water Power Company (UWPCO) and ARCO. PSNH is a 12.5
percent owner in ARCO and PSNH's ownership share in ARCO will be transferred
to the Buyer with the purchase of the Upper Hydro Group Hydroelectric
Facilities. PSNH has no ownership share in UWPCO, which has been transferred
in ownership to FPL Group as a result of FPL's purchase of assets from
Central Maine Power.
ARCO was created in order to develop an additional storage reservoir for the
Androscoggin Reservoir system, the Aziscohos Lake in Maine. UWPCO serves as
operator for ARCO as well as the Union Water Power storage sites, managing
river flows to maximize utilization of the water for electrical generation
downstream.
Through this managed operation of headwater, PSNH facilities at Smith and
Gorham are targeted to receive a minimum flow of 1,550 cfs throughout the
year, except in rare circumstances during exceptionally dry weather.
d. Canaan Station
Canaan Station is located on the northern Connecticut River in the towns of
Canaan, Vermont and Stewartstown , (West Stewartstown Village) New Hampshire.
It is located 10 miles below the large Murphy Dam at Lake Francis and 82
miles above Moore Dam, at river mile 370. The plant was built in 1927 and
operates one unit with a rated capacity of 1.1 MW.
Canaan Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (MW) installed
Canaan Run-of-river 1.1 1 1927
The unmanned Station is operated as a run-of-river plant and is operated
automatically as a base load unit. The original unit is still in service.
Pond level is maintained within a narrow band by using a float control
mechanism to control generation.
e. Ayers Island Station
Ayers Island Station is located on the Pemigewasset River approximately 12
miles upstream from the U.S. Army Corps of Engineers' Franklin Falls Flood
Control Dam in the Towns of Bristol, Bridgewater, Ashland and New Hampton,
New Hampshire. Small land rights associated with the station are in the
towns of Ashland and Bridgewater. The station operates three units with an
aggregate rated capacity of 9.08 MW. The plant was originally constructed in
1924 and redeveloped in 1931.
Ayers Island Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Ayers Island Run-of-river 9.1 3 1931
Ayers Island Station operates as a run-of-river facility with a daily ponding
capability. Pond level is maintained within a narrow band by using a float
control mechanism to control generator output, automatically.
f. Eastman Falls Station
Eastman Falls Station is on the Pemigewasett River in Franklin, New
Hampshire. The station operates two units with an aggregate rated capacity
of 6.5 MW. The project was originally constructed in 1901 and redeveloped in
1937 and 1983.
Eastman Falls Stations Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Eastman Falls Run-of-river 6.5 2 1983
Eastman Falls Station is operated as an unmanned run-of-the-river plant in
times of higher water flow and as a daily peaking facility at other times
taking advantage of upstream storage capability at Ayers Island. Pond level
is maintained within a narrow band by using a float control mechanism to
control generator output.
g. Amoskeag Station
Amoskeag Station is the southernmost of the three sites comprising the
Merrimack River Project. The station is located on the Merrimack River in
Manchester, New Hampshire, downstream from Hooksett Station. Amoskeag
operates three units with an aggregate rated capacity of 17.5 MW.
Amoskeag Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Amoskeag Run-of-river 17.5 3 1924
Amoskeag Station is operated as a run-of-the river plant in times of higher
water flow and as a daily peaking facility at other times. Pond level is
maintained automatically within a narrow band by using a float control
mechanism to control generator output.
h. Hooksett Station
Hooksett Station is located on the east side of the Merrimack River in
Hooksett, New Hampshire, downstream from the Garvins Falls Station and
Merrimack Station, and upstream from Amoskeag Station. The Station operates
one unit with a rated capacity of 1.9 MW.
Hooksett Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Hooksett Run-of-river 1.9 1 1927
The Hooksett Station is an automated site and is operated as a run-of the-
river facility. In addition to providing power to the NEPOOL transmission
grid, Hooksett provides a reservoir from which water is taken for condenser
cooling at Merrimack Station located a few miles upstream.
i. Garvins Falls Station
Garvins Falls is located on the Merrimack River in Bow, New Hampshire. The
Station operates four units with an aggregate rated capacity of 12.1 MW.
Garvins Falls Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Garvins Falls Run-of-river 12.1 4 1981
The discharge capability of the headgate structure is sufficient to operate
all four units at full load. For high flows, the units are operated so as to
utilize as much of the available water as possible. During times of moderate
and low flows, operation is scheduled to obtain the maximum on-peak energy
based on available head and relative overall unit efficiency. The newly
installed Units 1 and 2 are operated for as long as possible to take
advantage of their greater efficiency, while Units 3 and 4 are operated at
times of higher flow.
j. Jackman Station
Jackman Station consists of a dam, located on Franklin Pierce Lake, and a
penstock, surge tank and powerhouse, located in Hillsborough, New Hampshire.
The lake and project are fed from the North Branch of the Contoocook River.
This project is not subject to FERC jurisdiction because it is not classified
as a navigable waterway. The Station was constructed in 1926 and operates
one turbine with a rated capacity of 3.6 MW.
Jackman Station Generating Facilities
Station Load role Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Jackman Run-of-river 3.6 1 1926
Jackman Station is operated in an essentially run-of-river mode,
automatically by a float or pond level control mechanism at the dam. The
Station operates as a base load unit whenever adequate water flows are
available.
3. Remote Combustion Turbines:
Lost Nation Combustion Turbine
The Lost Nation Combustion Turbine is located in the town of Northumberland,
in northern New Hampshire. Lost Nation serves primarily as a peaking unit,
operating during the periods of highest seasonal peak demand. Additionally
this unit is called upon when a quick response is needed for additional
generation to maintain electrical system stability. While capable of
providing several NEPOOL products, the unit typically serves the capacity and
reserve markets, but not the energy market.
