Exhibit 10.15.1
STATE OF NEW HAMPSHIRE
BEFORE THE
PUBLIC UTILITIES COMMISSION
AGREEMENT TO SETTLE PSNH RESTRUCTURING
August 2, 1999
Revised and Conformed in Compliance with
Order No. 23,549
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
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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 0.383 cents/kWh, and the FPPAC BA amount of 6.281 cents/kWh will remain
in
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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 cents per kWh for a customer taking Transition Service,
broken down as follows:
Transition Service Energy Charge 4.400 cents
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 cents
Total 10.985 cents/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
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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 and shall not be later than October 1, 2000, unless
the PUC finds due to circumstances beyond its control that further delay is in
the public interest.
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.
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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 54 1:5.
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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
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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
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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.
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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 & ▇▇▇▇▇▇ Credit
Rating Co., Fitch Investors Service, L.P., ▇▇▇▇▇'▇ 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
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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 ▇▇▇▇▇▇ ▇▇▇▇▇▇▇▇▇
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.
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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.
D. 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
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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 2.800 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
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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
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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 2.80/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 0.130/kWh in the Delivery Charge above the otherwise effective 2.80/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 and related revenues 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
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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
E. 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
Page 15
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
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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
Return 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 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, ▇▇▇▇▇ ▇▇▇▇▇▇ and Yankee ▇▇▇▇) 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.
Page 17
- 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.
Page 18
- During the Initial Delivery Charge Period, 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
Page 19
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
Page 20
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 3.400/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
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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
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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
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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
Page 24
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, power purchase obligations 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.
Page 25
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.
Page 26
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 0.20/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
Page 27
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.
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.
H. 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 or
decrease by PSNH.
2. Fuel and Purchased Power Adjustment Clause ("FPPAC")
The FPPAC rate will be frozen at the currently effective amount of
0.3830/kWh and an FPPAC BA amount of 6.281 0/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
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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 market price 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.
I. TRANSMISSION AND DISTRIBUTION ISSUES
A. Classification of transmission and distribution facilities
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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.
▇. ▇▇▇▇▇ 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
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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.
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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.
J. 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
Unless otherwise directed by the PUC, 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
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▇▇▇▇▇▇▇ 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.
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D. Approvals
The following approvals have been identified as being required prior to the
closing of any sale resulting from the fossil and hydro auctions 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.
The pre-merger notification requirements of the ▇▇▇▇-▇▇▇▇▇-▇▇▇▇▇▇ 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 ▇▇▇▇▇ 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 will be required.
3. Other
The asset sales may require prior consent of certain lenders under PSNH's
existing credit agreements. In addition, the sales 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.
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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 administration and 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 (except ratification under the provisions of RSA 38:13), 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
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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
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support payments are based on cost of service, they may fluctuate from year to
year.
▇. ▇▇▇▇▇ Unit 4
PSNH may sell its ownership interest in ▇▇▇▇▇ 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 ▇▇▇▇▇ 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 ▇▇▇▇▇▇▇ 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 as of April 19,
2000, 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
Page 37
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
Page 38
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. The PUC shall administer 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.
▇. ▇▇▇▇▇▇▇▇
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
Page 39
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
▇▇▇ 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 ▇▇▇ 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
Page 40
failed auction include the bundling of various assets as "must bid" groupings at
the commencement of the Second Round of the auction process, 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
▇. ▇▇▇▇▇▇▇ 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.
Page 41
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.
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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.
▇. ▇▇▇▇ and NAESCO Non-Represented Employees
The purchaser will be required to offer all non-represented fossil/hydro
and nuclear employees a minimum of
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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 PSNHINAESCO 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/▇▇▇▇▇▇'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
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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
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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
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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 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,
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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.
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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
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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
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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).
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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.
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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
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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
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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).
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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
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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 to the extent indicated in
Chapter 249 of the 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.
Page 57
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.
