As filed with the Securities and Exchange Commission on October 17, 1997
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8 - K
Current Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
Date of Report (Date of earliest event reported) October 10, 1997
NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
New York
(State or Other Jurisdiction of Incorporation)
1-2987 15-0265555
(Commission File Number) (IRS Employer Identification No.)
300 Erie Boulevard West, Syracuse, NY 13202
(Address of Principal Executive Offices) (Zip Code)
(315) 474-1511
(Registrant's Telephone Number, Including Area Code)
N/A
(Former Name or Former Address, if Changed Since Last Report)
Items 1-4. Not Applicable.
Item 5. Other Events.
On October 10, 1997, Niagara Mohawk Power Corporation
("Company") filed its PowerChoice settlement with the Public
Service Commission of the State of New York ("PSC"), which
incorporates the terms of the Master Restructuring Agreement
(MRA). The settlement will be the subject of evidentiary and
public statement hearings before an administrative law
judge. The PSC will review the settlement and the judge's
analysis in open session before voting on the agreement.
The Company hopes to obtain approval from the PSC by early
1998 and to consummate the MRA in the first half of 1998.
The foregoing is qualified in its entirety by the text of
the PowerChoice settlement, a copy of which is filed as
Exhibit 99.1 hereto and incorporated herein by reference.
Item 6. Not Applicable.
Item 7. Financial Statements, Pro Forma Financial
Information and Exhibits.
(a)-(b) Not Applicable.
(c) Exhibits Required by Item 601 of Regulation
S-K.
EXHIBIT NUMBER DESCRIPTION
99.1 PowerChoice settlement filed with the
PSC on October 10, 1997
99.2 Press Release, dated October 10, 1997
Items 8-9. Not Applicable.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SIGNATURE
Pursuant to the requirements of the Securities and
Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, hereto
duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
BY:/s/ Steven W. Tasker
-----------------------
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer
Date: October 17, 1997
EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION
99.1 PowerChoice settlement filed with the
PSC on October 10, 1997
99.2 Press Release, dated October 10, 1997
EXHIBIT 99.1
-------------
NIAGARA MOHAWK POWER CORPORATION
POWERCHOICE SETTLEMENT AGREEMENT
Table of Contents
1.0 BACKGROUND
2.0 RATE PLAN
2.1 Introduction/Summary
2.2 Term and Effective Date of Rates
2.3 Master Restructuring Agreement (MRA)
2.3.1 Prudence of the MRA
2.3.2 Reasonable Opportunity to Recover Costs
2.3.3 Recovery of Costs Associated with
Termination of Related Gas
Transportation and Peak
Shaving Agreements
2.3.4 SIPP Cost Recovery
2.4 Overall Rate and Revenue Levels
2.4.1 Average Prices
2.4.1.1 Years One Through Three
2.4.1.2 Price Cap for Years Four and Five
2.4.2 Revenues and Financial Forecast
2.4.3 Rate Adjustment Mechanisms
2.4.4 Gross Receipts Tax (GRT) Reform
2.4.5 Securitization
2.5 Stranded Cost Recovery
2.6 Deferrals
2.6.1 Cost Categories Eligible for Deferrals
2.6.2 New York Power Authority Transmission
Access Charge (NTAC) Deferral
2.6.3 Tax Refunds/Payments
2.6.4 Additional IPP Contract Termination or
Restructuring
2.6.5 Disposition of Existing Cost Deferrals
Not Yet Reflected in Rates
2.6.5.1 Generally
2.6.5.2 Site Investigation and Remediation
Program
2.7 SFAS No. 71 Applicability
2.8 Rate Filing for Period After Term of This
Agreement
3.0 NIAGARA MOHAWK GENERATION
3.1 Introduction and Summary
3.1.1 Generation Owned by Niagara Mohawk
3.1.2 Generation Purchased from IPPs
3.2 Guiding Principles for Fossil/Hydro Generation
Auction
3.2.1 Agreement to Divest Fossil/Hydro
Generation
3.2.2 Non-Nuclear Generation Sale Incentive
3.2.3 Labor Issues Associated with Divestiture
3.2.3.1 Labor Contract Issues
3.2.3.2 Retraining and Severance Costs
3.2.4 Unhedged Energy and the CTC for
Fossil/Hydro Assets
3.3 Guiding Principles for Nuclear Assets
3.3.1 Study to Determine Future Disposition
3.3.2 Recovery of Stranded Costs
3.3.3 Cost Treatment if a Nuclear Plant is
Sold, Transferred or Divested
3.3.4 Cost Treatment in the Event of a Plant
Retirement
3.4 Design Principles for Transition Contracts with
Generators
3.4.1 Design Features Common to All Generators
3.4.1.1 Transition Contract Overview
3.4.1.2 Primary Design Components
3.4.2 NMPC Fossil and Hydro Generation
Transition Contract(s)
3.4.3 Nuclear Generation Transition Contracts
3.4.4 Settling Independent Power Producers
(SIPPs)
3.5 Other Independent Power Producers (IPPs)
4.0 ELECTRIC PRICES
4.1 Overview of Bundled and Unbundled Prices
4.1.1 Bundled Prices
4.1.1.1 Residential and Commercial Class
Price Levels
4.1.1.2 Industrial and Large Commercial
Price Levels
4.1.2 Methodology for Arriving at Bundled
Prices
4.1.2.1 Calculation of "Base" 1997 Rates
Before Decreases
4.1.2.2 Application of Percentage Decreases
for SC 1, 2, & 3
4.1.2.3 Calculation of SC-3A Rates
4.1.3 Relationship to Dairylea Pilot
4.1.4 Planned Reductions Associated with Gross
Receipts Tax Reform
4.1.5 Potential Securitization Savings
4.2 CTC and Market Price Hedging
4.2.1 Overview
4.2.2 General Calculation and Application
4.2.3 Commodity Adjustment Charge
4.2.4 Significance of Hedged and Unhedged
Energy
4.2.5 CTC Options and Market Price Forecast
4.2.5.1 For S.C. No. 3A and S.C. No.4
(>2 MW) Customers
4.2.5.2 For S.C. Nos. 1, 2, & 3 Customers
4.2.6 Adjustments to the CTC in Years Four and
Five
4.2.7 Alcan and Sithe/Independence
4.3 Surcharge and Reconciliation Mechanisms
4.3.1 Surcharge Mechanisms That Will Be
Abolished
4.3.2 Gross Receipts Tax Surcharge
4.3.3 NYPA Hydropower Benefit Reconciliation
4.3.4 System Benefits Charge
4.3.5 Deferrals
4.3.6 Recovery of Generation Sale Incentive
4.4 Unbundled Services and Prices
4.4.1 Unbundled Energy Commodity Charge
4.4.2 Unbundled Transmission Charges
4.4.3 Unbundled Distribution Charges
4.4.4 Price Cap Plan for Transmission and
Distribution Services
4.4.4.1 T&D Rate Increases
4.4.4.2 CTC Offsets to Increased T&D Prices
4.4.4.3 Price Cap for Years 4 and 5
4.4.5 Availability of Unbundled Prices for
Informational Purposes
4.4.6 Relationship to Generation Separation
4.4.7 Customer Service Backout Credit
4.5 Residential Pricing Designs
4.5.1 Service Classification No. 1 - Standard
Residential Rate
4.5.1.1 Flat Rate Structure
4.5.1.2 Phased-in Rebalancing of Customer
and Energy Charge
4.5.1.3 Phased-in Discount from Initial
Price Levels
4.5.2 Service Classification Nos. 1B and 1C -
Residential Time-of-Use Rates
4.5.3 Service Classification No. 1H - Optional
Residential Rate
4.5.4 CTC
4.6 Commercial Pricing Designs
4.6.1 Service Classification Nos. 2ND - Small
General Service Rates
4.6.1.1 Flat Rate
4.6.1.2 Phased-in Rebalancing of Customer
and Energy Charges
4.6.1.3 Phased-in Discount from Initial
Price Levels
4.6.2 Service Classification No. 2D - Small
General Service Rates
4.6.2.1 Phased-in Rebalancing of Customer
and Energy Charges
4.6.2.2 Phased-in Discount from Initial
Price Levels
4.6.3 CTC
4.7 Large General Service (S.C. Nos. 3, 3A, 4 and 5)
Pricing Designs
4.7.1 S.C. No. 3 (Large General Service <2 MW)
and Smaller S.C. No. 4 Customers (<2 MW)
4.7.1.1 Rate Design
4.7.1.2 Initial Price Levels
4.7.1.3 CTC
4.7.2 S.C. No. 3A (Large General Service,
Mandatory Time-of-Use, High Demand) and
Large S.C. No. 4 Customers (>2 MW)
4.7.2.1 Rate Design
4.7.2.2 Initial Price Levels
4.7.2.3 Rebalancing of Demand Charges
4.7.2.4 CTC
4.7.3 S.C. No. 5 (Combination 25 & 60 Cycle
Power)
4.7.4 Projected Industrial Prices
4.8 Customers with S.C. No. 11 Contracts and Economic
Development Programs
4.9 Optional Tariffs for non-Residential Customers
4.10 Customers Selling Power to Niagara Mohawk Under
S.C. No. 6
4.11 Exit Fee for Customers who Bypass the Company's
Delivery Service and Customers Taking Service
Under S.C. No. 7 (Sale, Backup, Maintenance and
Supplemental Energy and Capacity to Customers
with On-Site Generation Facilities)
4.11.1 Rationale
4.11.2 Applicability
4.11.3 Exit Fee
4.11.4 S.C. No. 7
4.11.4.1 Existing Customers
4.11.4.2 New Subscribers and Existing
S.C.No. 7 Customers Following
Divestiture of the Company's
Fossil and Hydro Assets
4.12 Economic Development Zone Rider (EDZR)
4.13 Pricing Designs for Service Classifications Under
PSC No. 214 -- Electricity
4.14 Application of Unbundled Prices to NYPA
Allocations
4.15 Annual Tariff Filings
4.16 Rate Flexibility
4.16.1 General
4.16.2 Optional Rates and Services
4.17 Miscellaneous Tariff Amendments
4.17.1 Aggregation of Demand and Customer
Charges
4.17.2 Low Voltage Bypass
5.0 CUSTOMER SERVICE BACKOUT CREDIT
5.1 Gross Revenue Exposure
5.2 Design Principles
5.3 Relationship to a Generic Proceeding
6.0 CUSTOMER SERVICE INCENTIVE
6.1 Customer Service Performance
6.1.1 PSC Complaint Rate
6.1.2 Corporate Residential Transaction
Satisfaction Index
6.1.3 Low Income Assistance Program
6.2 Statement of Intent
6.3 Service Reliability Incentive
6.3.1 System Interruption Frequency (SIF)
6.3.2 Customer Interruption Duration (CID)
6.3.3 Power Quality
6.4 Accounting Mechanism
7.0 SYSTEM BENEFITS CHARGE PROGRAMS
7.1 System Benefits Charge
7.1.1 Programs and Funding Levels
7.1.2 State-Wide Third Party Administrator
7.1.3 Low Income Customer Assistance Program
(LICAP)
7.2 Miscellaneous
8.0 RETAIL ACCESS
8.1 Conditions Necessary For Retail Access
8.1.1 Proper Metering
8.1.2 Billing and Settlement Procedures
Consistent with Market
8.2 Retail Access Timetable
8.2.1 Farm & Food Processor Pilot
8.2.2 Group 1
8.2.3 Group 2
8.2.4 Group 3
8.2.5 Group 4
8.2.6 Group 5
8.2.7 Customers With Special Contracts
8.2.8 Monitoring Progress Through Time
8.2.9 Contingencies
8.3 Retail Access Settlement Method
8.3.1 Forecasting and Scheduling Requirements
8.3.2 Metering Requirements
8.3.3 Services Not Covered by the Settlement
System
8.3.4 Nondiscriminatory Treatment of Customers
8.3.5 Auditing of the Settlement Function
8.4 Reciprocity Assurances
9.0 CORPORATE STRUCTURE AND AFFILIATE RULES
9.1 Proposed Corporate Structure
9.2 Rules Governing Affiliate Transactions
9.2.1 Organization
9.2.1.1 Separation and Location
9.2.1.2 Board of Directors Membership and
Fiduciary Duty
9.2.1.3 Cost Allocation
9.2.2 Transfer of Non-Generation Assets
9.2.3 Transfer of Services
9.2.4 Special Services
9.2.5 Human Resources
9.2.5.1 Separation of Employees and
Officers
9.2.5.2 Employee Transfers
9.2.5.3 Employee Loans in an Emergency
9.2.5.4 Compensation for Transfers
9.2.5.5 Employee Compensation and Benefits
9.2.5.6 Legal Representation
9.2.6 Maintaining Financial Integrity
9.2.7 Access to Books, Records and Reports
9.2.8 Reporting
9.3 Standards of Competitive Conduct
9.3.1 Use of Corporate Name and Royalties
9.3.2 Sales Leads
9.3.3 Customer Inquiries
9.3.4 No Advantage Gained by Dealing with
9.3.5 No Rate Discrimination
9.3.6 FERC Jurisdiction
9.3.7 Customer Information
9.3.8 Other Information
9.3.9 Complaint Procedures
9.4 Miscellaneous
9.4.1 Applicability of Settlement Standards of
Conduct
9.4.2 Annual Meeting
9.4.3 Training and Certification
9.4.4 Telergy
9.5 Mergers and Acquisitions
9.5.1 Recovery of Premium
9.5.2 Relationship to Divestiture
9.5.3 Applicability of this Agreement Post
Merger
9.5.4 Expedited Review
10.0 SUPPLIER OF LAST RESORT OBLIGATION AND
IMPLEMENTATION
10.1 Obligation to Serve
10.2 Implementation
10.2.1 Energy Service Providers, Marketers and
Brokers
10.2.2 Customer Operations Procedures
10.2.3 Credit and Collection Matters
10.2.3.1 Customer Creditworthiness
10.2.3.2 ESCo Creditworthiness Evaluation
10.2.4 Termination Decisions
10.2.5 Cost Recovery
11.0 REGULATORY CHANGES AND APPROVALS
11.1 Elimination of Certain Regulatory Requirements
11.1.1 Regulatory Reporting Requirements
11.1.2 Treatment of Future Refunds
11.2 Regulatory Approvals
11.2.1 Commercialization of Products and
Technologies Developed as a Result of
Research and Development
11.2.2 PSL Sections 69 and 70 Approval of the
Sale,Leasing or Financing of Building
Facilities
11.2.3 Conversion of 25 Cycle Customers
12.0 LOW INCOME CUSTOMER ASSISTANCE PROGRAM (LICAP)
12.1 Eligibility Criteria
12.2 Program Description
12.3 Program Funding
13.0 MISCELLANEOUS
13.1 Force Majeure
13.2 Commission Authority
13.3 Provisions Not Separable: Effect of Commission
Modification
13.4 Provisions Not Precedent
13.5 Dispute Resolution
13.6 Withdrawal from Litigation
13.7 Constriction of Terms
13.8 Steam Host Issues
14.0 TERM OF THIS AGREEMENT
SECTION 1.0
BACKGROUND
In February of 1994, Niagara Mohawk filed a
comprehensive five-year rate proposal, which opened
docket 94-E-0098. Following extensive public statement
and evidentiary hearings, the proposal was split into
two "phases" for briefing and decision by the
Commission. The Commission decided the first phase,
setting 1995 rates, in an April 21, 1995 "short order"
and in Opinion 95-21.() The multi-year part of the
record was never presented to the Commission. Rather,
in the April 21 Order, the Commission urged the parties
to attempt to negotiate a comprehensive long-term
solution to Niagara Mohawk's escalating costs. The
Commission ordered the parties, among other things, "to
address [the Company's 1996-1999] rate levels, Niagara
Mohawk's financial security, the protection of customer
service quality, and regulatory changes reflecting
increased competition. ... [and] improve the company's
competitive position, without anti-competitive effects,
by addressing the excessive generation cost burden."
The Commission also directed the parties to develop a
multi-year plan "consistent with policies being
developed in connection with the review of competitive
opportunities in Case 94-E-0952."()
The Company answered the Commission's call for a
comprehensive solution and multi-year plan by filing
its PowerChoice proposal on October 6, 1995, which
followed informational sessions among all parties held
June-September 1995. PowerChoice proposed an
electricity price freeze for most customer classes and
reductions for others for the period 1996-2000;
financial concessions by the Company and the IPPs in
proportion to their contribution to strandable costs in
order to finance the price freeze; creation of
competitive wholesale generation market in the
Company's service territory through the formation of an
Independent System Operator (ISO) and divestiture of
all of Niagara Mohawk's generation, including its
nuclear units; and introduction of customer choice for
all classes over a three-year period. In exchange for
the Company's willingness to undertake these
initiatives, Niagara Mohawk asked that the State help
in reducing the costs of above market IPP contracts;
for assurance of a reasonable opportunity to recover
strandable costs remaining after concessions by Niagara
Mohawk and the IPPs; and for permission to form a
holding company whose unregulated subsidiaries would
have a fair opportunity to compete in the new market.