Lost Nation CT Generating Facilities
Station Load role Fuel Seasonal claimed Units Year last unit
capability (winter)(MW) installed
Lost Nation Peaking Oil 19.1 1 1969
APPENDIX H - New Hampshire Affiliate Transaction Rules Applicable to PSNH and
NU
Introduction:
Northeast Utilities ("NU") is a registered holding company system which
provides centralized services to its affiliated companies. NU believes that
these integrated, centralized services increase efficiency through economies
of scale which translate to lower prices to all customers and are
particularly significant for NU because of the relative size of the NU
system.
The Commission has not yet undertaken a rulemaking to establish final rules
regarding affiliate separation and codes of conduct for New Hampshire utility
companies. However, the Commission indicated in Order No. 22,875 in Docket
No. DR 96-150, that utilities should operate in the interim period prior to
adoption of final rules in accordance with the California Affiliate
Transaction Rules. The California Affiliate Transaction Rules are attached as
Appendix I hereto. Based upon an analysis of these rules and the
interpretation provided below, the Parties, as an element of the settlement
of which this document is a part, agree that NU will comply with the
California rules in this interim period. The Parties agree to the
interpretation provided below as an integral element of this Settlement
Agreement.
Specific Provisions:
PSNH and NU's unregulated competitive marketing affiliates agree to abide by
the following provisions regarding separation of activities and services in
accordance with the California Affiliate Transaction Rules.
1. NU will maintain distinct corporations with separate books and records,
for its distribution operations and its competitive marketing activities.
PSNH shall not share employees, facilities, space or services with NU's
unregulated competitive marketing affiliates, except as allowed herein. PSNH
will not provide services to NU's unregulated competitive marketing
affiliates unless it also provides the same on a comparable basis to all
competitors pursuant to a tariff on file with the Commission.
2. NU will continue to maintain its management services company, Northeast
Utilities Service Company ("NUSCO") providing shared services to its various
affiliates as they require and in accordance with the regulations of the
Securities and Exchange Commission ("SEC") pursuant to the Public Utility
Holding Company Act of 1935. SEC regulations require NUSCO to charge
affiliates for services at cost in accordance with SEC approved allocation
procedures. Resulting costs charged to the distribution companies by NUSCO
will continue to be subject to review and verification by the Commission in
accordance with its authority over regulated retail utility rates and
operations.
3. NUSCO will continue to provide corporate services on a shared basis in
the areas of accounting, billing, financial, administrative, regulatory,
legal, information technology, communication and executive services.
4. NU's unregulated competitive marketing affiliates will hire its own
employees to conduct competitive sales and marketing, including customer
service, and will not utilize employees of NUSCO for such activities.
5. NU's unregulated competitive marketing affiliates staff may utilize
shared corporate facilities of NUSCO along with other NUSCO personnel, but
will be physically separated from PSNH and NUSCO staff engaged in customer
service, customer account management and similar functions for PSNH. (For
purposes of these provisions, physically separate shall be defined as being
located on a separate floor of NU's facilities.)
6. NU's unregulated competitive marketing affiliates staff may use the same
computer and telephone networks as other NUSCO and distribution company
staff; but will not have access to the proprietary customer information of
NU's distribution companies, such as customer databases or other
competitively sensitive information, unless such information has been made
available previously to nonaffiliated suppliers. Password protection for
sensitive information will be maintained to ensure confidentiality.
7. Power procurement functions for the distribution company are limited to
the selection of suppliers and administration of Transition and Default
Service in accordance with the provisions of the Settlement Agreement and the
requirements of the Commission. In addition, NU has in place a code of
conduct approved by the Federal Energy Regulatory Commission ("FERC")
governing the restrictions on sharing of information between affiliates
involved in wholesale power transactions. This FERC-approved code of conduct,
and the filing of open access wholesale transmission tariffs, were
prerequisites to FERC's approval of tariffs for market-based wholesale rates
filed by the NU companies.
8. NUSCO will ensure that its provision of services in accordance with the
above provisions does not allow for any preferences to be given to NU's
unregulated competitive marketing affiliates or to allow other activities
proscribed under the rules to occur.
9. NU will conduct formal training for all employees relative to the need
for internal barriers to information sharing in advance of Competition Day.
10. None of NU's unregulated competitive marketing affiliates will use the
name "Public Service of New Hampshire" or any similar name, nor may such
affiliates otherwise trade on the name or status of PSNH in marketing
efforts.
11. The books and accounts of NU's unregulated competitive marketing
affiliates which conduct business in the New Hampshire competitive electric
market will be open to inspection by the Commission. The NU affiliate
providing such books and accounts may seek to have them declared "Trade
Secrets" pursuant to RSA Chapter 350B and "confidential, commercial, or
financial information" pursuant to RSA Chapter 91A, and thus be accorded
confidential treatment by the Commission and exempted from disclosure
pursuant to these laws and Rule Puc 204.04(a)(4). The decision to provide
confidential treatment will be subject to the ongoing jurisdiction of the
PUC.