Signed this 22nd day of September, 2000
/s/ ▇▇▇▇▇▇ ▇▇▇▇▇▇▇ /s/ ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇
▇▇▇▇▇▇ ▇▇▇▇▇▇▇ ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇
Governor of the State of New Hampshire Chairman, President and Chief
State House Executive Officer
Concord, NH 03301 Northeast Utilities
▇▇▇ ▇▇▇▇▇▇ ▇▇▇▇▇▇
▇▇▇▇▇▇, ▇▇ ▇▇▇▇▇
/s/ ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇▇ /s/ ▇▇▇▇ ▇. ▇▇▇▇
▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇▇ ▇▇▇▇ ▇. ▇▇▇▇
Attorney General President and Chief
of the State of New Hampshire Operating Officer
▇▇ ▇▇▇▇▇▇▇ ▇▇▇▇▇▇ Public Service Company of New
Concord, NH 03301 Hampshire
▇▇▇▇ ▇▇▇ ▇▇▇▇▇▇
P.O. Box 330
Manchester, NH 03105
/s/ ▇▇▇▇▇▇ ▇. ▇▇▇▇
▇▇▇▇▇▇ ▇. ▇▇▇▇
Executive Director and Secretary
New Hampshire Public Utilities Commission
▇ ▇▇▇ ▇▇▇▇▇▇▇ ▇▇▇▇
▇▇▇▇▇▇▇, ▇▇ ▇▇▇▇▇
/s/ ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇
Director
Governor's Office of Energy and Community Services
▇▇ ▇▇▇▇▇▇▇▇ ▇▇▇▇▇
▇▇▇▇▇▇▇, ▇▇ ▇▇▇▇▇
Page 58
APPENDIX A - SUMMARY OF PROPOSED RATES
APPENDIX A - SUMMARY OF PROPOSED RATES
Public Service Company of New Hampshire
Current and Target Revenue by Class
Total Revenue Revenue, cents/kWh
Billed
Rate Class KWH Current Current Percentage
Sales (1) Rate (2) Target (3) Rates Target Decrease
Residential Service 2,294,071,493 $ 333,425,361 $276,917,370 $ 14.534 12.071 16.9%
General Service 1,421,780,341 182,776,854 156,452,709 12.855 11.004 14.4%
Primary General Service 1,219,154,700 133,906,224 115,563,674 10.984 9.479 13.7%
Large General Service 559,072,437 57,205,610 50,299,747 10.232 8.997 12.1%
Outdoor Lighting Service 40,858,107 10,553,509 8,780,816 25.830 21.491 16.8%
Total Retail 5,534,937,078 $ 717,867,558 $608,014,316 $ 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 cents/kWh.
(3) Includes a Transition Service energy charge of 4.400 cents/kWh.
Page 59
APPENDIX B - ENVIRONMENTAL RESERVE FUND IDENTIFIED SITES
▇▇▇▇▇▇ 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)
▇▇▇▇▇▇▇ Landfill (Dover, NH)
▇▇▇▇▇▇▇ 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)
Page 60
APPENDIX C - ESTIMATED BALANCE OF THE ASSETS AS OF JUNE 30, 2000
APPENDIX C - ESTIMATED BALANCE OF THE STRANDABLE ASSETS AS OF JUNE 30, 2000
(Millions of Dollars)
06/30/00 06/30/00 06/30/00
Book Market Strandable 2000 6/30/00 Amort.