In the nine months following the filing of PowerChoice,
the Company engaged in extensive negotiations and
discussions with all parties. During this time,
proceedings were ongoing in the Competitive
Opportunities Proceeding. Thereafter, in Opinion 96-12, Opinion
and Order Regarding Competitive
Opportunities for Electric Service (issued May 20,
1996), the Commission expressed its "vision for the
future of the electric industry in light of competitive
opportunities ...," and added that utilities and IPPs
"... are strongly encouraged to pursue agreements that
reduce rates to benefit ratepayers. If parties are
unwilling, however, to restructure those contracts
voluntarily, the Commission shall pursue policies to
mitigate the impact of such contracts on rates." The
Commission further directed the IPPs "to move forward
aggressively in appropriate forums to seek solutions
such as a buyout of contracts or renegotiations of
them so as to align them more closely with a
competitive framework." Opinion 96-12 went on to
require each utility to file a rate/restructuring plan
"consistent with our policy and vision for increased
competition" by October 1, 1996. Niagara Mohawk was
specifically excluded from that filing requirement
because it had previously filed its PowerChoice plan.
By June 1996, it had become clear that no further
progress in Niagara Mohawk's PowerChoice negotiations
could be made until the Company could put forward a
definitive rate plan, and a definitive rate plan would
require a comprehensive settlement with the IPPs. The
Company suspended PowerChoice negotiations and focused
on negotiations with the IPPs.
On July 9, 1997, after 16 months of arduous and
contentious negotiations against the backdrop of many
years of court and administrative litigation and the
very real prospect of years of future litigation, the
Company executed the Master Restructuring Agreement,
("MRA") with 29 IPPs represented by 16 developers who
collectively represent more than 80% of the Company's
above-market IPP costs. These IPPs (the "Settling
IPPs", or "SIPPs") agreed to restructure, amend or
replace their current IPP contracts in exchange for:
- $3.6 billion in newly issued debt or cash;
- 46 million shares of common stock (slightly
less than 25% of the Company's equity); and
- a portfolio of certain financial or physical
delivery contracts.
On July 23, 1997, the Company filed a revised
settlement offer for PowerChoice. Two months of
intensive negotiations followed, with the Company,
Staff and several intervenors reaching an Agreement in
Principle on September 25, 1997.
More than sixty parties have intervened in this
proceeding, with almost 30 parties participating
actively in the settlement negotiations. Unlike the
other New York electric utility restructuring
proceedings, the Company, Staff and other parties
negotiated without waiver of the Commission's
Settlement regulations. Administrative Law Judge
Stockholm has mediated the negotiations throughout,
with Judges Lee and Brilling joining him since the
Company's July 23, 1997 Settlement Offer filing.
The Settlement Agreement (also the Agreement or
Settlement) that follows, like the MRA upon which it
rests, resolves many complex and seemingly insoluble
issues and is the product of much hard bargaining among
the many, normally-adversarial parties to this
proceeding. The signatories to this Settlement
Agreement strongly recommend its swift approval.
SECTION 2.0
RATE PLAN
2.1 INTRODUCTION AND SUMMARY
Price level targets and price designs are described in
Section 4.0. This Section describes the Rate Plan,
including the date on which the Agreement becomes
effective, the treatment of costs during the term of
the Agreement, and the mechanisms for adjusting prices
over time.
RATE PLAN FOR YEARS ONE THROUGH THREE. During years
one through three of the Agreement, prices have been
set at the targets listed in Table 4-1 and 4-2. During
the first three years, prices may only be adjusted for
a limited number of surcharges which could raise or
lower prices. These surcharges include the New York
Power Authority (NYPA) Hydropower Credit described in
Section 2.4.3, a surcharge to account for variations
from forecasted costs in the event a nuclear power
plant is retired (described in Section 2.5 and 3.3.4)
and an increase in spending levels for the System
Benefits Charge (if ordered by the Commission, as
described in Section 2.4.3).
However, during the first three years, certain costs or
savings can be deferred for recovery or refund
beginning in years four and five of the Agreement. The
items that can be deferred are limited and are
described in Section 2.6.
RATE PLAN FOR YEARS FOUR AND FIVE. For years four and
five of the Agreement, the Company can file for a rate
increase, but that increase must be capped at 1% for
all elements of rates except the market price of the
electric commodity itself, and except as specified
below. The details of this price cap plan are
described in Section 2.4.1.2. In addition, Niagara
Mohawk can begin to recover through a surcharge, the
expenses that it was allowed to defer in the first
three years of the Agreement. Surcharges applicable in
years four and five are the surcharges applicable in
the first three years as well as the generation auction
incentive surcharge which is described in Section
2.4.3. Recovery of deferrals and the generation
auction incentive in years four and five is limited
such that these surcharges plus any allowed rate
increase under the 1% price cap cannot exceed the rate
of inflation. This mechanism is described in more
detail in Section 2.4.3. Finally, the price cap and
the inflation cap for deferral recovery exclude the
recovery or refund of the difference between the actual
and forecasted costs associated with certain approved
IPP Indexed Contracts, which will begin in year four as
described in Section 2.4.1.2.
STRANDED COST RECOVERY. Upon fulfilling certain
commitments described herein, the Company shall have a
reasonable opportunity to recover its stranded
generation costs, including costs associated with its
own generation as well as the costs associated with the
Master Restructuring Agreement between the Company and
the Settling Independent Power Producers (SIPPs) as
described in Sections 2.3, 2.5 and 3.0.
2.2 TERM AND EFFECTIVE DATE OF RATES
The Company proposes to implement the rate plan for a
period of five years, commencing on the PowerChoice
Implementation Date.
The PowerChoice Implementation Date is dependent upon
receipt of Public Service Commission approval of this
Settlement Agreement, as well as completion of other
steps subsequent to PSC approval, including, but not
limited to, obtaining various approvals to issue debt
and sell equity, SIPPs settlement of their third party
obligations and negotiation between the Company and the
SIPPs of new contractual arrangements. New tariffs will
not become effective until these steps are completed.
The Company will file proposed tariffs to implement
this agreement as soon as is reasonably possible
following approval of this agreement, but in no event
later than 60 days following approval of this
agreement. The Company's objective is to consummate
these steps as soon as possible. Many steps on the
critical path to implementation are predicated on
receiving written PSC approval. Any delays in receiving
written PSC approval will result in a delay in the
implementation of new rates. Any delay in the
completion of subsequent steps would also delay the
effective date. For the purpose of defining the five
year term of the rate plan, the first rate year begins
with the PowerChoice Implementation Date and each
subsequent rate year begins on the anniversary thereof.
2.3 MASTER RESTRUCTURING AGREEMENT (MRA)
2.3.1 PRUDENCE OF THE MRA
The MRA and the contracts to be executed pursuant
thereto are found to be prudent and recoverable to the
extent provided herein. The specific details of debt
and stock issuances required to finance the MRA will be
subject to separate review and approval after filing.
2.3.2 REASONABLE OPPORTUNITY TO RECOVER COSTS
The Company will have a reasonable opportunity to
recover stranded costs associated with the MRA,
including all costs of the contracts to be executed
pursuant to the MRA (as described in Appendix A and
Section 4.4), except for the return on the regulatory
asset, through the Competitive Transition Charge (CTC)
or, where applicable, exit fees. The Commission will
consider any request for a return on the regulatory
asset post year five of the PowerChoice Settlement
Agreement.
2.3.3 RECOVERY OF COSTS ASSOCIATED WITH TERMINATION
OF RELATED GAS TRANSPORTATION AND PEAK
SHAVING AGREEMENTS
The Parties agree that the Company will recover in gas
rates certain costs associated with the termination of
gas transportation and peak shaving agreements between
the SIPPs and Niagara Mohawk, as described in Appendix
B.
2.3.4 SIPP COST RECOVERY
The costs of the SIPP contract restructuring and
termination resulting from the MRA and associated
contracts will be deferred and amortized over a period
not to exceed ten years. To achieve the price levels
described in Tables 4-1 and 4-2, the Company proposes
not to set a specific rate of return on the regulatory
asset, although it is obvious from the financial
forecast in Appendix C that little or no return is
forecast to be earned on that asset during the term of
the settlement agreement.
The Company will be taking the position with the
Internal Revenue Service generally that the cash and
common stock portion of the SIPP settlement costs are
currently deductible, creating a Net Operating Loss
carry back that would entitle the Company to a refund
of prior years paid taxes. The refund would be used to
fund a portion of the cash needed for the SIPP
settlement, and would not be otherwise deferred for
other rate making purposes.
2.4 OVERALL RATE AND REVENUE LEVELS
2.4.1 AVERAGE PRICES
2.4.1.1 YEARS ONE THROUGH THREE
The agreed upon prices for the major service
classifications for years one through three
are set forth in Tables 4-1 and 4-2 and
described in greater detail in Section 4.0.
The starting point for establishing the
bundled retail prices that will apply for the
duration of this agreement is the retail base
rates that became effective April 27, 1995
adjusted to capture 1995 surcharges. Prices
for distribution and transmission services
will be increased during years one through
three as described in Section 4.4.4, but
offset by an equivalent reduction in the CTC
to meet the overall price goals.
2.4.1.2 PRICE CAP FOR YEARS FOUR AND FIVE
Prices in years four and five can be
increased by an amount not to exceed 1% of
the all-in price except the commodity (e.g.
inclusive of transmission, distribution and
forecasted CTC charges) except for exclusions
noted below. Unless an increase is sought,
the Company is not required to file. Any
rate increases to transmission prices
approved by FERC that would be charged to
retail customers would count towards the
price cap increase.
The price cap excludes recovery of deferrals
established pursuant to the Settlement
Agreement and any generation sale incentive,
and variations in the MRA contract costs due
to the indexing provisions of the IPP
contracts. The Company will be allowed to
file for deferrals and generation sale
incentive recovery pursuant to Section 2.4.3,
without a filing for the price cap.
Beginning in year four, the Company will
adjust the CTC quarterly for changes in the,
IPP Indexed Contracts through the CAC as
described in Section 4.2.6. The Company
agrees to file the amended or restated
contracts with the Commission for their
review and approval of the indexing
provisions. The contracts shall be approved
as just and reasonable if the indexing
provisions are consistent with the terms and
conditions for amended and restated contracts
contained in Exhibit A of the MRA. In
particular, the indexing formula, when
calculated using the assumptions set forth in
Exhibit A, Attachment A-5 of the MRA, will
result in weighted average contract prices
that do not exceed the weighted average
contract prices that are contained in
Attachment A-3 to Exhibit A to the MRA, with
such weighted average contract prices being
subject to adjustment if one or more of the
SIPPs do not consummate the contracts
contemplated in the MRA.
2.4.2 REVENUES AND FINANCIAL FORECAST
The Company's projection of the financial impacts of
the MRA and this settlement agreement are presented in
Appendix C.
2.4.3 RATE ADJUSTMENT MECHANISMS
The projected prices are subject to change only as
specified in this Agreement. The parties have agreed
upon several specific mechanisms that could change
prices periodically. These mechanisms include:
- SYSTEMS BENEFITS CHARGE (SBC)
As described in Section 7.0, the SBC will be used to
collect the costs of public policy programs, to be
imposed on all distribution customers except as
otherwise provided herein. Spending for SBC-related
programs will be set at $15 million annually for years
one through three. That level of spending is included
within the pricing goals set forth in Tables 4-1 and 4-2.
Additional spending, if approved by the PSC, would
be collected through a surcharge to customers.
- NYPA RESIDENTIAL HYDROPOWER CREDIT
In accordance with contracts between NYPA and the
Company, residential customers are to receive the
actual benefits of NYPA hydropower. The procedure to
reflect actual benefits in residential prices is
described in Section 4.3.3.
- GENERATION SALE INCENTIVE
Section 3.2.2 describes the Company's incentive for
the sale of fossil and hydro assets. To collect this
incentive, the Company will include a surcharge in
years four and five. The surcharge will be limited, in
combination with the Company's proposal to recover
deferrals, to an amount equal to inflation less amounts
authorized under the price caps filing and deferral
recovery. Unamortized amounts of incentive remaining at
the end of year 5 will be amortized over a period not
to exceed 3 years. All customers who pay the CTC, or,
where applicable, exit fees, will pay the generation
incentive through a surcharge. Customers who do not
pay the CTC or exit fees, will not be obliged to pay
the generation incentive.
To the extent the sales price of the assets is
sufficiently in excess of book value to fund some or
all of the incentive, the Company will retain that cash
and the incentive surcharge will be reduced or
eliminated (book value includes related costs, such as
parts and fuel inventory, allocation of common facility
costs, etc.). To the extent there is a net book gain
(after auction costs and incentive) on the sale of the
assets, the net gain will be used to reduce stranded
costs for all customers that pay the CTC. To the
extent there are unrecovered costs remaining (i.e.,
stranded costs), these costs will be deferred for
recovery in year six over a period up to the remaining
life of the assets sold, as provided herein.
- RECOVERY OF DEFERRALS
The Company will file for recovery of deferrals from
years one through three, beginning in year four.
Deferrals will include those referred to herein. The
amount of amortization and recovery will be limited to
an amount equal to the rate of inflation less the
amount allowed under the price caps filing and
generation sale incentive recovery if any. The rate of
inflation will be the latest Blue Chip indicator
forecast of GDPPI at the time of the Commission
decision. New deferrals recorded in year four will be
factored into the year five deferral filing. Any
remaining unamortized deferrals at the end of year five
will be recovered over a period not to exceed five
years beginning in year six.
Deferrals will be collected through appropriate rate
mechanisms, depending upon the nature of the cost,
i.e., generation-related deferrals such as changes in
nuclear costs will be collected through a surcharge to
all customers who pay a CTC. Customers who do not pay
the CTC or exit fee will not be obliged to pay for
generation deferrals. Distribution-related deferrals
will be collected through a distribution surcharge.
When available, new deferred debits will be netted
against new deferred credits arising during the term of
this settlement agreement.
2.4.4 GROSS RECEIPTS TAX (GRT) REFORM
New York State enacted legislation in 1997 phasing in a
1% reduction of the State gross receipts tax by 2000.
Such reduction in the GRT, as realized, will be passed
through to customers as described in Section 4.1.4.
2.4.5 SECURITIZATION
Further rate reductions could be achieved if the State
of New York were to authorize "securitization" of
certain costs in a way that reduces the borrowing cost
of the Company. To the extent that it is not otherwise
prohibited by any legislation authorizing
securitization, the benefits of securitization should
be used to further reduce prices to SC1, 2, and 3
customers. The Company and Staff recommend that the
Commission consider allocating a portion of such
savings for energy efficiency and clean technology.
2.5 STRANDED COST RECOVERY
Niagara Mohawk will be entitled to recover
allowable stranded costs through a non-bypassable
Competitive Transition Charge (CTC) or, in some
circumstances, an exit fee. The details of the
CTC and the exit fee are contained in Section 4.0.
As described in Section 3.0, Niagara Mohawk will
have a reasonable opportunity to recover stranded
costs associated with its fossil and hydro units,
which will be quantified through auction and
divestiture.
Niagara Mohawk will have a reasonable opportunity
to recover stranded costs associated with its
nuclear generation during the term of this
agreement, as described in Section 3.0. Recovery
of stranded costs associated with retirement of a
nuclear unit during the term of this agreement is
subject to a separate Commission review process
described in Section 3.0.
As described in Section 2.3.2 above, Niagara
Mohawk will have a reasonable opportunity to
recover stranded costs associated with the MRA,
with the exception of the return on the regulatory
asset related to the MRA. During the term of this
agreement, Niagara Mohawk has limited its return
on the regulatory asset, resulting in a low
projected return on equity, as shown in Appendix
C. The projected foregone returns represent
Niagara Mohawk's share of stranded cost
responsibility during the term of this agreement.
2.6 DEFERRALS
2.6.1 COST CATEGORIES ELIGIBLE FOR DEFERRALS
Site Investigation and Remediation (SIR) costs are
eligible for true-up and deferral. In addition, the
following changes in forecast costs are eligible for
deferral: changes in laws, regulations, rules and
accounting that can be substantiated as increasing or
decreasing the cost of doing business (in excess of
$500,000 per change), and nuclear costs beyond
management's control (including decommissioning, the
Price Anderson Act covering nuclear accidents, fuel
storage, disposal of waste (exclusive of cost increases
unrelated to changes in laws, regulations, etc.),
significant NRC actions and other government agency
mandates and policy issues). Changes in regulations
will include financial consequences associated with a
final decision in Case 97-E-0251. In addition, some
gross revenue losses associated with the customer
service backout credit (See Section 5.0) will be
deferred. Any penalties accrued under the Customer
Service Quality Incentive (See Section 6.0) will be
deferred to offset cost deferrals.
The Company will be entitled to petition for deferral
and recovery of any other incremental costs not
specifically anticipated in the financial forecast and
not otherwise provided for in the first sentence of
this subparagraph, including incremental costs
associated with the Company's role as provider of last
resort as well as incremental business retention price
discounts as described in herein.
2.6.2 NEW YORK POWER AUTHORITY TRANSMISSION ACCESS
CHARGE (NTAC) DEFERRAL
The Company shall be entitled to defer annually the
actual NTAC costs up to a capped level reflecting the
total of (1) the actual amount of leveraged co-funding
and grants used for electric technologies, renewable
projects and marketing and promotions related to energy
efficiency or other projects qualifying for funding
under the SBC, and (2) the actual amount of Low Income
Customer Assistance Program (LICAP) program generated
arrears forgiveness.