APPENDIX I - THE CALIFORNIA AFFILIATE TRANSACTION RULES
California Affiliate Transaction Rules
I. Definitions
Unless the context otherwise requires, the following definitions govern the
construction of these Rules:
A. "Affiliate" means any person, corporation, utility, partnership, or
other entity 5 per cent or more of whose outstanding securities are owned,
controlled, or held with power to vote, directly or indirectly either by a
utility or any of its subsidiaries, or by that utility's controlling
corporation and/or any of its subsidiaries as well as any company in which
the utility, its controlling corporation, or any of the utility's affiliates
exert substantial control over the operation of the company and/or indirectly
have substantial financial interests in the company exercised through means
other than ownership. For purposes of these Rules, "substantial control"
includes, but is not limited to, the possession, directly or indirectly and
whether acting alone or in conjunction with others, of the authority to
direct or cause the direction of the management or policies of a company. A
direct or indirect voting interest of 5% or more by the utility in an
entity's company creates a rebuttable presumption of control.
For purposes of this Rule, "affiliate" shall include the utility's parent or
holding company, or any company which directly or indirectly owns, controls,
or holds the power to vote 10% or more of the outstanding voting securities
of a utility (holding company), to the extent the holding company is engaged
in the provision of products or services as set out in Rule II B. However,
in its compliance plan filed pursuant to Rule VI, the utility shall
demonstrate both the specific mechanism and procedures that the utility and
holding company have in place to assure that the utility is not utilizing the
holding company or any of its affiliates not covered by these Rules as a
conduit to circumvent any of these Rules. Examples include but are not
limited to specific mechanisms and procedures to assure the Commission that
the utility will not use the holding company or another utility affiliate not
covered by these Rules as a vehicle to (1) disseminate information
transferred to them by the utility to an affiliate covered by these Rules in
contravention of these Rules, (2) provide services to its affiliates covered
by these Rules in contravention of these Rules or (3) to transfer employees
to its affiliates covered by these Rules in contravention of these Rules. In
the compliance plan, a corporate officer from the utility and holding company
shall verify the adequacy of these specific mechanisms and procedures to
ensure that the utility is not utilizing the holding company or any of its
affiliates not covered by these Rules as a conduit to circumvent any of these
Rules.
Regulated subsidiaries of a utility, defined as subsidiaries of a utility,
the revenues and expenses of which are subject to regulation by the
Commission and are included by the Commission in establishing rates for the
utility, are not included within the definition of affiliate. However, these
Rules apply to all interactions any regulated subsidiary has with other
affiliated entities covered by these rules.
B. "Commission" means the California Public Utilities Commission or
its succeeding state regulatory body.
C. "Customer" means any person or corporation, as defined in Sections
204, 205 and 206 of the California Public Utilities Code, that is the
ultimate consumer of goods and services.
D. "Customer Information" means non-public information and data
specific to a utility customer which the utility acquired or developed in the
course of its provision of utility services.
E. "FERC" means the Federal Energy Regulatory Commission.
F. "Fully Loaded Cost" means the direct cost of good or service plus
all applicable indirect charges and overheads.
G. "Utility" means any public utility subject to the jurisdiction of
the Commission as an Electrical Corporation or Gas Corporation, as defined in
California Public Utilities Code Sections 218 and 222.
II. Applicability
A. These Rules shall apply to California public utility gas
corporations and California public utility electrical corporations, subject
to regulation by the California Public Utilities Commission.
B. For purposes of a combined gas and electric utility, these Rules
apply to all utility transactions with affiliates engaging in the provision
of a product that uses gas or electricity or the provision of services that
relate to the use of gas or electricity, unless specifically exempted below.
For purposes of an electric utility, these Rules apply to all utility
transactions with affiliates engaging in the provision of a product that uses
electricity or the provision of services that relate to the use of
electricity. For purposes of a gas utility, these Rules apply to all utility
transactions with affiliates engaging in the provision of a product that uses
gas or the provision of services that relate to the use of gas.
C. These Rules apply to transactions between a Commission-regulated
utility and another affiliated utility, unless specifically modified by the
Commission in addressing a separate application to merge or otherwise conduct
joint ventures related to regulated services.
D. These rules do not apply to the exchange of operating information,
including the disclosure of customer information to its FERC-regulated
affiliate to the extent such information is required by the affiliate to
schedule and confirm nominations for the interstate transportation of natural
gas, between a utility and its FERC-regulated affiliate, to the extent that
the affiliate operates an interstate natural gas pipeline.
E. Existing Rules: Existing Commission rules for each utility and its
parent holding company shall continue to apply except to the extent they
conflict with these Rules. In such cases, these Rules shall supersede prior
rules and guidelines, provided that nothing herein shall preclude (1) the
Commission from adopting other utility-specific guidelines; or (2) a utility
or its parent holding company from adopting other utility-specific
guidelines, with advance Commission approval.
F. Civil Relief: These Rules shall not preclude or stay any form of
civil relief, or rights or defenses thereto, that may be available under
state or federal law.
G. Exemption (Advice Letter): A Commission-jurisdictional utility may
be exempted from these Rules if it files an advice letter with the Commission
requesting exemption. The utility shall file the advice letter within 30
days after the effective date of this decision adopting these Rules and shall
serve it on all parties to this proceeding. In the advice letter filing, the
utility shall:
1. Attest that no affiliate of the utility provides services as
defined by Rule II B above; and
2. Attest that if an affiliate is subsequently created which
provides services as defined by Rule II B above, then the utility shall:
a. Notify the Commission, at least 30 days before the
affiliate begins to provide services as defined by Rule II B above, that such
an affiliate has been created; notification shall be accomplished by means of
a letter to the Executive Director, served on all parties to this proceeding;
and
b. Agree in this notice to comply with the Rules in their
entirety.