Balance Value Assets Written-Off Securitized Amortized Years
Seabrook Over-Market Generation Assets $ 594 $ 100 $ 494 $ - $ 494 $ - $ 12
MP3 Over-Market Generation assets 82 - 82 - 64 18 12
Fossil Over-Market Generation assets (12/00) 178 290 (112) - - (112) 11.5
Hydro Over-Market Generation assets (12/01) 24 70 (46) - - (46) 10.5
Seabrook Deferred Return - NAEC 90 - 90 90 - -
Seabrook Deferred Return - PSNH 15 - 15 15 - -
Acquisition Premiums 310 - 310 162 - 148 12
Acquisition Premiums - F109 185 - 185 97 - 88 12
Unrecovered Obligation - YAEC, CY, MY 50 - 50 - - 50 8
Deferred SPP Costs 102 - 102 - - 102 12
Deferred FPPAC Costs 107 - 107 - - 107 12
Deferred VY Contract Termination Payments - (9) 9 - - 9 12
Market Value of Wholesale Power Contracts - 10 (10) - - (10) 12
Reserves for NHEC Settlement (24) - (24) - - (24) 12
Deferred NOx Allowance Credits (12/00) (5) - (5) - - (5) 11.25
Unamortized Loss on Reacq. Debt (6/00) 3 - 23 3 15 5 12
Unamortized Loss on Reacq. Debt (12/00) - - 11 - - 11 11.5
Unamortized Loss on Reacq. Debt (12/01) - - 3 - - 3 10.5
Total Assets $ 1,711 $ 461 $1,284 $ 366 $ 573 $ 345
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APPENDIX D - FORECAST AMORTIZATION SCHEDULE FOR STRANDABLE ASSETS
(Thousands of Dollars)
Year Ending 12/31:
7/00 - 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
6/30/00 12/00
Seabrook Over-Market
Generation Assets
Securitized -- 13,170 27,813 29,897 2,138 34,547 37,137 39,920 42,913 46,130 49,588 53,305
MP-3 Over-Market
Generation Assets
Securitized -- 1,703 3,597 3,867 4,156 4,468 4,803 5,163 5,550 5,966 6,413 6,894
Amortized -- 762 1,524 1,524 1,524 1,524 1,524 1,524 1,524 1,524 1,524 1,524
Fossil Over-Market
Generation
Assets (12/00) -- -- (9,781) (9,781) (9,781) (9,781) (9,781) (9,781) (9,781) (9,781) (9,781) (9,781)
Hydro Over-Market
Generation
Assets (12/01) -- (4,401) (4,401) (4,401) (4,401) (4,401) (4,401) (4,401) (4,401) (4,401) (4,401) (4,401)
Seabrook Deferred
Return-NAEC
Written-off 89,892 -- -- -- -- -- -- -- -- -- -- --
Seabrook Deferred
Return - PSNH
Written-off 15,169 -- -- -- -- -- -- -- -- -- -- --
Acquisition Premiums
Written-off 161,963 -- -- -- -- -- -- -- -- -- -- --
Amortized 6,178 12,356 12,356 12,356 12,356 12,356 12,356 12,356 12,356 12,356 12,356 12,356
Acquisition
Premiums - F109
Written-off 96,788 -- -- -- -- -- -- -- -- -- -- --
Amortized 3,692 7,384 7,384 7,384 7,384 7,384 7,384 7,384 7,384 7,384 7,384 7,384
Unrecovered
Obligation - YAEC,
CY, MY -- 3,538 7,048 6,901 6,718 6,700 6,229 5,992 4,850 2,440 -- --
Deferred DOE
Assessment -- 9 18 18 18 18 18 18 18 18 18 18
Deferred SPP Costs -- 4,240 8,481 8,481 8,481 8,481 8,481 8,481 8,481 8,481 8,481 8,481
Deferred FPPAC Costs -- 4,458 8,917 8,917 8,917 8,917 8,917 8,917 8,917 8,917 8,917 8,917
VY Contract
Termination Payment -- 392 783 783 783 783 783 783 783 783 783 783
Market Value of
Wholesale Power
Contracts -- (417) (833) (833) (833) (833) (833) (833) (833) (833) (833) (833)
Reserves for NHEC
Settlement -- (1,008) (2,017) (2,017) (2,017) (2,017) (2,017) (2,017) (2,017) (2,017) (2,017) (2,017)
Deferred NOx Allowance
Credits -- -- (391) (391) (391) (391) (391) (391) (391) (391) (391) (391)
Unamort. Loss on Reacq
Debt - Exist -- 124 249 249 249 249 249 249 249 249 249 249
Unamort. Loss on Reacq
Debt - 6/00 -- 90 181 181 181 181 181 181 181 181 181 181
Unamort. Loss on Reacq
Debt - 12/00 -- -- 953 953 953 953 953 953 953 953 953 953
Unamort. Loss on Reacq
Debt - 12/01 -- -- 248 248 248 248 248 248 248 248 248 248
Financing Costs - 6/00
Written-off 2,599 -- -- -- -- -- -- -- -- -- -- --
Securitized -- 400 844 908 976 1,049 1,127 1,212 1,303 1,400 1,505 1,618
Total 366,411 37,332 67,123 65,240 67,656 70,432 72,964 75,955 78,284 79,604 81,174 85,485
APPENDIX D - FORECAST AMORTIZATION SCHEDULE FOR STRANDABLE ASSETS