2.6.3 TAX REFUNDS/PAYMENTS
The Company is subject to ongoing examinations by
federal and state tax authorities. No amounts have been
provided for in the financial forecast for resolution,
either resulting in a refund or liability, of these
examinations. To the extent that refunds or payments,
including interest and penalties and net of any
deferred taxes, individually exceed $500,000, the
Company will defer such refund or payment for
disposition in rates as set forth in Section 2.4.3.
2.6.4 ADDITIONAL IPP CONTRACT TERMINATION OR
RESTRUCTURING
There may be additional opportunities to restructure or
terminate IPP contracts not included in the current
MRA. With respect to any such opportunities that are
pure IPP buyouts, the Company will defer the up-front
costs and amortize those costs over a five year period
from the date of the buyout. The up-front costs will be
accounted for on an accrual basis (including instances
where the buyout payment is structured over a number of
years). The Company will retain the savings from the
buyout during the five year period of the PowerChoice
settlement. Unamortized costs and savings remaining at
the end of year five will be recovered or refunded in
subsequent rate proceedings subject to prudence review.
With respect to restructuring of additional IPP
contracts, the Company will submit to the Commission
for approval and rate treatment each proposed
restructuring, along with a calculation of the
anticipated savings on both a nominal and NPV basis.
The parties agree that the Company should be entitled
to a share of savings to provide as a meaningful
incentive to pursue restructuring. The sharing level
shall be determined by the Commission on a case by case
basis.
2.6.5 DISPOSITION OF EXISTING COST DEFERRALS NOT
YET REFLECTED IN RATES
2.6.5.1 GENERALLY
Deferred debits and credits existing as of the
PowerChoice Implementation Date shall be netted
against each other, and the net balance shall be
added/subtracted to/from any deferrals provided
for herein. Appendix E sets forth the accounts
and estimated balances to be netted.
The Company will discontinue true-up accounting
for electric unbilled services. Revenues recorded
by the Company in each year of this settlement
agreement will reflect both billed and unbilled
revenues of the period.
2.6.5.2. SITE INVESTIGATION AND REMEDIATION
PROGRAM
The Company has conducted a Site Investigation and
Remediation program (SIR) the purpose of which has
been to efficiently and effectively manage a
number of environmental clean-up activities over
an extended period of time. The principal
activities involve investigation and, where
necessary remediation and monitoring of
manufactured gas plant sites and industrial waste
sites. The Company expects to continue these
activities through the term of the settlement
agreement. Under previous electric and gas rate
orders, the Company has been permitted to defer
cost differences from amounts provided for in
rates. This treatment continues under the existing
gas rate settlement through 1999. The Company
will apply deferral accounting as described
herein, to cost differences from amounts provided
for in the financial forecast presented in
Appendix C and described below.
The amount the Company proposes to include in
rates has been affected by two recent events.
First, the Company entered into an amended Order
on Consent with the New York Department of
Environmental Conservation (NYDEC) on May 12, 1997
that provides for an annual "cost cap" of
approximately $15 million on expenditures by the
Company for 52 sites covered by the Order. The
cost cap is not an absolute limit on the Company's
annual or total spending on these sites, but
represents an understanding between the Company
and the NYDEC that it is in the best interests of
both parties to provide for efficient management
of the investigation and remediation process.
However, where the NYDEC or the Company believes
that public health and safety concerns warrant
accelerated expenditures, the cost cap will be
exceeded. Also, total annual expenditures may be
influenced by requirements at sites over which the
Company has little or no control (for example,
where the Company is a "potentially responsible
party"). The amended order also does not establish
the method of remediation, which may vary site-by-site,
creating uncertainty as to total required
expenditures.
The Company has also been actively pursuing
insurance recoveries for environmental remediation
activities. Through December 31, 1996, the Company
has reached settlements with a number of insurance
carriers, resulting in payments to the Company of
$49.8 million before costs incurred in pursuing
recoveries, which have amounted to $13.4 million.
The net proceeds have been deferred for
disposition in this settlement agreement. In
establishing an annual allowance for true-up, the
Company proposes to amortize the proceeds, net of
costs, over a ten year period. The resulting
annual electric net allowance is approximately
$10.2 million. The Company is continuing to pursue
additional recoveries, and to the extent that
additional proceeds are received by the Company
during the settlement period, these will be
deferred, net of costs and will be used to offset
SIR costs expected to be incurred in the years
beyond this settlement period.
The Company will apply the accounting and
ratemaking for certain net gains of property, the
sale of timber, etc. on such land and any related
land/mining lease revenues as set forth in Section
III, A. of the Gas Stipulation and Agreement in
Case 95-G-1095 and 95-G-0091. The Company will be
permitted to conform prospectively the accounting
for the electric allocable portion of the proceeds
to the outcome of any gas proceeding during the
first three years of this settlement, or propose
different treatment as part of a price caps filing
for year four.
2.7 SFAS NO. 71 APPLICABILITY
The Company supports this settlement agreement in
part because the agreement is consistent with the
principles of SFAS No. 71. The parties agree
that during the terms of this settlement, the
Company should be regulated in a way that would
allow it to continue the principles of SFAS No. 71
to its regulated operations (RegCo). The parties
further agree that any material change in the
allocation of risk as set forth in this settlement
agreement, whether made during the approval
process or during the term of the settlement
agreement, could jeopardize the application of
SFAS No. 71, as well as the financial
stabilization and recovery of the Company.
It is the intent of the Parties, and the
Commission by virtue of its approval of this
Agreement, that the Agreement meets the accounting
requirements of Statement of Financial Accounting
Standards No. 71, throughout its term.
2.8 RATE FILING FOR PERIOD AFTER TERM OF THIS AGREEMENT
The Company will be permitted to file a rate case for
rates to be effective beginning immediately after the
conclusion of the fifth year of this settlement
agreement. If the Company elects not to file a rate
case, unbundled prices (exclusive of surcharges
described herein) would remain unchanged.
SECTION 3.0
NIAGARA MOHAWK GENERATION
3.1 INTRODUCTION AND SUMMARY
3.1.1 GENERATION OWNED BY NIAGARA MOHAWK
Niagara Mohawk has agreed to divest all fossil and
hydro generation as described below. Until such
divestiture is completed, the company will functionally
separate its fossil and hydro generation from its
regulated activities. Divestiture will be accomplished
either by an auction process or, if acceptable bids are
not received, by creating a legally separate generation
company as described herein.
Nuclear generation will remain part of RegCo, but will
stay in a business unit functionally separate from
RegCo's transmission and distribution and gas
businesses. It will be subject to further study and
disposition as described in Section 3.3 infra.
The rate treatment of generation owned by Niagara
Mohawk is governed by the provisions of the Rate Plan
described herein. However, for internal accounting
purposes, and to define the generation component of
unbundled prices, RegCo will enter into certain
transition "contracts" with its fossil and hydro
businesses and its nuclear business unit governing
quantities and prices for fossil/hydro and nuclear
generation, respectively. These "contracts" are
designed to achieve the rates to which Niagara Mohawk
is committed under this agreement. The fossil/hydro
contracts have an initial term of 3 years, and the
Company has agreed to explore an additional 2 years
through the auction design. The nuclear "contracts"
have 5 year terms, consistent with the term of this
settlement.
When the fossil and hydro units are sold or spun to
separate entities, the RegCo contracts will be sold
with them. In that event, the contracts may govern the
purchase of energy by RegCo from these independently
owned generators for the remainder of the 3, or, if
extended, 5-year term of the contracts (). After that
point in time, the parties anticipate that the new
owners of the former NMPC generating units will sell
their output at market prices, either into a spot
market or under bilateral contracts. They will have no
remaining contract with or obligation to RegCo for the
sale of energy or capacity.
Niagara Mohawk will define the terms and conditions of
a two year extension in the fossil/hydro contract as
part of the auction plan, which is subject to separate
PSC approval. If the PSC determines that the 2-year
extension is appropriate, then the net auction proceeds
and CTC will reflect the incremental/decremental value
of the contract extension.
As the generation transition contracts expire or are
terminated, and if a nuclear plant is retired, the
energy subject to them will become unhedged. The
market prices of unhedged energy will be flowed through
directly to customers, unless otherwise specified
herein (See Section 4.0).
3.1.2 GENERATION PURCHASED FROM IPPS
Contracts with IPPs who are not parties to the MRA
shall continue in force and effect, subject to their
own terms, except that Niagara Mohawk shall continue to
pursue opportunities to restructure, auction, or buy
out the IPP contracts. Rate treatment for such
additional restructuring or buyouts is discussed in
Section 2.6.4 herein.
Purchases of generation IPPs who are parties to the MRA
will be governed by the MRA and contracts executed
pursuant to the MRA.
Some IPPs who are signatories to the MRA shall have
their contracts terminated as a consequence. These
IPPs will have discretion to sell their output to
others, to sell to Niagara Mohawk at market prices, or
to close their operations, among other options. Other
IPPs who are signatories to the MRA shall have their
contracts restated or amended as described therein.
3.2 GUIDING PRINCIPLES FOR FOSSIL/HYDRO GENERATION AUCTION
3.2.1 AGREEMENT TO DIVEST FOSSIL/HYDRO GENERATION
DIVESTITURE
Niagara Mohawk will commit to hold a broad-based
auction of its non-nuclear generation assets (the
auction) and at its discretion may include some IPP
Power Purchase Agreements (inclusion of the IPP
contracts will be consistent with contractual rights or
consent of the IPPs). Any hydro projects that are part
of a nuclear license and any wind and solar generation
projects described elsewhere in this agreement will be
excluded from the auction and divestiture.
After the auction and/or spinoff transactions described
herein are complete, Niagara Mohawk and its
subsidiaries agree not to own any generation assets in
New York State, with the exception of any
sale/leaseback transactions and reorganizations
necessary to close the MRA and except as otherwise
provided for in this agreement. In the case of a
reorganization transaction pursuant to the MRA, NMPC
will either lease any project facilities acquired in
the reorganization to a third party operator, or enter
into a management and services contract with such a
third party approved by the PSC, or operate the
facility itself but only for the purpose of generating
a source, or a backup source, of supply for its own use
and not for re-sale. In addition, neither HoldCo nor
RegCo will own any generation assets inside or outside
of New York, except as otherwise provided for in this
agreement. However, any other affiliate of HoldCo is
not restricted in any way by this agreement from owning
generation assets outside New York.
Because the PSC will review merger applications under
the Public Service Law, nothing in this agreement will
limit the Company's ability to merge with or be
acquired by another entity owning generation.
Moreover, nothing in this agreement will limit the
Company's ability to form partnerships or affiliations
with entities who own generation in New York State,
provided that those partnerships or affiliations do not
involve ownership of generation assets. An unregulated
affiliate of HoldCo may enter into arms length
contracts with an entity owning generation in New York
State.
The sale/leaseback transactions, reorganizations,
partnerships and affiliations and arms-length contracts
referred to above are all subject to the restriction
that they must not create a conflict between the
interests of RegCo ratepayers and Company stockholders
by tying the profitability of the Company to the
profitability of the entity's generation business.
Any material violation of the above restrictions may
result in, inter alia, an affiliate being prohibited
from further transacting business with end users within
the RegCo service territory or divestiture of the
affiliate, provided, however, that the Company shall be
given the opportunity to explain why a violation has
not occurred and to remedy any such alleged violation
in accordance with the procedures outlined in Section
9.3.9 regarding Corporate Structure and Affiliate
Transactions.
AUCTION
Niagara Mohawk commits to file a detailed auction plan
within 30 days of the PSC Order approving the
PowerChoice Settlement Agreement. The detailed auction
plan will undergo Commission review, with an
opportunity for comment by other parties, and approval.
Winning bidders in the auction will be selected within
11 months of plan approval. Niagara Mohawk will use
its best efforts to transfer title within 9 months of
the selection of winning bidders, contingent on Niagara
Mohawk and the buyer(s) receiving all necessary
regulatory approvals to effectuate the transaction(s).
The auction process will include a screening stage to
establish minimum standards for qualified bidders, and
one or more bidding stages. The auction features may
include the sale of the portfolio in its entirety, in
any combination, or as individual plants or sites.
(Likely sub-groupings are: (a) coal plants, (b) Albany,
(c) Oswego, (d) 1-3 hydro plant combinations, (e) other
generation, and (f) any IPP contracts included in the
auction). After completion of the transactions
resulting from the auction process as described herein,
no fossil or hydro assets included in the auction and
receiving positive bids will remain part of Niagara
Mohawk.
Niagara Mohawk retains the right to reject the
following types of bids for any asset or group of
assets:
(1) ANY BIDS THAT ARE LESS THAN ZERO:. The rejected
bid will cap the level of mitigated stranded costs
for assets whose bids were rejected. The assets
whose bids are rejected will remain part of RegCo.
(2) BIDS THAT ARE GREATER THAN ZERO THAT ARE DEEMED
TOO LOW: Niagara Mohawk reserves the right to
reject any and all bids that it deems too low. If
it rejects all bids for an asset or group of
assets, then it commits to form a subsidiary
consisting of the assets with non-negative bids,
and spin the assets to a legally separate
generating company. The greater of the rejected
bid(s) or the average trading value of the stock
of the spun entity for the 30 trading days after
the stock is publicly traded, will determine the
market value of the assets for the purpose of
mitigating stranded costs. Nothing in this
agreement precludes the Commission from ordering
an alternative to the rejected bid approach in its
review and approval of the Company's auction plan.
To the extent that the IPP contracts are grouped
with other generation assets, Niagara Mohawk
waives its right to reject the bids for that
group.
3.2.2 NON-NUCLEAR GENERATION SALE INCENTIVE
Niagara Mohawk will receive an incentive based on the
net proceeds (gross sales price less auction costs
(external third party costs)) of the auction as an
incentive to obtain the maximum value in the sale of
its generation assets, and to offset in part the
stranded costs being absorbed by its shareholders as
part of this settlement. The incentive will be
recovered as described in Section 2.4.3. Niagara
Mohawk will have the right to use the incentive in any
manner it sees fit so long as it is consistent with
this agreement. The incentive will not apply to bids
rejected as described above.
The incentive will be calculated as follows:
(a) For all fossil/hydro assets sold, except for the
Oswego Steam Station, the Company will receive an
incentive equal to the following percentage of net
auction proceeds:
- 0% of the proceeds between 0 and $250 million
- 12% of the proceeds between $250 and $500
million
- 18% of the proceeds between $500 and $750
million
- 10% of the proceeds above $750 million
(b) For the Oswego Steam Station:
The Company will receive an incentive equal to the
following percentage of net auction proceeds:
- 0% of the proceeds between $0 and $100
million
- 5% of the proceeds above $100 million
3.2.3 LABOR ISSUES ASSOCIATED WITH DIVESTITURE
3.2.3.1 Labor Contract Issues
The parties recognize that the Company and the
IBEW Local 97, AFL-CIO, are bound by a collective
bargaining agreement effective March 1, 1996
through May 31, 2001, which includes a provision
at Article II entitled "Territory." Article II
provides that:
1. The territory covered by this agreement
shall include all the franchise
territory of the Company.
2. This agreement shall bind the
successors of the Company by merger
or consolidation as to the
provisions and territory covered by
this agreement. For the purpose of
preserving and protecting work
opportunities and job security for
the bargaining unit, it is agreed
that:
a. An absolute
precondition to the
sale, lease,
transfer, or
takeover by sale,
transfer, lease,
assignment,
corporate
reorganization,
receivership, or
bankruptcy
proceeding of the
entire operation or
any part thereof is
that any purchaser,
transferee, lessee,
assignee, etc. shall
agree and become
party to and bound
by all the terms,
conditions, and
obligations of this
agreement.
b. Any increased or
additional work of
a continuing or
permanent nature
performed at or in
conjunction with
the Company's
existing facilities
or from a transfer
of work occasioned
by the closing or
partial closing of
an operation
previously covered
by this agreement
shall be deemed
bargaining unit
work and shall be
fully covered by
the terms,
conditions, and
obligations of this
agreement.
(a) Nothing in this Settlement Agreement
adds to, subtracts from, or otherwise
modifies any rights, duties, or
obligations set forth in that collective
bargaining agreement, except as
otherwise indicated below.
(b) The Company agrees to provide a
copy of the collective bargaining
agreement to any party that
indicates an interest to bid in any
auction of the Company's generation
assets.
3.2.3.2 Retraining and Severance Costs
The auction of generation assets could have an
impact on Company employees. To address this
prospect, up to $10 million of incremental
retraining costs and severance payment, out
placement, voluntary early retirement program and
related costs, if any, incurred in 1999-2002 will
be provided for and deferred by the Company for
later recovery. These activities are limited to
direct consequences of the disposition of
fossil/hydro generation assets, including the
bumping process as set forth in the collective
bargaining agreement. Although the deferral is
not defined in reference to specific levels of
management or represented employees, it is the
understanding of the parties that approximately
75% of the existing employees in fossil/hydro
generation are covered by the collective
bargaining agreement. The actual costs incurred,
up to the $10 million cap, will be paid for
through a reduction in the net proceeds of the
auction that will determine stranded costs to be
recovered.
3.2.4 UNHEDGED ENERGY AND THE CTC FOR FOSSIL/HYDRO ASSETS
The net sales proceeds less the incentive will be used
to retire the capital structure. Consummation of the
sale pursuant to an approved auction will establish the
level of stranded cost recovery for the assets sold.