H. Limited Exemption (Application): A California utility which is
also a multi-state utility and subject to the jurisdiction of other state
regulatory commissions, may file an application, served on all parties to
this proceeding, requesting a limited exemption from these Rules or a part
thereof, for transactions between the utility solely in its capacity serving
its jurisdictional areas wholly outside of California, and its affiliates.
The applicant has the burden of proof.
A. These Rules should be interpreted broadly, to effectuate our stated
objectives of fostering competition and protecting consumer interests. If
any provision of these Rules, or the application thereof to any person,
company, or circumstance, is held invalid, the remainder of the Rules, or the
application of such provision to other persons, companies, or circumstances,
shall not be affected thereby.
III. Nondiscrimination
A. No Preferential Treatment Regarding Services Provided by the
Utility: Unless otherwise authorized by the Commission or the FERC, or
permitted by these Rules, a utility shall not:
1. represent that, as a result of the affiliation with the
utility, its affiliates or customers of its affiliates will receive any
different treatment by the utility than the treatment the utility provides to
other, unaffiliated companies or their customers; or
2. provide its affiliates, or customers of its affiliates, any
preference (including but not limited to terms and conditions, pricing, or
timing) over non-affiliated suppliers or their customers in the provision of
services provided by the utility.
B. Affiliate Transactions: Transactions between a utility and its
affiliates shall be limited to tariffed products and services, the sale or
purchase of goods, property, products or services made generally available by
the utility or affiliate to all market participants through an open,
competitive bidding process, or as provided for in Sections V D and V E
(joint purchases and corporate support) and Section VII (new products and
services) below, provided the transactions provided for in Section VII comply
with all of the other adopted Rules.
C. Provision of Supply, Capacity, Services or Information: Except as
provided for in Sections V D, V E, and VII, provided the transactions
provided for in Section VII comply with all of the other adopted Rules, a
utility shall provide access to utility information, services, and unused
capacity or supply on the same terms for all similarly situated market
participants. If a utility provides supply, capacity, services, or
information to its affiliate(s), it shall contemporaneously make the offering
available to all similarly situated market participants, which include all
competitors serving the same market as the utility's affiliates.
1. Offering of Discounts: Except when made generally available
by the utility through an open, competitive bidding process, if a utility
offers a discount or waives all or any part of any other charge or fee to its
affiliates, or offers a discount or waiver for a transaction in which its
affiliates are involved, the utility shall contemporaneously make such
discount or waiver available to all similarly situated market participants.
The utilities should not use the "similarly situated" qualification to create
such a unique discount arrangement with their affiliates such that no
competitor could be considered similarly situated. All competitors serving
the same market as the utility's affiliates should be offered the same
discount as the discount received by the affiliates. A utility shall
document the cost differential underlying the discount to its affiliates in
the affiliate discount report described in Rule III F 7 below.
2. Tariff Discretion: If a tariff provision allows for
discretion in its application, a utility shall apply that tariff provision in
the same manner to its affiliates and other market participants and their
respective customers.
3. No Tariff Discretion: If a utility has no discretion in the
application of a tariff provision, the utility shall strictly enforce that
tariff provision.
4. Processing Requests for Services Provided by the Utility: A
utility shall process requests for similar services provided by the utility
in the same manner and within the same time for its affiliates and for all
other market participants and their respective customers.
C. Tying of Services Provided by a Utility Prohibited: A utility
shall not condition or otherwise tie the provision of any services provided
by the utility, nor the availability of discounts of rates or other charges
or fees, rebates, or waivers of terms and conditions of any services provided
by the utility, to the taking of any goods or services from its affiliates.
D. No Assignment of Customers: A utility shall not assign customers
to which it currently provides services to any of its affiliates, whether by
default, direct assignment, option or by any other means, unless that means
is equally available to all competitors.
E. Business Development and Customer Relations: Except as otherwise
provided by these Rules, a utility shall not:
1. provide leads to its affiliates;
2. solicit business on behalf of its affiliates;
3. acquire information on behalf of or to provide to its
affiliates;
4. share market analysis reports or any other types of
proprietary or non-publicly available reports, including but not limited to
market, forecast, planning or strategic reports, with its affiliates;
5. request authorization from its customers to pass on customer
information exclusively to its affiliates;
6. give the appearance that the utility speaks on behalf of its
affiliates or that the customer will receive preferential treatment as a
consequence of conducting business with the affiliates; or
7. give any appearance that the affiliate speaks on behalf of the
utility.
F. Affiliate Discount Reports: If a utility provides its affiliates a
discount, rebate, or other waiver of any charge or fee associated with
services provided by the utility, the utility shall, within 24 hours of the
time at which the service provided by the utility is so provided, post a
notice on its electronic bulletin board providing the following information:
1. the name of the affiliate involved in the transaction;
2. the rate charged;
3. the maximum rate;
4. the time period for which the discount or waiver applies;
5. the quantities involved in the transaction;
6. the delivery points involved in the transaction;
7. any conditions or requirements applicable to the discount or
waiver, and a documentation of the cost differential underlying the discount
as required in Rule III B 2 above; and
8. procedures by which a nonaffiliated entity may request a
comparable offer.
A utility that provides an affiliate a discounted rate, rebate, or other
waiver of a charge or fee associated with services provided by the utility
shall maintain, for each billing period, the following information:
9. the name of the entity being provided services provided by the
utility in the transaction;
10. the affiliate's role in the transaction (i.e., shipper,
marketer, supplier, seller);
11. the duration of the discount or waiver;
12. the maximum rate;
13. the rate or fee actually charged during the billing period;
and
14. the quantity of products or services scheduled at the
discounted rate during the billing period for each delivery point.