(Thousands of Dollars)
2011 2012 Total
Seabrook Over-Market
Generation Assets
Securitized 57,300 30,242 494,099
MP-3 Over-Market
Generation Assets
Securitized 7,411 3,911 63,901
Amortized 1,524 762 18,285
Fossil Over-Market
Generation
Assets (12/00) (9,781) (4,891) (112,487)
Hydro Over-Market
Generation
Assets (12/01) (4,401) (2,200) (46,209)
Seabrook Deferred
Return-NAEC
Written-off -- -- 89,892
Seabrook Deferred
Return - PSNH
Written-off -- -- 15,169
Acquisition Premiums
Written-off -- -- 161,963
Amortized 12,356 6,178 148,269
Acquisition
Premiums - F109
Written-off -- -- 96,788
Amortized 7,384 3,692 88,603
Unrecovered
Obligation - YAEC,
CY, MY -- -- 50,416
Deferred DOE
Assessment 18 9 215
Deferred SPP Costs 8,481 4,240 101,771
Deferred FPPAC Costs 8,917 4,458 107,000
VY Contract
Termination Payment 783 392 9,400
Market Value of
Wholesale Power
Contracts (833) (417) (10,000)
Reserves for NHEC
Settlement (2,017) (1,008) (24,200)
Deferred NOx Allowance
Credits (391) (196) (4,500)
Unamort. Loss on Reacq
Debt - Exist 249 124 2,982
Unamort. Loss on Reacq
Debt - 6/00 181 90 2,167
Unamort. Loss on Reacq
Debt - 12/00 953 476 10,955
Unamort. Loss on Reacq
Debt - 12/01 248 124 2,604
Financing Costs - 6/00
Written-off -- -- 2,599
Securitized 1,740 918 15,000
Total 90,118 46,905 1,284,682
Page 62
(Thousands of Dollars)
Year Ending 12/31:
12/00
7/00 - 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
6/30/00 12/00
Total Write-Off 366,411 -- -- -- -- -- -- -- -- -- -- --
Total Securitized -- 15,273 32,254 34,671 37,270 40,064 43,067 46,295 49,766 53,496 57,506 61,817
Total Amortization -- 22,059 34,869 30,569 30,386 30,368 29,897 29,660 28,518 26,108 23,668 23,668
Total 366,411 37,332 67,123 65,240 67,656 70,432 72,964 75,955 78,284 79,604 81,174 85,485
Balance of Total
Stranded Assets 918,271 880,940 813,817 748,577 680,921 610,489 537,525 461,570 383,286 303,682 222,508 137,023
Securitization: 6/30/00 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Total Payment 35,816 71,631 71,631 71,631 71,631 71,631 71,631 71,631 71,631 71,631 71,631
Interest Payment
(at 7.25%) 20,543 39,377 36,960 34,361 31,567 28,564 25,336 21,865 18,135 14,125 9,814
Principal Payment 15,273 32,254 34,671 37,270 40,064 43,067 46,295 49,766 53,496 57,506 61,817
Principal Balance 573,000 557,727 490,802 453,532 413,468 370,401 324,106 274,340 220,844 163,338 101,521
EOY
(Thousands of Dollars)
Year Ending 12/31:
2011 2012 Total
Total Write-Off - - 366,411
Total Securitized 66,450 35,071 573,000
Total Amortization 23,668 11,834 345,271
Total 90,118 46,905 1,284,682
Balance of Total
Stranded Assets 46,905
Securitization: 2010 2011 2012
Total Payment 71,631 71,631 35,816
Interest Payment 9,814 5,181 745
Principal Payment 61,817 66,450 35,071
Principal Balance 101,521 35,071 -
EOY
Page 63
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.
Page 64
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
E. Revise Descriptive Memorandum (DM) to conform to PUC
approval
17
F. 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
G. 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
H. 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
I. Round 2 Bidders notified and scheduled
24 Site visits and management presentations
1-May-00 Site visits and management presentations
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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.
Page 66
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:
Seasonal
claimed Year
Unit Load role Fuel 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.
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Newington Station Generating Facilities
Seasonal
claimed Year
Unit Load role Fuel 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.