Niagara Mohawk will be entitled to a reasonable
opportunity to collect, in the CTC, or where
applicable, exit fees, all remaining stranded costs
from the non-nuclear assets sold in the auction.
When the fossil/hydro assets are sold or spun, and when
RegCo's contract with the fossil/hydro assets expires,
the quantity of energy that was previously purchased
from those assets will become unhedged. The
contribution to the CTC associated with the
fossil/hydro assets will become a fixed amount
reflecting the difference between the book cost of the
assets and the market proceeds received for them (as
adjusted, when applicable, for the generation auction
incentive and for retraining and severance costs). The
risk associated with the market price of the unhedged
energy will be shifted to customers except as otherwise
provided herein.
3.3 GUIDING PRINCIPLES FOR NUCLEAR ASSETS
3.3.1 STUDY TO DETERMINE FUTURE DISPOSITION
The nuclear assets held by Niagara Mohawk will remain
part of RegCo as a separate business unit until they
are either transferred or divested.
Niagara Mohawk will continue to pursue Statewide
solutions for its nuclear assets through discussions in
formation of NYNOC and in any generic proceedings
established by the Commission. Statewide solutions for
nuclear plants will be explored before other potential
solutions.
The proposed solutions for Niagara Mohawk's nuclear
plants are contingent on the following:
- treatment of the nuclear plants meets all
requirements of the NRC, and
- there is consistent regulatory treatment for sale
and cost recovery for all the co-tenants of NMP2.
Absent a Statewide solution, Niagara Mohawk commits to
file a detailed plan, analyzing the proposed solutions
for its nuclear assets, within 24 months of this
Settlement Agreement. The plan will consider the
feasibility of auction, transfer, and/or divestiture of
Niagara Mohawk's nuclear assets. The detailed plan
will undergo an appropriate level of Commission review
and approval to be concluded on an expedited basis.
3.3.2 RECOVERY OF STRANDED COSTS
Subject to price-cap considerations discussed herein,
nuclear will remain subject to cost-based regulation
including a rate of return for the five year term of
this agreement or until the nuclear plants are divested
or another statewide solution is developed.
- RegCo will be allowed annual deferrals during the
term of this settlement for changes in costs for
categories which are beyond management's control
as described in Section 2.6.1.
- Customers will not be allowed to negotiate one
time buyouts for all nuclear costs.
Subject to other provisions in this settlement,
sunk capital costs, fuel inventory, and material
and supplies inventory, and all decommissioning
and shutdown costs (including O&M rampdown,
property taxes and insurance, and fuel and low
level waste storage and disposal) are considered
to be unavoidable. To the extent that such cost
levels are deemed prudent, they will be recovered
through a non by-passable competitive transition
charge.
Accordingly, Niagara Mohawk will be entitled to a
reasonable opportunity to recover all nuclear sunk
and decommissioning costs allocable to the five-year
period of the settlement agreement (as
described in Sections 3.3.3, 3.3.4 and 3.4.3)
through the CTC or, where applicable, exit fees,
during the five-year term of this agreement. If
the assets are divested within the term of this
agreement, Niagara Mohawk will be allowed to
recover the full decommissioning costs and the
return of and on the nuclear assets less the
market value received in divestiture through the
CTC or, where applicable, exit fees.
3.3.3 COST TREATMENT IF A NUCLEAR PLANT IS SOLD,
TRANSFERRED OR DIVESTED
As part of its plan analyzing the feasibility of
auction, transfer or divestiture of its nuclear plants
(see Sec. 3.3.1), the Company will propose treatment
for recovery of any remaining stranded costs consistent
with the intent that (a) unhedged commodity risk be
shifted to customers, and (b) that the CTC reflect
revised nuclear costs for the Company (including
recovery of sunk costs net of sale proceeds) and any
remaining cost obligations that stay with the company
such as decommissioning costs.
3.3.4 COST TREATMENT IN THE EVENT OF A PLANT
RETIREMENT
If Niagara Mohawk decides to retire or abandon a plant
before a sale or auction, then it agrees to file an
economic study with the Commission that justifies the
decision. The Commission will review the study on an
expedited basis, and determine the prudence of the
retirement decision before the plant is retired or
abandoned.
If the Company retires a nuclear plant, the following
will apply:
- Until the Company announces its intent to retire a
plant, it will be responsible for replacement
power costs as outlined in Sec. 3.4.3.
- On the date that the Company announces that it
plans to retire the plant, if the plant is not
then operating, the Company will begin passing
through to customers (through the Commodity
Adjustment Charge) the difference between the spot
market price of energy and the nuclear plant's
avoided fuel costs. Such passthrough will be in
the form of temporary rates, subject to refund, as
described below. On that same date, the
difference between the level of nuclear O&M and
decommissioning costs embedded in rates and the
actual level of O&M and decommissioning costs
incurred will be deferred on a monthly basis for
later recovery. In any month in which such
deferral shows a net credit and the spot market
price exceeds the plant's avoided costs, the
credit will be used to offset the passthrough. In
the event the plant is operating when the Company
announces its plans to retire the plant, the
passthrough described above will commence on the
date the plant is permanently shut down.
- The Company will prepare and file with the
Commission a study assessing the economics of
continued operation versus retirement, and
explaining why it believes a retirement is prudent
and in the ratepayers' interests. The study will
include a proposal to account for, defer and
recover estimated remaining unfunded
decommissioning costs. The costs passed through
to customers above will be subject to refund or
adjustment, pending the Commission's finding that
the retirement was prudent and that the cost
impacts are justified.
- Upon PSC approval of the retirement decision, the
CTC (competitive transition charge) for the
nuclear plant will be recalculated consistent with
the intent (a) that unhedged commodity risk be
shifted to certain customers, and (b) that the CTC
reflect revised nuclear costs (sunk costs and
decommissioning costs (including rampdown and
shutdown costs), and reduced operation and
maintenance costs (including fuel cost savings).)
The PSC approval will also address the amortization
(in excess of $500,000 per change) schedule of any
deferral balance as created in Section 2.6.1.
In the event of a nuclear plant retirement,
replacement power costs (RPC); defined herein as
the difference between the cost of commodity
purchased at market prices and the cost of nuclear
fuel, offset by any operations and maintenance
cost reductions, should be flowed through to all
customers that pay CTCs. It is the intent of the
parties that cost deviations resulting solely from
variations between actual and forecast market
prices be flowed through only to customers with
floating CTCs. The RPCs for customers with fixed
CTC's will be determined based on forecasted
rather than actual market prices. The forecast
market prices used for this purpose will be based
on the option chosen by the customers pursuant to
Section 4.2. Forecast RPCs, offset by O & M
savings in years 1 through 3, for SC 3A customers,
will be deferred for recovery from SC 3A customers
in year 4 and beyond, subject to the price caps
set forth herein.
3.4 TRANSITION CONTRACTS WITH GENERATORS
3.4.1 DESIGN FEATURES COMMON TO ALL GENERATORS
3.4.1.1 Transition Contract Overview
The transition contracts utilize financial
contract structures (financial swaps -
Contracts-For-Differences (CFDs) and financial call options
- swaptions) to allow the collection of strandable
costs for a fixed time period, while requiring
generators to participate in the market.
The fossil/hydro and nuclear contracts operate
only as interval accounting devices within Niagara
Mohawk until such assets are divested.
Details concerning financial contracts, including
a general description of the primary design
components and the general structure of the
financial contracts are provided in Appendix F and
subsequent sections of this document.
3.4.1.2 Primary Design Components
Financial contracts have three primary design
components: contract price, contract quantity, and
contract term.
- The contract prices were developed using the
forecasted costs. Contracts will have a two
part pricing design that includes a fixed
cost charge and a volumetric price. For the
swaptions, the fixed cost charge will become
the reservation fee in the contract.
- The contract quantities have been developed
primarily through the use of forecasted
generator output to serve existing Niagara
Mohawk retail load in Promod. Generator
loads are metered at the generator busbar.
- The term for the financial contracts have
been established based on the contract price,
contract quantity, and total strandable costs
to be collected. Financial contracts that
have been negotiated between RegCo and
generators will begin on the date that the
existing Power Purchase Agreements of
Settling IPPs are terminated.
The general structure of financial swaps and
swaptions is described in Appendix F.
3.4.2 NMPC FOSSIL AND HYDRO GENERATION TRANSITION
CONTRACT(S)
There will be separate financial swaption contracts for
each Niagara Mohawk fossil unit. The contracts are
established based on the forecasted revenue for fossil
and hydro generation that fit within Niagara Mohawk's
retail price commitments. The forecast of energy
output to serve retail load serves as the basis for the
contract quantity of the transition contracts. Tables
3-1a and 3-1b contain the aggregate annual contract
quantities and contract prices and revenues for fossil
and hydro.
The contract quantity for hydro generation will be
adjusted annually to reflect variations in actual water
flow. The expected output less 650 GWH (i.e., 2299
GWH) has a variable price of zero. The actual output
less 2299 GWH is priced at the variable price described
in Table 3-1b. The forecast of wholesale sales margins
has been imputed as a credit against the generation
fixed payment in the transition contract for each
fossil unit.
Three-year transition contracts were developed for
Niagara Mohawk fossil and hydro assets, which will
begin on the PowerChoice implementation date. Niagara
Mohawk will evaluate the cost/benefit of extending the
transition contracts for two additional years in the
auction process.
The quantity available under the swaption will be
limited to the capacity of generation assets sold or
spun (adjusted for availability, maintenance outages
and unit minimums, response rates and cycling
limitations, etc. ).
Niagara Mohawk's fossil and hydro generation and the
transmission and distribution facilities were designed
and constructed as integrated facilities with
interdependent control and protection functions.
Niagara Mohawk will prepare a separation agreement,
prior to implementation of the contracts, which
describes points of demarcation and any shared services
agreements between RegCo and the entity purchasing
generation.
TABLE 3-1a FOSSIL CONTRACT QUANTITIES, CONTRACT PRICES, AND
REVENUE
Variable Annual
Contract Contract Fixed Retail Total
Quantity Price (A) Payment Revenue (B) Revenue (C)
(GWH) ($/MWH) ($ million)($ million)($ million)
-----------------------------------------------------------
1998 3,532 $14.90 $139.6 $192.2 $291.3
1999 3,562 $14.62 $137.8 $189.9 $282.1
2000 3,175 $13.44 $117.2 $159.9 $273.7
(A) Will vary by unit.
(B) Retail revenues are the sum of (1) contractual payments
by RegCo to the generators under the contract, and (2)
revenues received by the generators for physical sales
into the spot market for the contract quantities.
(C) Total revenues are retail revenues plus imputed
wholesale market revenues.
TABLE 3-1b HYDRO CONTRACT QUANTITIES, CONTRACT PRICES, AND
REVENUE
Variable Annual
Contract Contract Fixed Retail
Quantity Price (A) Payment Revenue (B)
(GWH) ($/MWH) ($ million) ($ million)
----------------------------------------------------
1998 2,949 $10 $62.4 $68.9
1999 2,949 $10 $58.9 $65.4
2000 2,949 $10 $60.6 $67.1
(A) Applies to 650 GWH
(B) Retail revenues are the sum of (1) contractual payments
by RegCo to the generators under the contract, and (2)
revenues received by the generators for physical sales
into the spot market for the contract quantities.
3.4.3 NUCLEAR GENERATION TRANSITION CONTRACTS
For the five year term of this agreement Niagara
Mohawk will have a transition contract (financial swap)
for each of its nuclear plants reflecting its forecast
level of going forward costs. This forecast will be
updated for years four and five as part of the rate
filing. Niagara Mohawk will terminate the transition
contract if it retires a unit during the term of the
contract, and the energy associated with the retired
unit will become unhedged.
All forecast costs to operate the nuclear units are
included within the rate goals in Tables 4-1 and 4-2.
After the initial five year period, RegCo will make a
filing to the Commission for continued transition cost
recovery treatment for the nuclear units.
The contract quantities, contract prices, and revenues
for each unit are shown in the Tables 3-2a and 3-2b.
TABLE 3-2a NM1 CONTRACT QUANTITIES, CONTRACT PRICE, AND
REVENUE
Variable Annual
Contract Contract Fixed
Quantity Price Payment Revenue
(GWH) ($/MWH) ($1,000) ($1,000)
----------------------------------------------------
1998 4,564 $5.46 $235,084 $260,003
1999 4,027 $4.79 $239,240 $258,529
2000 4,577 $4.71 $233,994 $255,552
2001 4,027 $4.73 $247,175 $266,223
2002 4,564 $4.72 $243,818 $265,360
TABLE 3-2b NM2 CONTRACT QUANTITIES,PRICE AND REVENUE
Variable Annual
Contract Contract Fixed
Quantity Price Payment Revenue
(GWH) ($/MWH) ($1,000) ($1,000)
----------------------------------------------------
1998 3,079 $4.65 $231,124 $245,441
1999 3,489 $4.87 $240,721 $257,712
2000 3,087 $4.57 $239,839 $253,947
2001 3,489 $4.73 $239,038 $255,541
2002 3,079 $4.58 $244,072 $258,174
Note: Year to year variations are due to refueling and
scheduled outages.
3.4.4 SETTLING INDEPENDENT POWER PRODUCERS (SIPPS)
A detailed description of the contracts for the
Settling IPPs is included as Exhibit A of the Master
Restructuring Agreement in Appendix A. An outline of
the negotiated schedule of aggregate contract
quantities, weighted average contract prices, and
contract term are contained in Table 3-3. Variations
in contract costs due to the indexing provisions of the
contracts will be passed through to customers after
year three, subject to the provisions described
herein. The form of the individual contracts remain
to be negotiated between Niagara Mohawk and the IPPs.
The dominant type of contracts will be financial swaps
and swaptions. However, there will be some physical
bilateral contracts between Niagara Mohawk and some of
the IPPs.
TABLE 3-3 SETTLING IPP CONTRACT QUANTITIES, CONTRACT PRICE, AND
REVENUE
Contract Contract Total
Quantity Price Revenue
(GWH) ($/MWH) ($1,000)
--------------------------------------------
1998 4,993 $45.13 $225,357
1999 4,993 $45.56 $227,484
2000 5,043 $42.91 $216,399
2001 5,083 $44.90 $228,215
2002 5,089 $46.17 $234,965
2003 7,108 $50.18 $356,645
2004 8,118 $52.60 $427,012
2005 9,131 $54.51 $497,760
2006 9,139 $56.93 $520,238
2007 9,151 $60.24 $551,219
2008 8,353 $60.99 $509,440
2009 8,353 $61.11 $510,424
2010 353 $40.70 $ 14,367
2011 353 $41.90 $ 14,791
2012 353 $43.20 $ 15,250
2013 353 $44.50 $ 15,709
2014 176 $45.84 $ 8,068
3.5 OTHER INDEPENDENT POWER PRODUCERS (IPPs)
Table 3-4 shows the current forecast of payments to the
109 IPP contracts that are not part of the buyout
group. The contract quantities and prices represent
the forecasted amounts in the existing Power Purchase
Agreements (PPAs). RegCo will update the level of
transition cost recovery for approximately 109 IPP PPAs
in the rate filing adjusting for rates in years four
and five of this Agreement consistent with Section
2.6.4 of this Agreement. The forecast contract
quantities, contract prices, and revenues in aggregate
are shown in the Table 3-4.
TABLE 3-4 OTHER IPP CONTRACT QUANTITIES, CONTRACT PRICE,
AND REVENUE
Total
Contract Contract Total
Quantity Price Revenue
(GWH) ($/MWH) ($1,000)
--------------------------------------------
1998 3,839 $64 $246,530
1999 3,839 $66 $255,059
2000 3,839 $68 $261,913
2001 3,839 $64 $246,207
2002 3,839 $64 $247,255
SECTION 4.0
ELECTRIC PRICES
4.1 OVERVIEW OF BUNDLED AND UNBUNDLED PRICES
In accordance with the schedule contained in Section 8,
over the life of this agreement all Niagara Mohawk
customers will come to have the option of selecting
their own energy supplier.
Services and prices will be unbundled for all customers
who have the option of choosing their own retail
supplier even if they elect to continue taking energy
service from Niagara Mohawk. The unbundling of
services and prices will make available to customers
who are eligible for retail access cost information for
generation, transmission, customer service and
distribution services.
An essential predicate for unbundling is the
establishment of a Competitive Transition Charge (CTC).
Both the bundled and unbundled prices called for under
this Agreement will be implemented through the filing
of tariffs with the appropriate regulatory agencies.
The Company will continue to work with the parties and
resolve any outstanding issues so as to file unbundled
prices on a minimum of 30 days prior to the PowerChoice
Implementation date.
4.1.1 BUNDLED PRICES
Appendix D () sets forth the proposed prices for the
major service classifications for the term of this
agreement and shall become effective on the PowerChoice
Implementation Date.
4.1.1.1 RESIDENTIAL AND COMMERCIAL CLASS
PRICE LEVELS
Table 4-1 summarizes the projected class-average prices
for Service Classifications 1,
2 and 3, including the effects of the System
Benefits Charge and currently planned gross
receipts tax reductions. The Company expects
that 1997 prices will generally be consistent
with 1995 prices. If 1997 results vary, the
percentage reductions may change but the
price levels will not.