All records maintained pursuant to this provision shall also conform to FERC
rules where applicable.
IV. Disclosure and Information
A. Customer Information: A utility shall provide customer information
to its affiliates and unaffiliated entities on a strictly non-discriminatory
basis, and only with prior affirmative customer written consent.
B. Non-Customer Specific Non-Public Information: A utility shall make
non-customer specific non-public information, including but not limited to
information about a utility's natural gas or electricity purchases, sales, or
operations or about the utility's gas-related goods or services, electricity-
related goods or services, available to the utility's affiliates only if the
utility makes that information contemporaneously available to all other
service providers on the same terms and conditions, and keeps the information
open to public inspection. Unless otherwise provided by these Rules, a
utility continues to be bound by all Commission-adopted pricing and reporting
guidelines for such transactions. Utilities are also permitted to exchange
proprietary information on an exclusive basis with their affiliates, provided
the utility follows all Commission-adopted pricing and reporting guidelines
for such transactions, and it is necessary to exchange this information in
the provision of the corporate support services permitted by Rule V E below.
The affiliate's use of such proprietary information is limited to use in
conjunction with the permitted corporate support services, and is not
permitted for any other use. Nothing in this Rule precludes the exchange of
information pursuant to D.97-10-031.
C. Service Provider Information:
1. Except upon request by a customer or as otherwise authorized
by the Commission, a utility shall not provide its customers with any list of
service providers, which includes or identifies the utility's affiliates,
regardless of whether such list also includes or identifies the names of
unaffiliated entities.
2. If a customer requests information about any affiliated
service provider, the utility shall provide a list of all providers of gas-
related, electricity-related, or other utility-related goods and services
operating in its service territory, including its affiliates. The Commission
shall authorize, by semi-annual utility advice letter filing, and either the
utility, the Commission, or a Commission-authorized third party provider
shall maintain on file with the Commission a copy of the most updated lists
of service providers which have been created to disseminate to a customer
upon a customer's request. Any service provider may request that it be
included on such list, and, barring Commission direction, the utility shall
honor such request. Where maintenance of such list would be unduly
burdensome due to the number of service providers, subject to Commission
approval by advice letter filing, the utility shall direct the customer to a
generally available listing of service providers (e.g., the Yellow Pages).
In such cases, no list shall be provided. The list of service providers
should make clear that the Commission does not guarantee the financial
stability or service quality of the service providers listed by the act of
approving this list.
D. Supplier Information: A utility may provide non-public information
and data which has been received from unaffiliated suppliers to its
affiliates or non-affiliated entities only if the utility first obtains
written affirmative authorization to do so from the supplier. A utility
shall not actively solicit the release of such information exclusively to its
own affiliate in an effort to keep such information from other unaffiliated
entities.
E. Affiliate-Related Advice or Assistance: Except as otherwise
provided in these Rules, a utility shall not offer or provide customers
advice or assistance with regard to its affiliates or other service
providers.
F. Record-Keeping: A utility shall maintain contemporaneous records
documenting all tariffed and nontariffed transactions with its affiliates,
including but not limited to, all waivers of tariff or contract provisions
and all discounts. A utility shall maintain such records for a minimum of
three years and longer if this Commission or another government agency so
requires. The utility shall make such records available for third party
review upon 72 hours' notice, or at a time mutually agreeable to the utility
and third party.
If D.97-06-110 is applicable to the information the utility seeks to protect,
the utility should follow the procedure set forth in D.97-06-110, except that
the utility should serve the third party making the request in a manner that
the third party receives the utility's D.97-06-110 request for
confidentiality within 24 hours of service.
G. Maintenance of Affiliate Contracts and Related Bids: A utility
shall maintain a record of all contracts and related bids for the provision
of work, products or services to and from the utility to its affiliates for
no less than a period of three years, and longer if this Commission or
another government agency so requires.
H. FERC Reporting Requirements: To the extent that reporting rules
imposed by the FERC require more detailed information or more expeditious
reporting, nothing in these Rules shall be construed as modifying the FERC
rules.
V. Separation
A. Corporate Entities: A utility and its affiliates shall be separate
corporate entities.
B. Books and Records: A utility and its affiliates shall keep
separate books and records.
1. Utility books and records shall be kept in accordance with
applicable Uniform System of Accounts (USOA) and Generally Accepted
Accounting Procedures (GAAP).
2. The books and records of affiliates shall be open for
examination by the Commission and its staff consistent with the provisions of
Public Utilities Code Section 314.
C. Sharing of Plant, Facilities, Equipment or Costs: A utility shall
not share office space, office equipment, services, and systems with its
affiliates, nor shall a utility access the computer or information systems of
its affiliates or allow its affiliates to access its computer or information
systems, except to the extent appropriate to perform shared corporate support
functions permitted under Section V E of these Rules. Physical separation
required by this rule shall be accomplished preferably by having office space
in a separate building, or, in the alternative, through the use of separate
elevator banks and/or security-controlled access. This provision does not
preclude a utility from offering a joint service provided this service is
authorized by the Commission and is available to all non-affiliated service
providers on the same terms and conditions (e.g., joint billing services
pursuant to D.97-05-039).
D. Joint Purchases: To the extent not precluded by any other Rule,
the utilities and their affiliates may make joint purchases of good and
services, but not those associated with the traditional utility merchant
function. For purpose of these Rules, to the extent that a utility is
engaged in the marketing of the commodity of electricity or natural gas to
customers, as opposed to the marketing of transmission and distribution
services, it is engaging in merchant functions. Examples of permissible
joint purchases include joint purchases of office supplies and telephone
services. Examples of joint purchases not permitted include gas and electric
purchasing for resale, purchasing of gas transportation and storage capacity,
purchasing of electric transmission, systems operations, and marketing. The
utility must insure that all joint purchases are priced, reported, and
conducted in a manner that permits clear identification of the utility and
affiliate portions of such purchases, and in accordance with applicable
Commission allocation and reporting rules.