▇. ▇▇▇▇▇▇▇▇ 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
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coal for Merrimack Station is received by ship or barge at the main dock at
Schiller Station.
Schiller Station Generating Facilities
Seasonal
claimed
Unit capability
Installed Load role Fuel (winter)(MW) Year
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. ▇▇▇▇▇▇▇▇'▇ 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, ▇▇▇▇▇▇▇▇ 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:
▇. ▇▇▇▇▇ Station
▇▇▇▇▇ 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.
Page 69
▇▇▇▇▇ Station Generating Facilities
Seasonal
claimed
capability Year
Unit Load role Fuel (winter) (MW) Installed
▇▇▇▇▇ Run-of-river 14.2 1 1948
The project operates in a run-of-river mode. High capacity factors are
achieved at ▇▇▇▇▇ 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.
▇. ▇▇▇▇▇▇ Station
▇▇▇▇▇▇ 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.
▇▇▇▇▇▇ Station Generating Facilities
Seasonal
claimed
capability Year
Unit Load role Fuel (winter) (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
▇▇▇▇▇ Station. ▇▇▇▇▇▇ Station consists of a dam and adjacent canal gatehouse, a
power canal and a four-unit powerhouse. Limited ponding capability exists.
▇▇▇▇▇▇ 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)
▇▇▇▇▇ 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
Page 70
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 ▇▇▇▇▇ and
▇▇▇▇▇▇ 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 ▇▇▇▇▇▇ Dam at Lake ▇▇▇▇▇▇▇ and 82 miles
above ▇▇▇▇▇ 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
Seasonal
claimed
capability Year
Unit Load role Fuel (winter) (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.
▇. ▇▇▇▇▇ Island Station
▇▇▇▇▇ 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.
▇▇▇▇▇ Island Station Generating Facilities
Seasonal
claimed Year
capability Last Unit
Station Load role (winter) (MW) Units Installed
▇▇▇▇▇ Island Run-of-river 9.1 3 1931
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▇▇▇▇▇ 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.
▇. ▇▇▇▇▇▇▇ Falls Station
▇▇▇▇▇▇▇ 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.
▇▇▇▇▇▇▇ Falls Stations Generating Facilities
Seasonal
claimed Year
capability Last Unit
Station Load role (winter) (MW) Units Installed
▇▇▇▇▇▇▇ Falls Run-of-river 6.5 2 1983
▇▇▇▇▇▇▇ 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 ▇▇▇▇▇ 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
Seasonal
claimed Year
capability Last Unit
Station Load role (winter) (MW) Units 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.
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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
Seasonal
claimed Year
capability Last Unit
Station Load role (winter) (MW) Units 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.
▇. ▇▇▇▇▇▇▇ 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
Seasonal
claimed Year
capability Last Unit
Station Load role (winter) (MW) Units 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.
▇. ▇▇▇▇▇▇▇ Station
Jackman Station consists of a dam, located on ▇▇▇▇▇▇▇▇ ▇▇▇▇▇▇ 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
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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.
▇▇▇▇▇▇▇ Station Generating Facilities
Seasonal
claimed Year
capability Last Unit
Station Load role (winter) (MW) Units Installed
Jackman Run-of-river 3.6 1 1926
▇▇▇▇▇▇▇ 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
Seasonal
claimed Year
capability Last Unit
Station Load role Fuel (winter) (MW) Units Installed
Lost Nation Peaking Oil 19.1 1 1969
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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.
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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.
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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
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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.
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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
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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,
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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
I. 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
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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.
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D. 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.
E. 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.
F. 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.
G. 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
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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
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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.▇▇-▇▇-▇▇▇.
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,
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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
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third party.
If D.▇▇-▇▇-▇▇▇ is applicable to the information the utility seeks to
protect, the utility should follow the procedure set forth in
D.▇▇-▇▇-▇▇▇, except that the utility should serve the third party
making the request in a manner that the third party receives the
utility's D.▇▇-▇▇-▇▇▇ 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
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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
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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.
Page 89
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
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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.▇▇-▇▇-▇▇▇,
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
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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
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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
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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
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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.
4. "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
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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
e. 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
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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.▇▇-▇▇-▇▇▇, 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:
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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.
5. 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
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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.
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