TABLE 4-1 AVERAGE ELECTRICITY PRICES FOR THE YEARS 1998-2000 BY CUSTOMER CLASS (C)
1997 (A) 1998 1999 2000
-------- ---- ---- ----
SC1 Cents/KWh 12.724 12.623 12.503 12.286
% Change (B) -0.79% -1.74% -3.44%
SC1B Cents/KWh 8.557 8.557 8.557 8.557
% Change 0.00% 0.00% 0.00%
SC1C Cents/KWh 9.628 9.626 9.626 9.626
% Change -0.02% -0.02% -0.02%
SC2ND Cents/KWh 16.492 16.37 16.224 15.968
% Change -0.74% -1.63% -3.18%
SC2D Cents/KWh 11.945 11.853 11.747 11.562
% Change -0.77% -1.66% -3.21%
SC3 Cents/KWh 10.43 10.222 10.198 10.103
% Change -1.99% -2.22% -3.14%
(A) Based on 1995 Freeze Prices applied to Company's 1997 Sales Forecast.
(B) Percentage reductions are as calculated based on 1997 projected prices.
Actual percentage reductions may vary based on actual 1997 results.
(C) Inclusive of SBC and GRT.
4.1.1.2 INDUSTRIAL AND LARGE COMMERCIAL
PRICE LEVELS
Table 4-2 summarizes the Company's estimates
of the individual class rate levels that
would result from this settlement including
the effects of the System Benefits Charge and
currently enacted gross receipts tax
reductions.
Table 4-2
Average Electricity Prices for the SC3A / SC4(>2MW) / EDP Programs/SC11
RATE 1997 1998 1999 2000 % CHANGE
CLASS CENTS/KWH (A) CENTS/KWH CENTS/KWH CENTS/KWH FROM 1997
----- ------------ --------- --------- --------- ---------
SC3A/SC4/
ERIR/EDR 7.98 5.99 -24.95%
Special
Contracts 7.84 5.77 -26.40%
Economic De-
velopment 7.99 3.00 -62.44%
TOTAL
CLASS (B) 7.93 6.28 6.0 5.84 -26.38%
(A) Values are full tariff based on 1995 Freeze Prices and Company's Hours Use Rate
Design applied to Actual 1996 Billing Data
(B) Individual customer reductions may vary from the class average. Includes SBC
and GRT
By the year 2000, Niagara Mohawk will supply and
deliver power to larger commercial and industrial
customers (S.C. No. 3A, large S.C. No. 4 and S.C.
No. 11) at a forecasted class weighted average
price (including ERIR, EDR and EDZR discounts) of
approximately $0.0585 per KWh (based on current
load and price forecasts) inclusive of all
currently enacted New York State gross receipts
tax reductions. If the currently enacted gross
receipts tax reductions are repealed, these prices
will increase accordingly.
The company has allocated certain funds ($17.1
million in 1998, $17.8 million in 1999 and $18.3
million in 2000) to incremental, uncommitted S.C.
No. 11 and EDZR/EDR/ERIR discounts as a means of
achieving its price goals. These funds are in
addition to those funds necessary to develop the
phase in plan for existing EDZR customers as
described in Section 4.12. To the extent that the
price goals are not met and these incremental
uncommitted discounts are not ultimately issued,
the company shall flow back either the unused
discounts or an amount necessary to achieve the
price goals, whichever is less, to S.C. No. 3A
customers. Should implementation of this
provision become necessary, it will be
accomplished via a one time pass-back initiated
during the 12-month period immediately following
year three of this agreement.
Comparisons between annual price goals and actual
billing experience shall be recorded following
each of the first three years of this agreement,
with carrying charges applied to the equivalent
revenue discrepancies (plus or minus) in deriving
an accumulated three year net discrepancy. The
net revenue discrepancy so determined will be
compared to the remaining uncommitted incremental
discounts (as may exist). To the extent that the
price goals are not met, the lesser of these two
quantities shall become the amount to be passed
back to S.C. No. 3A customers. The level of year
4 and 5 uncommitted incremental discounts will be
determined in the proceeding setting rates for
years 4 and 5, but in no event will the Company
propose or recommend uncommitted incremental
discount levels for years 4 and 5 less than the
level of any excess uncommitted incremental
discounts so determined after year 3. Should the
Company forecast that actual incremental discounts
will exceed the incremental uncommitted discount
funds discussed above, the Company will notify the
Parties, and the Company or any Party will have
the right to petition the Commission for
ratemaking treatment to fund additional discounts
that may be needed for business retention and
revitalization purposes.
4.1.2. METHODOLOGY FOR ARRIVING AT BUNDLED PRICES
4.1.2.1. CALCULATION OF "BASE" 1997 RATES BEFORE
DECREASES
The starting point for establishing the bundled
retail prices that will apply for the duration of
this agreement is the retail base rates that
became effective April 27, 1995 adjusted to
capture surcharges. To capture the effect of
external surcharge mechanisms that were in effect
at that time, Niagara Mohawk rolled into base
rates all surcharge balances that existed as of
December 31, 1995. Surcharges applied
volumetrically (e.g., FAC, DIRAM, IPP buyouts and
fuel amortization) were translated into annual
rates per KWh and added to the energy components
of base rates; surcharges applied on a net base
rate revenue basis (e.g., NERAM, MERIT, Regulatory
Deferral and Extension of Suspension) were
translated into class specific factors and applied
to the net base rate revenue components of base
rates. The resulting prices, when applied to an
individual customer's 1995 usage, would produce
the same electric bill amounts as would be
produced by the application of base rates and
individual surcharges factors. The adjusted
prices were applied to 1997 sales to produce 1997
revenues and 1997 class-average prices.
4.1.2.2. APPLICATION OF PERCENTAGE DECREASES FOR
SC 1, 2, & 3
Given the class-average prices developed above,
the price reductions were implemented for
residential (S.C. No. 1), small commercial (S.C.
No. 2, and S.C. 2 Demand (S.C. 2D)) customers
using the following five-step procedure:
(1) The Company will reduce prices for these
customers by approximately 2.2% over three
years following the effective date of tariffs
implementing the Settlement Agreement prices
(the "PowerChoice" Implementation Date) ().
(2) Class-Average 1997 prices were multiplied by
projected 1998 sales to estimate 1998
revenues and class-average prices under the
preceding year's rates. These average rates
were reduced by approximately 0.7% to get
1998 class-average prices.
(3) Class-average 1998 prices were multiplied by
the forecast sales for 1999 to estimate 1999
revenues and class-average prices under the
preceding year's rates. These average rates
were reduced by approximately 0.7% again to
derive 1999 class-average prices.
(4) Class average 1999 prices were multiplied by
the forecast sales for 2000 to estimate 2000
revenues and class average prices under the
preceding year's rates. These average rates
were reduced by approximately 0.8% to derive
2000 class-average prices.
(5) Additional savings in New York State Gross
Receipts Tax will be applied, as realized,
pursuant to Subsection 4.1.4.
Smaller large general service (S.C. No. 3)
customers and smaller customers taking a portion
of their electric requirements from NYPA (S.C. No.
4 customers under 2 MW) would receive an
approximate 2.2% phased in reduction over three
years (composed of approximately 2.0% in 1998, an
additional 0.1% in 1999 and an additional 0.1% in
2000). These customers will also receive the
phased in reductions in New York State gross
receipts tax, as they are realized, as specified
in the Section 4.1.4 below.
4.1.2.3. CALCULATION OF SC-3A RATES
As described in Section 4.1.1.2 and
illustrated on Table 4-2, S.C. No. 3A rates
have been designed to achieve targeted
prices.
4.1.3 RELATIONSHIP TO DAIRYLEA PILOT
Niagara Mohawk is implementing a pilot retail access
program for commercial farmers and food processors in
compliance with the Commission's June 23, 1997 Order
Establishing Retail Access Pilot Programs and September
18, 1997 order concerning compliance filings (the
"Pilot Program Orders").() The lost margins
associated with the Dairylea pilot program will count
towards rate decreases outlined in Section 4.1.2. Such
lost margins will be allocated to participating classes
according to the estimates shown in Table 4-3.
TABLE 4-3 PROJECTED COST OF DAIRYLEA PILOT
LOST MARGIN
-----------
SC1 $ 172,800
SC1B $ 11,600
SC1C $ 490,000
SC2ND $ 11,000
SC2D $ 118,000
SC3 $ 395,400
SC3A $ 271,500
----------
$1,470,300
4.1.4 PLANNED REDUCTIONS ASSOCIATED WITH GROSS
RECEIPTS TAX REFORM
New York State has enacted legislation to reduce its
gross receipts tax (GRT) by a phased-in 1% beginning in
October 1998. These GRT reductions will be applied as
realized.
4.1.5 POTENTIAL SECURITIZATION SAVINGS
To the extent that it is not otherwise prohibited by
legislation, the benefits of securitization should be
used to further reduce prices to S.C. No. 1, S.C. No. 2
and S.C. No. 3 customers. The Company and Staff
recommend that the Commission consider allocating a
portion of such savings for energy efficiencies and
clean technologies.
4.2 CTC AND MARKET PRICE HEDGING
4.2.1 Overview
For most customers, the CTC floats inversely with the
market price in order to guarantee the fixed total
price levels in Years 1-3. The Commodity Adjustment
Charge (CAC) is the mechanism that accomplishes this
variation in the CTC.
Customers will have the option of a fixed CTC, as
described in section 4.2.5 below.
In general, as more of Niagara Mohawk's supply
portfolio becomes unhedged, more of the market price
risk of energy is passed on to customers.
4.2.2 GENERAL CALCULATION AND APPLICATION
Except as otherwise provided in this agreement, all
customers, regardless of their energy supplier will be
assessed a non-bypassable CTC to cover their strandable
cost allocation. During the first three years of this
agreement, the CTC for each service classification will
be derived by deducting from the Company's bundled
retail prices, i) an Energy Commodity Charge, ii) a
transmission charge, and iii) a customer service and
distribution charge. During years 4-5, the CTC may not
be reduced to totally offset increases in transmission
or distribution prices. In addition, the CTC will be
subject to certain adjustment mechanisms, deferrals and
incentives as described in Section 4.3
As described in Subsection 4.2.3, the CTC will be a
function of the market price of electricity. This
approach will produce a location-specific CTC.
4.2.3 COMMODITY ADJUSTMENT CHARGE
A Commodity Adjustment Charge will be implemented to
adjust the CTC for those customers with floating CTCs.
This will generally include customers served under S.C.
No. 1, S.C. No. 2 Demand (S.C. No. 2D), S.C. No. 2 Non-Demand (S.C. No. 2ND), S.C. No. 3, and S.C. No 4
(customers < 2MW only).
The CTC for each service classification reflects a
location specific estimate of the market price of
electric energy and capacity. The Commodity Adjustment
Charge will be implemented by location, voltage
delivery level, load factor and service classification
in order to reconcile the actual market price with the
forecast of market prices upon which the CTC is
initially set.
Customers served on S.C. No. 3A, S.C. No. 4 (greater
than 2 MW only), S.C. No. 11, and certain other
customers (described in Section 4.2.5) will not be
subject to the Commodity Adjustment Charge.
4.2.4. SIGNIFICANCE OF HEDGED AND UNHEDGED ENERGY
The Company has hedged a large portion of its
transition costs through the contracts described in
Section 3. Except as otherwise provided in Section
4.2.5, the Company is bearing the risk of the amount of
unhedged energy in the forecast, except for any changes
in prices associated with unhedged energy resulting
from a nuclear plant retirement (which shall be
addressed as provided in Section 3.3.4). Over time, as
described in detail in Section 3.2 for fossil/hydro
assets, and Section 3.3 for nuclear assets, an
increasing proportion of energy purchased by RegCo will
become unhedged. The parties agree that the CTC in
years four and five should be designed: (1) to recover
allowable stranded costs and (2) to pass through to
certain customers the market price of unhedged energy.
In the event of a nuclear retirement within the first
three years of this agreement, the related unhedged
energy effects on the CTC are discussed in Section
3.3.4.
4.2.5 CTC OPTIONS AND MARKET PRICE FORECAST
The Company will make available fixed CTC options as
described below. The options described below do not
preclude adjustments to the CTC that may otherwise
be provided for in this agreement. If the Company
should retire a nuclear unit, energy prices and the CTC
will be adjusted in a manner consistent with Section
3.3.4.
4.2.5.1 FOR S.C. NO. 3A AND S.C. NO. 4 (>2
MW) CUSTOMERS:
Thirty days prior to the PowerChoice
implementation date, SC# 3A and SC# 4
customers greater than 2 MW will have a
choice of three pricing options. Following
this one time thirty day selection period,
the only offer available to S.C.# 3A
customers will be the default (option 1)
program described below. Tariffs for each of
these options will be available at least
sixty days prior to the PowerChoice
Implementation Date, subject to Commission
approval. Existing SC#11 customers with
expiring contracts will have the choice of
either taking the standard tariff or
extending their SC#11 contracts on the same
terms and conditions through the term of this
settlement agreement. Such SC#11 customers
choosing the standard tariff will only be
allowed to choose option 1. The
implementation of these options will be in
conjunction with the Company's hours use
design and individual customer load profiles.
(1) Option 1 (Default): Fixed CTC and
Floating Commodity Price
- Adjust CTC in the PowerChoice
filing to reflect a compromise
market price forecast. The
estimate of the market price
forecast varies by region, service
class, load factor and voltage
level.
- The Floating Commodity Price will
be the Energy Commodity Charge
discussed in Section 4.4.1.
Appendix D contains the energy backout credit
for each service classification and voltage
level. Appendix D will be adjusted for the
final rate year as discussed in Section
4.1.1. These prices are measured at the
customer meter. Market prices for years four
and five will be reforecasted in year three.
(2) Option 2a: Fixed CTC and Fixed
Commodity Charge
- This option will be designed with
the original forecast of energy
backout rates (contained in
Appendix D identified as the
7/23/97 forecast), such that if all
SC-3A customers choose this option
the rate goal will be met.
- Customers commit to contract to
purchase forecast quantity of
electricity from Niagara Mohawk for
the five year period.
(3) Option 2b: Customers who select Option
2a can purchase the right to exit the
contract on six months notice. The
purchase price of the option to exit
will be provided by the Company as part
of its tariff filing. The fee would be
paid during the five-year period
regardless of whether the option to exit
the contract is exercised.
(4) Prior to December 1, 1997, the Company
must elect one of the following
alternatives.
a) After customers have chosen option
2a or 2b, the Company will solicit
and award bids for the right and
obligation to provide the commodity
to customers that choose Option 2a
or 2b, but only subject to customer
approval; or
b) The Company will offer a 5-year
fixed CTC, Floating Commodity Price
Option (in addition to the 3-year
fixed CTC Floating Commodity Price
Option, above) which shall be based
upon the energy forecast underlying
Options 2a and 2b, above.
(5) For all customers who choose an
alternative supplier and return, they
return to the Floating Commodity Price
and the fixed CTC option originally
selected by the customer. If a
customer's SC-11 contract expires and
they do not choose to renew it, then
they return to the default of a floating
commodity price and a fixed CTC.
4.2.5.2 FOR S.C. NOS. 1, 2, 3 CUSTOMERS:
(1) Option 1: Fixed CTC and Floating
Commodity Price and Fixed CTC
An amount of energy up to 75 percent of
the amount of forecasted energy
necessary to serve SC-3A customers
choosing Option 2 (fixed CTC and fixed
commodity charge) will be made available
for those SC-1, 2 and 3 customers who
have retail access.
- Customers who choose this option
will have their CTC based on the
energy backout rate described above
for the SC-3A customers, adjusted
for region and load shape as shown
in Appendix D.
- For customers who choose an
alternative supplier and return,
they return to the default of
Option 2, floating CTC and floating
commodity price.
(2) Option 2 (Default): Floating CTC and Floating Commodity.
The CTC is adjusted to reflect the level
of unhedged energy after adjustments to
reflect customers choosing the fixed CTC
and floating commodity option described
above.
(3) The parties will continue to pursue
mechanisms to increase the availability
of fixed CTCs for SC 1, 2, and 3
customers in Years 3 and beyond. Any
final resolution of this issue will not
negate the Company's obligation to cover
unhedged energy in years one through
three.
4.2.6 ADJUSTMENTS TO THE CTC IN YEARS FOUR AND FIVE
The CTC will be adjusted to reflect a new market price
forecast for years four and five. The CTC may also be
adjusted in years four and five due to generation-related deferrals, recovery of a generation sale
incentive (Section 2.4.3), and if a nuclear plant is
retired , sold or divested (Section 3.3). In addition,
variations between the actual and forecasted cost of
the indexing provisions of certain IPP contract, as
described in Section 2.4, will be passed through the
Commodity Adjustment Charge beginning in year four.
4.2.7 ALCAN AND SITHE/INDEPENDENCE
Alcan and/or Sithe/Independence's stranded cost
responsibility with respect to service to Alcan will be
handled in accordance with the Order issued and
effective 11-3-94 in Case No. 94-E-0136. Accordingly,
Alcan and/or Sithe/Independence will not be assessed a
CTC access fee for exit fee or Alcan load served by
Sithe/Independence except as provided for in Case No.
94-E-0136. The Company reserves the right to petition
the Commission for changes in those obligations in
accordance with the Order in that case.