E. Corporate Support: As a general principle, a utility, its parent
holding company, or a separate affiliate created solely to perform corporate
support services may share with its affiliates joint corporate oversight,
governance, support systems and personnel. Any shared support shall be
priced, reported and conducted in accordance with the Separation and
Information Standards set forth herein, as well as other applicable
Commission pricing and reporting requirements.
As a general principle, such joint utilization shall not allow or
provide a means for the transfer of confidential information from the utility
to the affiliate, create the opportunity for preferential treatment or unfair
competitive advantage, lead to customer confusion, or create significant
opportunities for cross-subsidization of affiliates. In the compliance plan,
a corporate officer from the utility and holding company shall verify the
adequacy of the specific mechanisms and procedures in place to ensure the
utility follows the mandates of this paragraph, and to ensure the utility is
not utilizing joint corporate support services as a conduit to circumvent
these Rules.
Examples of services that may be shared include: payroll, taxes,
shareholder services, insurance, financial reporting, financial planning and
analysis, corporate accounting, corporate security, human resources
(compensation, benefits, employment policies), employee records, regulatory
affairs, lobbying, legal, and pension management.
Examples of services that may not be shared include: employee
recruiting, engineering, hedging and financial derivatives and arbitrage
services, gas and electric purchasing for resale, purchasing of gas
transportation and storage capacity, purchasing of electric transmission,
system operations, and marketing.
F. Corporate Identification and Advertising:
1. A utility shall not trade upon, promote, or advertise its
affiliate's affiliation with the utility, nor allow the utility name or logo
to be used by the affiliate or in any material circulated by the affiliate,
unless it discloses in plain legible or audible language, on the first page
or at the first point where the utility name or logo appears that:
a. the affiliate "is not the same company as [i.e. PG&E,
Edison, the Gas Company, etc.], the utility,";
b. the affiliate is not regulated by the California Public
Utilities Commission; and
c. "you do not have to buy [the affiliate's] products in
order to continue to receive quality regulated services from the utility."
The application of the name/logo disclaimer is limited to the
use of the name or logo in California.
2. A utility, through action or words, shall not represent that,
as a result of the affiliate's affiliation with the utility, its affiliates
will receive any different treatment than other service providers.
3. A utility shall not offer or provide to its affiliates
advertising space in utility billing envelopes or any other form of utility
customer written communication unless it provides access to all other
unaffiliated service providers on the same terms and conditions.
4. A utility shall not participate in joint advertising or joint
marketing with its affiliates. This prohibition means that utilities may not
engage in activities which include, but are not limited to the following:
a. A utility shall not participate with its affiliates in
joint sales calls, through joint call centers or otherwise, or joint
proposals (including responses to requests for proposals (RFPs)) to existing
or potential customers. At a customer's unsolicited request, a utility may
participate, on a nondiscriminatory basis, in non-sales meetings with its
affiliates or any other market participant to discuss technical or
operational subjects regarding the utility's provision of transportation
service to the customer;
b. Except as otherwise provided for by these Rules, a
utility shall not participate in any joint activity with its affiliates. The
term "joint activities" includes, but is not limited to, advertising, sales,
marketing, communications and correspondence with any existing or potential
customer;
c. A utility shall not participate with its affiliates in
trade shows, conferences, or other information or marketing events held in
California.
5. A utility shall not share or subsidize costs, fees, or
payments with its affiliates associated with research and development
activities or investment in advanced technology research.
G. Employees:
1. Except as permitted in Section V E (corporate support), a
utility and its affiliates shall not jointly employ the same employees. This
Rule prohibiting joint employees also applies to Board Directors and
corporate officers, except for the following circumstances: In instances when
this Rule is applicable to holding companies, any board member or corporate
officer may serve on the holding company and with either the utility or
affiliate (but not both). Where the utility is a multi-state utility, is not
a member of a holding company structure, and assumes the corporate governance
functions for the affiliates, the prohibition against any board member or
corporate officer of the utility also serving as a board member or corporate
officer of an affiliate shall only apply to affiliates that operate within
California. In the case of shared directors and officers, a corporate
officer from the utility and holding company shall verify in the utility's
compliance plan the adequacy of the specific mechanisms and procedures in
place to ensure that the utility is not utilizing shared officers and
directors as a conduit to circumvent any of these Rules.
2. All employee movement between a utility and its affiliates
shall be consistent with the following provisions:
a. A utility shall track and report to the Commission all
employee movement between the utility and affiliates. The utility shall
report this information annually pursuant to our Affiliate Transaction
Reporting Decision, D.93-02-016, 48 CPUC2d 163, 171-172 and 180 (Appendix A,
Section I and Section II H.).
b. Once an employee of a utility becomes an employee of an
affiliate, the employee may not return to the utility for a period of one
year. This Rule is inapplicable if the affiliate to which the employee
transfers goes out of business during the one-year period. In the event
that such an employee returns to the utility, such employee cannot be
retransferred, reassigned, or otherwise employed by the affiliate for a
period of two years. Employees transferring from the utility to the
affiliate are expressly prohibited from using information gained from the
utility in a discriminatory or exclusive fashion, to the benefit of the
affiliate or to the detriment of other unaffiliated service providers.