4.3 SURCHARGE AND RECONCILIATION MECHANISMS
4.3.1 SURCHARGE MECHANISMS THAT WILL BE ABOLISHED
Upon the PowerChoice Implementation Date, the following
surcharge mechanisms will be abolished:
Rule 29: Adjustment in Accordance With Changes in The
Cost of Fuel (inclusive of the FAC, fuel amortizations,
and DIRAM)
Rule 43: Adjustment of Charges Pursuant to the
Measured Equity Return Incentive Term (MERIT)
Rule 44: Adjustment of Charges Pursuant to the Niagara
Mohawk Electric Revenue Adjustment Mechanism (NERAM)
Rule 46: Adjustment of Charges Pursuant to the
Regulatory Surcharge Mechanism
Rule 47: Adjustment of Charges Pursuant to the
Extension of Suspension Period Surcharge Mechanism
4.3.2 MUNICIPAL GROSS RECEIPTS TAX SURCHARGE
For the terms of this Agreement and beyond, the
surcharge for PSC No. 207 Rule 32 - Increase in Rates
Applicable in Municipality Where Service is Supplied,
more commonly referred to as Gross Receipts Tax (GRT),
will continue to be applied as a surcharge due to
variances in tax rates by municipal taxing authorities.
4.3.3 NYPA HYDROPOWER BENEFIT RECONCILIATION
A New York Power Authority (NYPA) Hydropower Benefit
Reconciliation Mechanism for residential service will
be established. Under certain contracts for the sale
of low-cost hydropower to Niagara Mohawk, the price
benefits of that power are to be passed on to the
Company's residential customers. As a result of the
elimination of the FAC, a new reconciliation must be
established to ensure that Niagara Mohawk can fulfill
this requirement.
Because 1995 FAC surcharge balances were rolled into
1995 base rates, as described in Subsection 4.1.2, the
resulting residential prices reflect NYPA hydropower
benefits that accrued in 1995. Accordingly, the
Company will perform an annual reconciliation comparing
actual benefits received in 1998 and subsequent years
with those that were received in 1995. The variance
resulting from the reconciliation (credit or debit)
will be applied as an annualized reconciliation factor
during the 12 months following completion of the
reconciliation. For residential customers who are
ineligible for retail access, a reconciliation factor
will be applied to their overall bill. For residential
customers who have a choice of power suppliers, a
reconciliation factor will be applied to the CTC.
Due to reporting lag, the 1998 calendar year
reconciliation cannot be performed until February 1999,
which will delay the application of the annualized
reconciliation factor until March 1999.
4.3.4 SYSTEM BENEFITS CHARGE
As further described in Section 7, a System Benefits
Charge (SBC) will be implemented as part of customer
service and distribution charges, although stipulated
as a distinctly separate charge, for all customer
service classifications (with the exception of Economic
Development Zone power, S.C. No. 11 contracts (except
as specifically allowed by contract) and certain NYPA
allocations) in order to recover costs associated with
public policy programs. Table 4-4 shows the projected
SBC recoveries for 1998-2000.
TABLE 4-4 PROJECTED SBC RECOVERIES
1998 1999 2000
---- ---- ----
1. Base Public Policy
Programs ($000) 15,000 15,000 15,000
2. Sales Forecast (MWH)
subject to SBC
recoveries 24,174,398 24,472,671 24,650,753
3. SBC Charge (Line 1)/
(Line 2) ($/KWH) .000620 .000613 .000609
4.3.5 DEFERRALS
The cost categories eligible for deferrals are
described in Section 2.6.
Starting in year four, deferrals will be collected
through appropriate rate mechanisms, depending upon the
nature of the cost, i.e., generation-related deferrals
such as changes in nuclear costs will be collected
through a surcharge to all customers who pay a CTC,
distribution-related deferrals will be collected
through a distribution surcharge. Customers who do not
pay the CTC will not pay generation related deferrals.
4.3.6 RECOVERY OF GENERATION SALE INCENTIVE
As described in Section 3.2.2, the Company will receive
an incentive for the sale of fossil and hydro assets.
All customers who pay the CTC or, where applicable,
exit fees will pay the generation incentive through a
surcharge. Customers who do not pay the CTC will not
pay the generation incentive.
Table 4-5 summarizes all of the adjustment mechanisms
described in Sections 4.2 and 4.3 and their
applicability to service classifications.
TABLE 4-5 SURCHARGES AND RECONCILIATION MECHANISMS
S.C. NO.3 S.C. NO. 3A
(SMALL S.C. (INCLUDING
S.C. NO. S.C. NO. NO. 4) AND LARGE S.C. S.C. NO.
1/1B/1C 2D/2ND S.C. NO. 7 NO. 4) 11
------- ------- ----------- ----------- --------
Gross Receipts Tax Yes Yes Yes Yes Yes
NYPA Hydropower Benefits Yes No No No No
Commodity Adjustment Charge Yes*** Yes*** Yes*** No No
SBC Yes Yes Yes**** Yes**** *
Deferrals**/Generation Yes Yes Yes**** Yes**** *
Incentive
*Contract Specific
**Applies to years 4-5 only
***Assumes default option is chosen
**** Except as provided for certain NYPA customers in Section 4.14 and Table 4-6
/TABLE
4.4 UNBUNDLED SERVICES AND PRICES
4.4.1 UNBUNDLED ENERGY COMMODITY CHARGE
To ensure that customers receive correct price signals,
it is important to establish a reliable proxy for the
generation commodity price embedded in Niagara Mohawk's
bundled retail rates. Prior to the time the ISO
tariff becomes effective, the actual market price of
electricity will be based upon Niagara Mohawk's
Commission approved methodology for determining
marginal cost. This document is on file with the
Commission (entitled Technical Administrative Rules and
Procedures ("TARPS")) and is associated with S.C. No.
11 and the now expired S.C. No. 8. These prices will
be delineated by hour, month and voltage level for each
class. In addition, the Company will adjust the TARPS
prices, on a revenue neutral basis, to reflect
differences in prices for the western, central and
eastern regions. If, prior to the effectiveness of an
ISO tariff, the New York Power Pool (NYPP) begins to
calculate and publish location-specific marginal prices
of power, Niagara Mohawk reserves the right to employ
those prices instead of the TARPS values.
If the TARPs prices are used in the Company's unbundled
prices, the Company will, after consulting with the
parties, develop rules and/or procedures designed to
oversee and audit the Company's development of the TARP
process. The Company will submit these rules and/or
procedures to the Commission for review.
Once the ISO tariff becomes effective, assuming a fully
functioning ISO and a viable market, the commodity
value represented in retail tariffs will be based upon
locational prices posted by the ISO.
The CTC inherently reflects a forecast of commodity
prices. A portion of the differential between
forecasted and actual commodity prices will be
reconciled and refunded to or recovered from customers
with floating CTC's through the Commodity Adjustment
Charge.
There will be no prudence review associated with
RegCo's energy or capacity purchases during the period
of this rate Settlement Agreement. As described above,
commodity prices will be capped by the spot market
price. RegCo is free to enter into longer term
contracts, other than those described in Section 3.0,
for capacity and energy, but will bear the full risks
of such contracts (i.e., will keep any savings or
absorb any losses during the five year period). If
RegCo enters into a contract for energy and capacity
whose duration is longer than five years (i.e., whose
duration extends beyond the term of this Settlement
Agreement), the cost associated with that contract will
be subject to the normal revenue requirements review
that occurs in the next rate case RegCo files for rates
beyond the fifth year. If RegCo does not enter into
any longer-term contract, there will be no prudence
review associated with its not having entered into
longer-term contracts.
4.4.2 UNBUNDLED TRANSMISSION CHARGES
Niagara Mohawk's retail access tariff will be filed
with the Commission and the FERC and cover all
components of the retail access tariff described
herein. The transmission component of such retail
access tariffs will be provided under Niagara Mohawk's
Open Access Transmission Tariff ("OATT").
Network service charges under the OATT are calculated
as the FERC approved annual revenue requirement
multiplied by the customer's load ratio share (the 12-month
rolling average of the customer MW load divided
by the total demand on the Transmission System at the
time of the monthly transmission peak). To ease the
administrative burden of applying this formula to
calculate and bill the transmission charges applicable
to each customer under the OATT, and decreasing the
distribution charge by that value, Niagara Mohawk
proposes to implement a procedure whereby the total
delivery charge (transmission and distribution) does
not require an individual, customer-specific OATT
value. That is, the total delivery charge will be
designed to recover both the transmission and
distribution revenue requirements using PSC rules for
the assignment of costs even as transmission service is
provided under the terms and conditions of the OATT
applicable to each customer. Niagara Mohawk will seek
from the FERC a waiver to implement this administrative
simplification.
4.4.3 UNBUNDLED DISTRIBUTION CHARGES
Distribution services include power delivery services
other than transmission services, and encompass not
only local "wires" services but also metering, billing,
collections, and customer service telephone.
Distribution prices are cost-based. Distribution
prices for 1998 were estimated to recover fully the
costs associated with distribution services, and
allocated to rate classes and rate components based on
the Company's latest cost of service studies.
Distribution service prices for the years two through
five will be increased according to the Price Cap plan
described in Section 4.4.4 and the price goals
described in Section 4.1.
4.4.4 PRICE CAP PLAN FOR TRANSMISSION AND
DISTRIBUTION SERVICES
A price cap plan for the Company's transmission and
distribution services will apply for years 2 through 5
of this settlement.
4.4.4.1 T&D RATE INCREASES
The Company may increase its prices for
transmission and distribution services up to
a cap in each year except as otherwise
provided herein. The cap will be based on
the projected increase in the cost of
providing transmission and distribution
services as set forth in the financial
forecast in Appendix C.
4.4.4.2 CTC OFFSETS TO INCREASED T&D PRICES
Except as provided in Section 4.14, in years
2 and 3, any increase in T&D prices will be
exactly offset by a decrease in the CTC
charges for those years in order to satisfy
the overall bundled price targets outlined in
Sections 4.5 through 4.8. In years 4 and 5,
there will be no explicit offset to the CTC
for increases in T&D prices.
4.4.4.3 PRICE CAP FOR YEARS 4 AND 5
As described in Section 2.4.1.2, prices in
years four and five can be increased by an
amount not to exceed 1% of the all-in price
excluding the commodity (e.g. inclusive of
transmission, distribution and forecasted CTC
charges). The price cap excludes recovery
of deferrals and the generation sale
incentive. The price cap also excludes the
variations in contract costs due to the
indexing provisions of IPP indexed contracts
(See Section 2). The filing to propose an
increase under the cap or to recover deferred
costs or to recover the generation sale
incentive will address the design of the rate
recovery mechanism.
4.4.5 AVAILABILITY OF UNBUNDLED PRICES FOR
INFORMATIONAL PURPOSES
Prior to the time a customer becomes eligible for
retail access, Niagara Mohawk, upon request, will
provide the customer with unbundled price data for the
customer's use.
4.4.6 RELATIONSHIP TO GENERATION SEPARATION
A reallocation of costs between the
transmission/distribution and CTC components of
unbundled prices may be necessary as a result of a
sale, spin-off or transfer of generation assets. To
the extent this reallocation is necessary, it will be
done on a class-average revenue neutral basis.
4.4.7 CUSTOMER SERVICE BACKOUT CREDIT
The customer service backout credit is described in
Section 5. Once the credit is designed, customers who
select an alternate supplier will receive an
appropriate credit for the particular Company services
provided by the ESCO, and a minimum credit regardless
of the services offered.
4.5 RESIDENTIAL PRICING DESIGNS
4.5.1 SERVICE CLASSIFICATION NO. 1 - STANDARD
RESIDENTIAL RATE
4.5.1.1 FLAT RATE STRUCTURE
The design will remain a flat rate structure
consisting of a single energy rate with a
customer charge.
4.5.1.2 PHASED-IN REBALANCING OF CUSTOMER
AND ENERGY CHARGE
The customer charge will be phased in to
achieve a $17.44 level in the year 2000 with
additional changes to be considered in years
4 and 5. The Company and Staff share the
objective of continuing to move volumetric
charges toward marginal energy costs. The
increase in customer charge revenue will be
offset by an equal reduction in the energy
charge revenues to ensure that the
rebalancing of customer and energy charge is
revenue neutral on a class-average basis.
4.5.1.3 PHASED-IN DISCOUNT FROM INITIAL
PRICE LEVELS
As described in Section 4.1, over the three
years beginning with the PowerChoice
Implementation Date, tariff rate reductions
will be phased-in so as to ultimately produce
an approximate 2.2 percent reduction in class
average prices. (As described in Section
4.1.4, additional savings associated with
currently planned reductions in New York
gross receipts taxes will be applied as
realized). These reductions will be applied
to the energy rate. The pricing designs and
resulting bill impacts are illustrated in
Appendix D.
4.5.2 SERVICE CLASSIFICATION NOS. 1B AND 1C -
RESIDENTIAL TIME-OF-USE RATES
Currently the Company has two Time-of-Use (TOU)
offerings for residential customers. Service
Classification No. 1B is a voluntary offering;
approximately 3700 customers take service under this
rate. Service Classification No. 1C is a mandatory
rate for all residential and farm customers who consume
greater than 30,000 KWh annually. There are
approximately 12,000 customers served under S.C. No.
1C.
As of the PowerChoice Implementation Date, S.C. No. 1B
will be closed to new subscribers other than
subscribers who will use geothermal technology.
Existing S.C. 1B customers will have the option of
remaining under the existing program or changing to
S.C. No. 1 service. No price reductions will be
applied to the S.C. No. 1B class.
As of the PowerChoice Implementation Date, S.C. No. 1C
will no longer be mandatory. S.C. No 1C will become
the optional TOU offering for residential customers.
Customers served under this service classification will
have the option of remaining under the existing program
or changing to S.C. No. 1. No price reductions will be
applied to the S.C. No. 1C class.
4.5.3 SERVICE CLASSIFICATION NO. 1H - OPTIONAL
RESIDENTIAL RATE
This option consists of higher customer charge and a
lower flat energy charge. On the PowerChoice
Implementation Date, S.C. No. 1H will be closed to new
subscribers. Existing S.C. No. 1H customers will have
the option of remaining under the existing program
until the beginning of year 4 of this agreement at
which time they will be transferred to S.C. No. 1.
These customers will have the option to migrate to S.C.
No. 1 at any time prior to year 4 of this agreement.
4.5.4. CTC
The CTC will be recovered volumetrically in accordance
with the actual usage of each residential customer.
4.6 COMMERCIAL PRICING DESIGNS
4.6.1 SERVICE CLASSIFICATION NOS. 2ND - SMALL
GENERAL SERVICE RATES
4.6.1.1 FLAT RATE
Under S.C. No. 2ND, the design will remain a
flat rate structure consisting of a single
energy rate with a customer charge.
4.6.1.2 PHASED-IN REBALANCING OF CUSTOMER
AND ENERGY CHARGES
The customer charge will be phased in to
achieve a $23.95 level in the year 2000 with
additional changes to be considered in years
4 and 5. The Company and Staff share the
objective of continuing to move volumetric
charges toward marginal energy costs. The
increases in customer charge revenues will be
offset by an equal reduction in the energy
charge revenues to ensure that the
rebalancing of customer and energy charge is
revenue neutral on a class-average basis.
4.6.1.3 PHASED-IN DISCOUNT FROM INITIAL
PRICE LEVELS
As described in Section 4.1, over the three
years beginning with the PowerChoice
Implementation Date, rate reductions will be
phased-in so as to produce an approximate 2.2
percent reduction in class average prices.
(As described in Section 4.1.4, additional
savings associated with currently planned
reductions in New York gross receipts taxes
will be applied as realized). These
reductions will be applied to the energy
rates. The pricing designs and resulting
bill impacts are illustrated in Appendix D.
4.6.2 SERVICE CLASSIFICATION NO. 2D - SMALL GENERAL
SERVICE RATES
Upon the PowerChoice Implementation date, the design of
Niagara Mohawk's Small General Demand Service (S.C.2
Demand (S.C. No. 2D)) will be altered as described
below:
4.6.2.1 PHASED-IN REBALANCING OF CUSTOMER
AND ENERGY CHARGES
The customer charge for S.C. No. 2D will be
phased-in to achieve a $63.49 level in the
years 2000 with additional changes to be
considered in years 4 and 5. The Company and
Staff share the objective of continuing to
move volumetric charges toward marginal
energy costs. The increases in customer
charge revenues will be offset by equal
reductions in the energy charge revenues to
ensure that the rebalancing of customer and
energy charges is revenue neutral on a class-average basis.
The existing demand charge for S.C. No. 2D will remain
unchanged for the first three years of this agreement.
4.6.2.2 PHASED-IN DISCOUNT FROM INITIAL
PRICE LEVELS
As described in Section 4.1, over the three
years beginning with the PowerChoice
Implementation Date, rate reductions will be
phased-in so as to produce an approximate 2.2
percent reduction in class average prices.
(As described in Section 4.1.4, additional
savings associated with currently planned
reductions in New York gross receipts taxes
will be applied as realized). These
reductions will be applied to the energy
rate. The pricing designs and resulting bill
impacts are illustrated in Appendix D.
4.6.3 CTC
The CTC will include per KW (where
applicable) and per KWh charges applied to
100 percent of actual demand and usage
quantities of each commercial customer for
the billing period.
4.7 LARGE GENERAL SERVICE (S.C. NOS. 3, 3A, 4 AND 5)
PRICING DESIGNS
Prices for Niagara Mohawk's S.C. No. 3, S.C. No. 3A,
and S.C. No. 4 (customers who also take power from
NYPA), will be structured as declining block rates as
described below. Unbundled prices will include a CTC
if applicable.
4.7.1 S.C. NO. 3 (LARGE GENERAL, SERVICE < 2MW) AND
SMALLER S.C. NO. 4 CUSTOMERS (<2MW)
Prices for customers taking service under S.C. No. 3
and customers taking service under S.C. No. 4 whose
demand (exclusive of the portion of demand served by
NYPA) is less than 2 megawatts will be developed as
follows:
4.7.1.1 RATE DESIGN
Prices will include a customer charge, a
demand charge, a reactive demand charge and
energy charges based on two blocks. The
blocks will be established based on the usage
above and below 450 hours of use of the peak
demand (61.6% load factor). This design is
referred to as an "hours use" design. The
pricing designs and resulting bill impacts
are illustrated on Appendix D.
4.7.1.2 INITIAL PRICE LEVELS
As described in Subsection 4.1, the class
average prices for S.C. No. 3 and smaller
S.C. No. 4 customers will be reduced by
approximately 2.2 percent. The reduction
will be reflected in the tail block energy
price. (As described in Section 4.1.4,
additional savings associated with currently
planned reductions in New York gross receipts
taxes will be applied as realized).
4.7.1.3 CTC
The CTC will include per KW and per KWh
charges applied to 100 percent of actual
demand and usage quantities for each customer
during the billing period.
4.7.2 S.C. NO. 3A (LARGE GENERAL SERVICE, MANDATORY
TIME OF USE, HIGH DEMAND) AND LARGE S.C. NO.
4 CUSTOMERS (>2MW)
Prices for customers taking service under S.C. No. 3A
and customers taking service under S.C. No. 4 whose
demand (exclusive of the portion of demand served by
NYPA) is greater than 2 megawatts will be developed as
follows:
4.7.2.1 RATE DESIGN
Prices will include a customer charge, a
demand charge, a reactive demand charge and
energy charges based on declining blocks.
Effective upon the PowerChoice Implementation
Date, two blocks will be established based on
the usage above and below 250 hours of use at
the peak demand (34.2% load factor). One
year later, a third block will be established
at 400 hours of use (54.8% load factor).
This design is referred to as an "hours use"
design. The pricing designs and resulting
bill impacts are illustrated on Appendix D.
4.7.2.2 INITIAL PRICE LEVELS
Price reductions are designed to be phased-in
during the three years following the
PowerChoice Implementation Date such that the
average price, based on current forecasts, in
the year 2000 for all customers under S.C.
Nos. 3A, 11, and large S.C. No. 4 (including
ERIR, EDR, and EDZR discounts) will be $.0585
per KWh inclusive of all currently enacted
New York State gross receipts tax reductions.
If the currently enacted gross receipts tax
reductions are repealed, the prices will
increase accordingly.
4.7.2.3 REBALANCING OF DEMAND CHARGES
While the demand charge for S.C. No. 4 is
currently based on the peak demand occurring
within the billing period, the demand charge
under S.C. No. 3A is based entirely on the
customer's maximum demand during peak hours.
Niagara Mohawk will file tariff revisions to
establish a demand charge based on the
customer's maximum demand during all hours to
cover transmission and distribution costs.
The on-peak demand charge has been reduced to
offset the revenue increases resulting from
this change.
4.7.2.4 CTC
The CTC will include per KW (based on the
maximum demand occurring during peak hours)
and per KWh charges applied to 100 percent of
actual demand and usage quantities for the
billing period.
4.7.3 S.C. NO. 5 (COMBINATION 25 & 60 CYCLE POWER)
The Company currently provides combination 25 cycle and
60 cycle power to approximately 7 customers. The
Company will freeze the existing 25 cycle S.C. No. 5
rates (which were approved in April 1995) and hold them
constant for the term of this Agreement. The Company
will reduce the rates for 60 cycle service to those
contained in S.C. No. 2, S.C. No. 3 or S.C. No. 3A,
depending on the size of the customer. The Customer
will then be eligible to receive unbundled 60 cycle
electric service according to the otherwise applicable
service classification.
4.7.4 PROJECTED INDUSTRIAL PRICES
The weighted average price has been computed by summing
the forecasted revenues associated with the S.C. No.
3A, "large" S.C. No. 4, S.C. No. 11 (those qualifying
for S.C. No. 3A) and dividing by the forecasted
kilowatt-hours associated with the same classes. (This
will include all economic development riders with the
exception of revenues and sales associated with EDP
customers). The Company plans to administer the
phased-in price reductions in a manner similar to that
contained in Table 4-2.
4.8 CUSTOMERS WITH S.C. NO. 11 CONTRACTS AND ECONOMIC
DEVELOPMENT PROGRAMS
The Company will honor all existing S.C. No. 11
contracts through their normal expiration.
Upon implementation of the ISO, the Company will revise
the definition and calculation of marginal cost under
tariff to: 1) incorporate the prices, terms and
conditions of the ISO tariff and 2) calculate and
administer a system-wide weighted average marginal cost
consistent with the existing S.C. No. 11 tariff for the
billing of S.C. No. 11 contracts entered into prior to
July 23, 1997.
In the event that an existing Customer's S.C. No.11
contract expires during the term of this agreement, at
the Customer's request and upon 60 days prior notice,
the Company will extend the S.C. No. 11 contract on the
same terms and conditions for the remaining term of
this agreement, or until the Company files for a rate
increase or otherwise petitions the Commission post
year five, after which such contract shall expire
unless otherwise specifically agreed to between the
Company and Customer.
The Company will offer EDR and ERIR customers a choice
of their existing rider, the otherwise applicable
tariff rate, or if eligible, retail access.
The Company will not petition the Commission to modify
or cancel its current S.C. No. 11, ERIR or EDR tariffs
until an adequate replacement tariff is developed that
meets the economic development objectives of the
existing tariffs. The Company will contemporaneously
file its replacement tariff with its petition to cancel
or modify its current SC-11, ERIR and EDR tariffs.
The Company will continue to work with the parties to
design the S.C. No. 11 replacement tariff with the
objective that the revised tariff will be filed as soon
as possible, but in no event later than December 31,
1997.
Under no circumstances will the Company require that a
customer purchase the commodity from the Company in
order to qualify for an S.C. No. 11 contract.
The Company will not be precluded from proposing other
programs of general applicability to address economic
development issues.
4.9 OPTIONAL TARIFFS FOR NON-RESIDENTIAL CUSTOMERS
The Company will cease signing Customers to the
Optional Tariff Schedules effective with the
PowerChoice Implementation Date. Customers currently
served on the Optional Pricing Schedules will be given
the option to continue to receive their optional
provisions until such customers become eligible for
retail access after which optional pricing schedules
will be eliminated; provided, however, that the
optional rates will continue to be changed to reflect
changes in the marginal cost of electricity. Customers
who choose to retain their optional provisions prior to
their eligibility for retail access will be subject to
the rates in effect on April 27, 1995 for the Contract
Load portion of their bill.
4.10 CUSTOMERS SELLING POWER TO NIAGARA MOHAWK UNDER S.C.
NO. 6
(a) Separate S.C. No. 6 buy back rates shall be
determined for Load Areas 1, 2, 3, and 4. Niagara
Mohawk's payments for deliveries from Independence
Station shall be the applicable rates (as set
forth in paragraphs b and c below) for Area 2.
(b) Commencing January 1, 1998 until the date the
Master Restructuring Agreement ("MRA") is
consummated as defined in Section 10.2 of that
agreement ("Consummation Date"), the buy back
rates shall be the time-differentiated price by
month. Appendix D sets forth the prices to be
used in the tariff. Area 3 prices are equal to
Area 2 prices plus one mill.
(c) Commencing with the MRA Consummation Date, the buy
back rates for each Load Area shall be the time-differentiated
prices, set forth by month in
Appendix D hereto. The rates set forth in
Appendix D shall remain in effect until December
31, 1998.
(d) Commencing no later than August 1, 1998, the
parties shall convene technical conferences to,
(i) (assuming there is an operating ISO/PE on
August 1, 1998) determine the appropriateness of
using the ISO market data to set 1999 SC 6 buy-back rates, and
the specific market data from the
ISO/PE which should be used to calculate a market-based buy
back rate that is consistent with PURPA,
or (ii) administratively redetermine the S.C. No.
6 rates for the rate year commencing January 1,
1999 if a transition to market-based rates will
not occur on January 1, 1999.
(e) If, after such technical conferences, the parties
do not reach a consensus as to the appropriate
rates or mechanism for setting the 1999 S.C. No. 6
rates, then on or before October 1, 1998, the
parties will jointly request the assistance of a
settlement judge to resolve these issues. If
after a reasonable period of intervention by the
settlement judge, an S.C. No. 6 rate or mechanism
has not been reached by consensus of the affected
parties, any party may request evidentiary
hearings followed by briefs and a recommended
decision to the Commission that will enable the
Commission to issue an order on the 1999 S.C. No.
6 rates prior to January 1, 1999. Any S.C. No. 6
rate filing shall be subject to discovery under
the Commission's Rules and to public comment under
the State Administrative Procedures Act.
4.11 CUSTOMERS TAKING SERVICE UNDER S.C. NO. 7 (SALE,
BACKUP, MAINTENANCE AND SUPPLEMENTAL ENERGY AND
CAPACITY TO CUSTOMERS WITH ON-SITE GENERATION
FACILITIES) AND EXIT FEES FOR CUSTOMERS WHO BYPASS THE
COMPANY'S DELIVERY SERVICE.
4.11.1 RATIONALE
The intention of the Exit Fee and the CTC provisions of
SC#7 is to discourage uneconomic bypass of the
Company's services and charges in cases where such
bypass is not economic from society's standpoint and
would therefore shift costs to other stakeholders.
4.11.2 APPLICABILITY
The following table sets forth the applicability of the
Exit Fee and SC#7 in specific circumstances. In
addition, applicability of exit fees for NYPA
allocations will be determined in accordance with
Section 4.14 and Table 4-6 of this Settlement. For
circumstances not included in this table, or
contemplated herein, the company will be permitted to
petition the Commission to assess an Exit Fee or apply
SC#7 in accordance with the intentions of this Section
4.11.
EXIT FEE AND SC#7 APPLICABILITY
-------------------------------
CIRCUMSTANCE EXIT FEE SC# 7
- ------------ -------- -----
Municipalization, including cases where Yes No
the municipal disconnects from the
Company's delivery system.
Customer remains in the same location, Yes No
disconnects from the Company's delivery
system and connects to another utility's
delivery system such as that of another
utility or IPP.
Self generation with backup from the No Yes
company's delivery system.
Self generation where the customer No No
disconnects from the interconnected
system or is not connected to the
interconnected system.
Customers that received an SC#11 No No
Contract prior to 7/23/97 based on
a showing of a viable cogeneration
threat up to the electric capacity of
the demonstrated viable cogeneration
project.
Customers that relocate or close No No
their operation.
4.11.3 EXIT FEE
(a) Exit Fee Calculation Methodology
The Company will use a "revenues lost" exit fee
methodology similar to that proposed by the FERC
in Order 888. The exit fee would be calculated on
a one-time basis. However, the Company is willing
to entertain levelized annual payments or other
options that may be negotiated between the Company
and the customer, subject to adequate security.
The "revenues lost" formula is equal to the net
present value (at the Company's weighted average
cost of capital) over Y years of:
(R-E)
Where,
R shall equal the annual estimated revenue from
the customer at using the bundled price designs
contained in the settlement agreement. There will
be no credit for transmission related revenues, as
proposed in FERC Order 888, since the customer
will not be using the Company's delivery system.
E is the Company's estimate of the annual revenues
that it can receive by selling the released
capacity and associated energy. As in FERC Order
888, the customer will have the option to market a
portion of the released capacity and associated
energy.
Y is the number of years required for the Company
to recover its full stranded costs. Since Y is
dependent upon a number of factors, including the
timing of the departure, the Company will address
Y on a case-by-case basis.
In addition, the Company will charge departing
customers for their allocation of nuclear
decommissioning costs through time.
(b) Accounting for Exit Fees
The Company agrees with the concept that any exit
fees received should be deferred to affect
stranded costs. The Company will work with the
parties to develop the specific accounting, and
subsequent amortization, of the deferral for exit
fees. To the extent that exit fees are received
during the term of this settlement that result in
a reduction in revenues otherwise expected to be
collected by the Company through the CTC, the
parties agree that a portion of the exit fee can
be recognized during the term of the Settlement to
hold the Company harmless.
4.11.4 S.C. NO. 7
Effective with the PowerChoice Implementation Date,
S.C. No. 7 will be closed to new subscribers.
4.11.4.1 EXISTING CUSTOMERS
Existing customers shall be subject to the
S.C. No. 7 prices in effect on July 23, 1997,
as well as any applicable surcharges as
identified on Table 4-5.
At such time as all or the majority of the
Company's Fossil and Hydro units are divested
and the commodity portion of backup,
supplemental and maintenance service are
available on a competitive basis, the rates
for existing S.C. No. 7 users shall be
changed to those described in 4.11.4.2 below.
The Company agrees to use its best efforts to
acquire ancillary services from the
competitive market at the time of
divestiture. The Company, however, will not
be required to create new systems to allow
for the procurement of such services on a
competitive basis.
4.11.4.2 NEW SUBSCRIBERS AND EXISTING S.C.
NO. 7 CUSTOMERS FOLLOWING
DIVESTITURE OF THE COMPANY'S FOSSIL
AND HYDRO ASSETS
New tariff leaves shall be added which will
apply to all non-residential customers with
on-site generation and existing customers
with on-site generation who are not currently
served under S.C. No. 7. In addition, these
new tariff leaves shall apply to existing
S.C. No. 7 customers at a later date as
provided in Section 4.11.4.1. These tariff
leaves shall provide for rates which include:
i) a combination of an access charge and an
energy charge for the baseline customer load
("CL") and, ii) the rates contained in the
customer's otherwise applicable service
classification (or S.C. No. 11, if qualified)
for any load which exceeds the CL, where:
- The CL shall be based on the customer's
load in a historic period.
- The access charge for load at or below
the CL shall be equal to the customer's
contribution to the Company's fixed
costs during the historic period. The
access charge shall be subject to
adjustment for surcharges as identified
on Table 4-5.
- The energy charge for load at or below
the CL shall equal the commodity cost
under the otherwise applicable tariff,
if the commodity is purchased from
Company.
4.12 ECONOMIC DEVELOPMENT ZONE RIDER (EDZR)
The Parties will continue to work on developing a rate
plan that will result in current economic development
zone rates that are equal to full marginal commodity
and distribution cost (excluding the SBC) and full
transmission cost by the end of the five year
settlement period for customers taking service under
the current rider. The rate plan will be developed as
soon as possible but in no event later than December
31, 1997.
In developing the EDZR rate plan the following
principles shall govern:
(a) Non-contestable customers will be phased into full
marginal costs on an accelerated schedule that
takes into account the level of rate impacts on
individual customers.
(b) Contestable loads will be phased in over the full
five years of the settlement period.
(c) For a limited number of customers that may need
special economic development considerations, the
Company will work with the parties to address
these special cases.
For new EDZR customers or new growth, the tariff rate
will be equal to full marginal commodity and
distribution cost (excluding the SBC) and full
transmission cost.
4.13 PRICING DESIGNS FOR SERVICE CLASSIFICATIONS UNDER PSC
NO. 214 -- ELECTRICITY
Niagara Mohawk's prices for outdoor lighting services
are set forth in PSC No. 214 -- Electricity (formerly
PSC No. 213 -- Electricity). Service Classification
Nos. 1, 2, 3 and 6 under PSC No. 214 represent private
area and street lighting. The Company is proposing a
rebalancing of the facility-specific and volumetric
charges. The proposed facility charges have been set
at marginal cost as calculated under the current long-run
incremental cost of service studies. The proposed
volumetric component of these service classifications
have been increased to offset the decrease in facility
specific charges to ensure that the rebalancing is
revenue neutral. The prices for these service
classifications are attached in Appendix D. The
Company will phase in these price changes over the
first three years of this agreement.
Service Classification No. 4 of PSC No. 214 - Traffic
Signals, is energy and delivery-only related. The
charge for this classification does not include the
cost of owning or maintaining facilities and therefore
has not been changed.
The resulting volumetric charges under PSC No. 214 will
be unbundled when customers become eligible for retail
access.
4.14 APPLICATION OF UNBUNDLED PRICES TO NYPA ALLOCATIONS
(a) NYPA Economic Development Power Allocations
The Company agrees to maintain for existing EDP
allocations its existing tariff rates for the
first three years of the settlement. For new
allocations the Company will use its unbundled
rate schedules and the sales will be conducted as
a direct sale from NYPA.
(b) NYPA Rural and Domestic (R & D) Hydro Credit
The benefits of the R & D hydro credit will flow
through to consumers in accordance with the 1990
Contract. NMPC and NYPA agree to work in good
faith to modify as appropriate, the 1990 Contract
to reflect the changes in industry structure.