c. When an employee of a utility is transferred, assigned,
or otherwise employed by the affiliate, the affiliate shall make a one-time
payment to the utility in an amount equivalent to 25% of the employee's base
annual compensation, unless the utility can demonstrate that some lesser
percentage (equal to at least 15%) is appropriate for the class of employee
included. All such fees paid to the utility shall be accounted for in a
separate memorandum account to track them for future ratemaking treatment
(i.e. credited to the Electric Revenue Adjustment Account or the Core and
Non-core Gas Fixed Cost Accounts, or other ratemaking treatment, as
appropriate), on an annual basis, or as otherwise necessary to ensure that
the utility's ratepayers receive the fees. This transfer payment provision
will not apply to clerical workers. Nor will it apply to the initial
transfer of employees to the utility's holding company to perform corporate
support functions or to a separate affiliate performing corporate support
functions, provided that that transfer is made during the initial
implementation period of these rules or pursuant to a Section 851
application or other Commission proceeding. However, the rule will apply to
any subsequent transfers or assignments between a utility and its affiliates
of all covered employees at a later time.
d. Any utility employee hired by an affiliate shall not
remove or otherwise provide information to the affiliate which the affiliate
would otherwise be precluded from having pursuant to these Rules.
e. A utility shall not make temporary or intermittent
assignments, or rotations to its affiliates.
H. Transfer of Goods and Services: To the extent that these Rules do
not prohibit transfers of goods and services between a utility and its
affiliates, all such transfers shall be subject to the following pricing
provisions:
1. Transfers from the utility to its affiliates of goods and
services produced, purchased or developed for sale on the open market by the
utility will be priced at fair market value. Transfers from an affiliate to
the utility of goods and services produced, purchased or developed for sale
on the open market by the affiliate shall be priced at no more than fair
market value.
2. For goods or services for which the price is regulated by a
state or federal agency, that price shall be deemed to be the fair market
value, except that in cases where more than one state commission regulates
the price of goods or services, this Commission's pricing provisions govern.
3. Goods and services produced, purchased or developed for sale
on the open market by the utility will be provided to its affiliates and
unaffiliated companies on a nondiscriminatory basis, except as otherwise
required or permitted by these Rules or applicable law.
4. Transfers from the utility to its affiliates of goods and
services not produced, purchased or developed for sale by the utility will be
priced at fully loaded cost plus 5% of direct labor cost.
5. Transfers from an affiliate to the utility of goods and
services not produced, purchased or developed for sale by the affiliate will
be priced at the lower of fully loaded cost or fair market value.
VI. Regulatory Oversight
A. Compliance Plans: No later than December 31, 1997, each utility
shall file a compliance plan demonstrating to the Commission that there are
adequate procedures in place that will preclude the sharing of information
with its affiliates that is prohibited by these Rules. The utility should
file its compliance plan as an advice letter with the Commission's Energy
Division and serve it on the parties to this proceeding. The utility's
compliance plan shall be in effect between the filing and a Commission
determination of the advice letter. A utility shall file a compliance plan
annually thereafter by advice letter served on all parties to this proceeding
where there is some change in the compliance plan (i.e., when a new affiliate
has been created, or the utility has changed the compliance plan for any
other reason).
B. New Affiliate Compliance Plans: Upon the creation of a new
affiliate which is addressed by these Rules, the utility shall immediately
notify the Commission of the creation of the new affiliate, as well as
posting notice on its electronic bulletin board. No later than 60 days after
the creation of this affiliate, the utility shall file an advice letter with
the Energy Division of the Commission, served on the parties to this
proceeding. The advice letter shall demonstrate how the utility will
implement these Rules with respect to the new affiliate.
C. Affiliate Audit: No later than December 31, 1998, and every year
thereafter, the utility shall have audits prepared by independent auditors
that verify that the utility is in compliance with the Rules set forth
herein. The utilities shall file this audit with the Commission's Energy
Division beginning no later than December 31, 1998, and serve it on all
parties to this proceeding. The audits shall be at shareholder expense.
D. Witness Availability: Affiliate officers and employees shall be
made available to testify before the Commission as necessary or required,
without subpoena, consistent with the provisions of Public Utilities Code
Section 314.
VII. Utility Products and Services
A. General Rule: Except as provided for in these Rules, new products
and services shall be offered through affiliates.
B. Definitions: The following definitions apply for the purposes of
this section (Section VII) of these Rules:
1. "Category" refers to a factually similar group of products and
services that use the same type of utility assets or capacity. For example,
"leases of land under utility transmission lines" or "use of a utility repair
shop for third party equipment repair" would each constitute a separate
product or service category.
2. "Existing" products and services are those which a utility is
offering on the effective date of these Rules.
3. "Products" include use of property, both real and
intellectual, other than those uses authorized under General Order 69-C.
1. "Tariff" or "tariffed" refers to rates, terms and conditions
of services as approved by this Commission or the Federal Energy Regulatory
Commission (FERC), whether by traditional tariff, approved contract or other
such approval process as the Commission or the FERC may deem appropriate.
C. Utility Products and Services: Except as provided in these Rules,
a utility shall not offer nontariffed products and services. In no event
shall a utility offer natural gas or electricity commodity service on a
nontariffed basis. A utility may only offer for sale the following products
and services:
1. Existing products and services offered by the utility pursuant
to tariff;
2. Unbundled versions of existing utility products and services,
with the unbundled versions being offered on a tariffed basis;
3. New products and services that are offered on a tariffed
basis; and
4. Products and services which are offered on a nontariffed basis
and which meet the following conditions:
a. The nontariffed product or service utilizes a portion of
a utility asset or capacity;
b. such asset or capacity has been acquired for the purpose
of and is necessary and useful in providing tariffed utility services;
c. the involved portion of such asset or capacity may be
used to offer the product or service on a nontariffed basis without adversely
affecting the cost, quality or reliability of tariffed utility products and
services;
d. the products and services can be marketed with minimal or
no incremental capital, minimal or no new forms of liability or business risk
being incurred by the utility, and minimal or no direct management control;
and
c. the utility offering is restricted to less than 1% of the
number of customers in its customer base.
D. Conditions Precedent to Offering New Products and Services: This
Rule does not represent an endorsement by the Commission of any particular
nontariffed utility product or service. A utility may offer new nontariffed
products and services only if the Commission has adopted and the utility has
established:
1. A mechanism or accounting standard for allocating costs to
each new product or service to prevent cross-subsidization between services a
utility would continue to provide on a tariffed basis and those it would
provide on a nontariffed basis;
2. A reasonable mechanism for treatment of benefits and revenues
derived from offering such products and services, except that in the event
the Commission has already approved a performance-based ratemaking mechanism
for the utility and the utility seeks a different sharing mechanism, the
utility should petition to modify the performance-based ratemaking decision
if it wishes to alter the sharing mechanism, or clearly justify why this
procedure is inappropriate, rather than doing so by application or other
vehicle.
3. Periodic reporting requirements regarding pertinent
information related to nontariffed products and services; and
4. Periodic auditing of the costs allocated to and the revenues
derived from nontariffed products and services.
E. Requirement to File an Advice Letter: Prior to offering a new
category of nontariffed products or services as set forth in Section VII C
above, a utility shall file an advice letter in compliance with the following
provisions of this paragraph.
1. The advice letter shall:
a. demonstrate compliance with these rules;
b. address the amount of utility assets dedicated to the
non-utility venture, in order to ensure that a given product or service does
not threaten the provision of utility service, and show that the new product
or service will not result in a degradation of cost, quality, or reliability
of tariffed goods and services;
c. demonstrate that the utility has not received recovery in
the Transition Cost Proceeding, A.96-08-001, or other applicable Commission
proceeding, for the portion of the utility asset dedicated to the non-utility
venture; and
d. address the potential impact of the new product or
service on competition in the relevant market.
2. In the absence of a protest alleging non-compliance with these
Rules or any law, regulation, decision, or Commission policy, or allegations
of harm, the utility may commence offering the product or service 30 days
after submission of the advice letter.
3. A protest of an advice letter filed in accordance with this
paragraph shall include:
a. An explanation of the specific Rules, or any law,
regulation, decision, or Commission policy the utility will allegedly violate
by offering the proposed product or service, with reasonable factual detail;
or
b. An explanation of the specific harm the protestant will
allegedly suffer.
4. If such a protest is filed, the utility may file a motion to
dismiss the protest within 5 working days if it believes the protestant has
failed to provide the minimum grounds for protest required above. The
protestant has 5 working days to respond to the motion.
1. The intention of the Commission is to make its best reasonable
efforts to rule on such a motion to dismiss promptly. Absent a ruling
granting a motion to dismiss, the utility shall begin offering that category
of products and services only after Commission approval through the normal
advice letter process.
F. Existing Offerings: Unless and until further Commission order to
the contrary as a result of the advice letter filing or otherwise, a utility
that is offering tariffed or nontariffed products and services, as of the
effective date of this decision, may continue to offer such products and
services, provided that the utility complies with the cost allocation and
reporting requirements in this rule. No later than January 30, 1998, each
utility shall submit an advice letter describing the existing products and
services (both tariffed and nontariffed) currently being offered by the
utility and the number of the Commission decision or advice letter approving
this offering, if any, and requesting authorization or continuing
authorization for the utility's continued provision of this product or
service in compliance with the criteria set forth in Rule VII. This
requirement applies to both existing products and services explicitly
approved and not explicitly approved by the Commission.
G. Section 851 Application: A utility must continue to comply fully
with the provisions of Public Utilities Code Section 851 when necessary or
useful utility property is sold, leased, assigned, mortgaged, disposed of, or
otherwise encumbered as part of a nontariffed product or service offering by
the utility. If an application pursuant to Section 851 is submitted, the
utility need not file a separate advice letter, but shall include in the
application those items which would otherwise appear in the advice letter as
required in this Rule.
H. Periodic Reporting of Nontariffed Products and Services: Any
utility offering nontariffed products and services shall file periodic
reports with the Commission's Energy Division twice annually for the first
two years following the effective date of these Rules, then annually
thereafter unless otherwise directed by the Commission. The utility shall
serve periodic reports on the service list of this proceeding. The periodic
reports shall contain the following information:
1. A description of each existing or new category of nontariffed
products and services and the authority under which it is offered;
2. A description of the types and quantities of products and
services contained within each category (so that, for example, "leases for
agricultural nurseries at 15 sites" might be listed under the category
"leases of land under utility transmission lines," although the utility would
not be required to provide the details regarding each individual lease);
3. The costs allocated to and revenues derived from each
category; and
4. Current information on the proportion of relevant utility
assets used to offer each category of product and service.
I. Offering of Nontariffed Products and Services to Affiliates:
Nontariffed products and services which are allowed by this Rule may be
offered to utility affiliates only in compliance with all other provisions of
these Affiliate Rules. Similarly, this Rule does not prohibit affiliate
transactions which are otherwise allowed by all other provisions of these
Affiliate Rules.