(c) Table 4-6 delineates the treatment of NYPA
allocations. A "yes" under a column heading means
the charge identified in the column heading
applies to the allocation. A "no" means the
charges shall not apply.
TABLE 4-6 APPLICATION OF UNBUNDLED PRICES TO NYPA ALLOCATIONS (3)
EXIT FEES
-----------------
TRANSMISSION DISTRI-
& BUTION SUPPLY
DISTRIBUTION CTC RELATED RELATED SBC
------------ --- ------- ------- ---
Replacement Power (4) no no no no
445MW
Expansion Power (1) (4) no no no no
250MW
EDP < 46MW (4) no no no no
EDP > 46MW (4) yes yes yes yes
HLFF
Schedule A & First (4) no no no no
50MW Replacement (2)
HLFF above (4) yes yes yes yes
Schedule A & First
50MW Replacement (2)
(d) Notes to Table 4-6:
(1) Except deliveries of EP allocated pursuant to
paragraph 13(b) of Section 1005 of the Public
Authorities Law for revitalization purposes
will be subject to the CTC if and to the
extent that the amount of any allocation when
added to the then existing EP sales in NMPC
service area exceeds 210 MW.
(2) Schedule A as provided for in the Agreement
Among Niagara Mohawk Corporation, New York
Power Authority and Department of Public
Service Resolving and Settling Certain
Disputes, dated May 22, 1997. The first 50MW
of replacement refers to a provision of the
May 22, 1997 agreement that allows the Power
Authority to replace certain HLFF allocation
prior to the PowerChoice Implementation Date.
(3) All rights and responsibilities contained in
the "May 22, 1997 Agreement" shall remain
legally binding in accordance with its terms,
and nothing contained in the PowerChoice
Settlement or this Section shall be construed
to overrule, explain or otherwise modify the
May 22, 1997 Agreement except that in the
event of any conflict between the provisions
of paragraph 5 of the May 22, 1997 Agreement
entitled "Delivery of Expansion and
Replacement Power" and the provisions of this
Section 4.14 and Table 4-6 relating to
Expansion and Replacement Power, the
provisions of this Section 4.14 and Table 4-6
shall prevail. The following abbreviations
apply to Table 4-6: Expansion Power ("EP");
Economic Development Power ("EDP"); High Load
Factor Power ("HLF"); Replacement Power
("RP").
(4) Delivery service for all NYPA Replacement,
Expansion, EDP and HLF Power transmitted and
delivered by NMPC are governed by existing
agreements and/or authorities, provided
however that nothing herein shall be
construed as an admission or agreement by
NMPC or NYPA or any other party that delivery
services provided to new EP, RP or other
customers or modifications of delivery
services provided to existing EP, RP or other
customers shall or shall not be provided
under NMPC's Open Access Transmission Tariff
filed with the Federal Energy Regulatory
Commission and a separate agreement for local
distribution services, and provided further
that nothing contained herein shall be
regarded as a waiver by NMPC of its rate
change rights under any existing agreement
between NMPC and NYPA except as expressly
specified herein.
4.15 ANNUAL TARIFF FILINGS
The Company will file tariff amendments to implement
the initial rates and terms of this agreement as soon
as practicable after the conditions described in
Section 2 have been satisfied. During the term of this
agreement, the Company may make annual tariff filings
to be effective on each anniversary of the PowerChoice
Implementation Date. These annual filings will be made
approximately 120 days prior to their effective date
and will reflect the terms of this agreement including
the pricing design changes, deferrals (years 4-5 only),
the generation sale incentive (years 4-5 only) and
transmission/distribution price escalation.
4.16 RATE FLEXIBILITY
4.16.1 GENERAL
During the term of this Agreement, the Company will
have the right to seek rate changes that are revenue-neutral on
a class average basis. Such rate proposals
will be filed with the Commission and subject to
regulatory approval. The type of changes that may be
proposed include:
a. changes in service class segmentation by
consumption levels, load factors, end-use
purposes, or any other distinguishing factors;
b. reallocation of revenue within classes between
demand, energy and customer charges;
c. reallocation of revenue among customer groups
based on cost-of-service and competitive analyses;
d. additions, deletions or other changes to rate
blocks or rating periods; and
e. changes to establish uniform transmission and
distribution rates across rate classifications
offset, if necessary, by changes to the CTC.
This Agreement will not preclude the Company from
proposing pricing changes in response to competitive
developments.
4.16.2 OPTIONAL RATES AND SERVICES
The initial services contained in this agreement would
be available to all qualified customers for the term of
this agreement. The Company may, additionally, propose
optional rates and/or services at any time. Tariffs
for such rates and/or services would become effective
30 days after they are filed.
4.17 MISCELLANEOUS TARIFF AMENDMENTS
The Company will make amendments to its tariff to
reflect the following issues:
4.17.1 AGGREGATION OF DEMAND AND CUSTOMER CHARGES
Since the prices contained in this Agreement for
service classifications that include demand and
customer charges have been calculated based on
historical non-coincident customer demands, the
aggregation of customers in those service classes
likely would result in the shifting of costs to other
customers or to the Company. ESCos accordingly will
not be permitted to aggregate customers' loads and pay
demand and customer charges based on their coincident
demands. The benefits of load diversity have already
been reflected in the calculation of these charges. It
is not the intent of this Section 4.17.1 to prohibit
ESCos from aggregating the commodity for customers
eligible for retail access.
4.17.2 LOW VOLTAGE BYPASS
Customers may be reconnected to a delivery point at a
higher voltage level at no additional cost to the
customer if in the Company's sole judgment, such
reconnection will alleviate reliability or safety
problems; provided, however, that the Company may
permit such reconnection in other circumstances if the
customer agrees to pay 1) the differential in
distribution charges and CTC, and 2) the incremental
reconnection costs.
SECTION 5.0
CUSTOMER SERVICE BACKOUT CREDIT
The details of a customer service backout credit will be
established by December 31, 1997 through continued
negotiations among the parties, based on agreement on the
following general principles:
5.1 GROSS REVENUE EXPOSURE
The Company's gross revenue exposure attributable to
the customer service backout credit will be limited as
follows:
Year 1 $6M
Year 2 $10M
Year 3 $14M
The Company may defer for future recovery pursuant to
Section 2.4.3 and 2.6 one-half of each dollar of lost
revenue.
If the limits of Company liability and deferrals
outlined above are reached, the backout credit will be
capped, either by numbers of customers, amount of load,
or other method.
5.2 DESIGN PRINCIPLES
(1) Several categories of the backout credit will be
established so that different amounts will be
backed out depending on which services are taken
over by the ESCo. However, there would be a
minimum credit that will be backed out regardless
of the services offered.
(2) The credit could be calculated volumetrically or
per customer.
(3) There will be different levels of the backout rate
by service class.
(4) The Company will provide a study of avoidable
customer service costs by June 1999. Upon
petition of any party after the end of Year 2 of
this agreement, the Commission can revisit the
customer service backout credit, including the
appropriate level of any credit or alternate
mechanisms for handling the movement of customers
to other suppliers (See Section 8.2.8). In any
event, the Company's gross revenue exposure in
year 3 shall not exceed the caps set forth above
in 5.1.
5.3 RELATIONSHIP TO A GENERIC PROCEEDING
If there is a final PSC Order or an order which has not
been stayed pending appeal in a Generic Proceeding
regarding customer services currently provided by
regulated utilities which should be made competitive
and/or the method for determining avoided costs
associated with those services, that Order shall
supersede this agreement. Whether or not there is a
Generic Order regarding customer services, the
Company's gross revenue exposure in years 1-3 shall not
exceed the caps in 5.1. In years four and five the
backout shall not exceed the Company's avoided costs
unless the incremental exposure is offset by other
revenue sources (e.g. deferrals). If there is no
Generic Order regarding competitive customer services,
the Company's study, including comments of other
parties thereon, will provide the basis for determining
the Company's avoided customer service costs in years 4
and 5.
This Agreement does not limit any Party's rights to
challenge or otherwise petition for relief from any
proposed policy in the Generic Proceeding.
SECTION 6.0
SERVICE QUALITY INCENTIVE
There will be a service quality incentive whose total value
is 30 basis points or $6.6 million, where 1 basis point for
both electric and gas will be valued at $220,000 after-tax,
or $338,000 before-tax, for the purposes of this agreement.
All of the amounts reflected below are after-tax dollars.
6.1 CUSTOMER SERVICE PERFORMANCE
For 1998 and beyond, the Customer Service Performance
incentive is equal to a maximum of $3.3 million per
year. The measures of customer service performance
described in this Section 6.1 supersede the provisions
of Section VIII, Customer Service Guarantees set forth
in the Stipulation and Agreement approved by the
Commission in Niagara Mohawk Cases 96-G-1095 and 96-G-0091, Opinion
No. 96-32 (December 19, 1996).
6.1.1 PSC COMPLAINT RATE
The PSC Complaint Rate is the 12-month complaint rate,
measured at each year end. The targets are average
monthly rates of total complaints per 100,000
customers, including collection-related complaints.
The maximum penalty is $1,100K.
RATE INTERVAL MAX. PENALTY WITHIN SCALED INTERVAL
< 10 $0
10.0 - 10.9 $220K
11.0 - 11.9 $660K
12.0 and above $1,100K
6.1.2 CORPORATE RESIDENTIAL TRANSACTION
SATISFACTION INDEX
The Corporate Residential Transaction Satisfaction
Index is the cumulative index of 4 quarterly surveys of
customers who have had transactions with the Company.
It excludes collections transactions. The maximum
penalty is $1,100K.
CSI INTERVAL MAX. PENALTY WITHIN
SCALED INTERVAL
80.0 < or = CSI $0
78.0 < or = CSI < 80.0 $220K
76.0 < or = CSI < 78.0 $660K
CSI < 76.0 $1,100K
6.1.3 LOW INCOME CUSTOMER ASSISTANCE PROGRAM
A Low Income Customer Assistance Program (LICAP)
performance incentive mechanism will be negotiated
prior to December 31, 1997. The mechanism will include
enrollments and energy service targets. The maximum
penalty is $1,100K.
6.2 STATEMENT OF INTENT
There is agreement in principle to consider whether a
program of individual customer service guarantees may
in part or wholly replace the broad-based penalty
measures adopted above, including within the time frame
of this agreement. The Company will continue to work
with Staff on the development of customer service
guarantees as a mechanism for insuring a high level of
customer service. Specifically and initially, the
Company and Staff have a mutual interest in improving
customer convenience and satisfaction with scheduling
of appointments.
6.3 SERVICE RELIABILITY INCENTIVE
The maximum penalty for service reliability performance
is $3,300K.
6.3.1 SYSTEM INTERRUPTION FREQUENCY (SIF)
The maximum penalty for System Interruption Frequency
(SIF) performance is $1,320K. Targets are the number
of outages per customer, excluding major storms.
SIF INTERVAL PENALTY
0.93 < or = SIF $1,320K
SIF < 0.93 $0
6.3.2 CUSTOMER INTERRUPTION DURATION (CID)
The maximum penalty for CID performance is $1,320K.
The targets are the average hours per interruption,
excluding major storms.
CID INTERVAL PENALTY
2.07 < or = CID $1,320K
CID < 2.07 $0
6.3.3 POWER QUALITY
The maximum penalty for Power Quality is $660K.
Targets will be updated annually based on most recent
four year data. Targets displayed below are for 1997.
INTERVAL PENALTY
115KV
-----
294 < or = Momentaries $220K
247 < or = Momentaries < 294 $110K
Momentaries < 247 $0
23-69KV
-------
848 < or = Momentaries $220K
743 < or = Momentaries < 848 $110K
Momentaries < 743 $0
DISTRIBUTION
------------
2095 < or = Momentaries $220K
1951 < or = Momentaries < 2095 $110K
Momentaries < 1951 $0
6.4 ACCOUNTING MECHANISM
Any penalties accrued will be used to offset cost
deferrals.
SECTION 7.0
SYSTEM BENEFITS CHARGE PROGRAMS
7.1 SYSTEM BENEFITS CHARGE
7.1.1 PROGRAMS AND FUNDING LEVELS
The parties agree that the System Benefits Charge (SBC)
applies as follows:
1. The SBC covers programs related to demand-side
management (DSM), Research and Development (R&D),
and low income energy efficiency.
2. Spending levels will be set at $15 million
(approximately 1995 spending levels) for years 1
through 3 with an equal amount removed from base
rates, i.e., spending levels are included within
the pricing (rate) goals in Tables 4-1 and 4-2.
3. The continuation of the SBC and appropriate
funding levels will be revisited in a proceeding
for year 4 notwithstanding the assumptions in
Appendix C.
4. Activities that are integral to RegCo business
functions will not be funded through the SBC.
These include, for example, activities which are
part of a bundled package of services that allow
RegCo to maintain customer satisfaction and
service including outreach, information,
education, dialogue, and customer consultation
programs and other activity that are not within
the scope of the System Benefit Charge as set by
the Commission and the third party administrator.
5. Unexpended SBC funds will be accumulated for
future SBC program use.
6. New programs that the Commission orders or
expansion of existing programs that would increase
spending above the $15 million target will be
passed through to customers outside of the price
caps.
7.1.2 STATE-WIDE, THIRD PARTY ADMINISTRATOR
The Company will propose the use of a state-wide, third
party administrator for DSM and R&D program spending
consistent with PSC policy on the SBC and the other PSC
approved utility settlement agreements. The Company
will work with the parties to accomplish the transition
from the Company-administered programs to a third party
administrator as rapidly as possible, recognizing the
funding that has been committed to certain projects.
RegCo and unregulated affiliates will be allowed to bid
to implement various DSM and R&D projects.
Until a third party administrator is established, the
Company will file a Public Policy Plan annually for
Commission approval. In developing the Public Policy
Plan, the company will establish a Public Policy
Advisory Panel, comprised of representatives from
various constituencies to provide advice and guidance
to program development.
Nothing in this agreement will prohibit the Statewide
administrator from allocating a significant portion of
the total SBC revenues derived from Niagara Mohawk
customers to be disbursed within Niagara Mohawk's
service territory through competitive standard
performance contracts which provide for stipulated
pricing for energy efficiency, consistent with any
generic guidelines for SBC expenditures separately
developed from this proceeding by the PSC.
7.1.3 LOW INCOME CUSTOMER ASSISTANCE PROGRAM
(LICAP)
The energy efficiency portion of the LICAP program will
be funded through the SBC.
7.2 MISCELLANEOUS:
(i) The Company will continue to develop detailed
annual forecasts of transmission and
distribution ("T&D") capital budget
requirements and will identify for each major
T&D project (i.e., projects of $2.5 million
or more), the location, reason for project,
scope of project, projected capital costs,
appropriate load and other data. The Company
will also perform load monitoring consisting
of monitors at a significant sample of the
transmission and area substations scheduled
for expansion/upgrade in the five-year T&D
capital plan. The Company will evaluate and
implement cost-effective measures as
alternatives to major T&D projects that defer
major T&D system projects through the use of
technologies or services that could reduce
peak T&D loads. For such cost-effective
projects, consideration will be given to
technologies or services that minimize the
environmental impacts of electricity usage
including demand side and other new cost
effective technologies (such as wind, solar
and distributed generation) where
practicable. The Company will continue to
seek to minimize costs and environmental
impacts for T&D projects that are not major
T&D projects. The Company will include
testimony in its next rate case discussing
alternatives to transmission and distribution
capital spending, including on site
generation and demand side management
programs and the relationship between current
rate structures, energy efficiency
alternatives and distribution revenues and
profits.
(ii) Plum Street Enterprises or any successor
companies shall offer to all its retail
electric commercial and industrial customers
for-profit energy efficiency services; and
will make a good faith effort to market for-profit energy
efficiency services or products
for all of its residential and small
commercial customers. Plum Street
Enterprises or any successor companies will
offer a green pricing program designed, in
cooperation with interested parties, as a
profit making enterprise to aggregate demand
of customers interested in receiving
electric power from renewable energy
resources (e.g. wind, solar and biomass).
(iii) NMPC agrees to donate 5,000 SO2 allowances to
the Adirondack Council for retirement.
(iv) Niagara Mohawk agrees to donate to the State
of New York, in fee, 1000+ acres of high
intrinsic habitat value lands surrounding
Dead Creek, Town of Piercefield within the
Adirondack Park and commits to negotiate in
good faith with the State of New York for the
sale of a conservation and development right
easement for the remaining 2400+ acres
surrounding Dead Creek (Town of Piercefield).
(v) The Company commits to negotiate in good
faith with the State of New York for the sale
of a conservation and development right
easement for 1000+ acres that are on the west
side of Carry Falls Reservoir. NMPC agrees
to offer to the State of New York fee
interest to 600+ acres on the east side of
Carry Falls Reservoir for a set price of
$258.00 per acre which represents a 50%
donation of our appraisal value. (This
amounts to a donation of $155,000 in value.)
The Company commits to also making the offer
contained in sections 7.1(v) through 7.1(x)
in the Raquette River relicensing
negotiations. In consideration of reaching
a mutually satisfying settlement of the
Raquette River relicensing negotiations, the
Company commits to donate to New York State
fee interest to 600+ acres on the east side
of Carry Falls Reservoir.
(vi) The Company commits to donate to the State of
New York in fee a portion of land at the
southern tip of Carry Falls being a parcel or
parcels of lands of approximately 200 acres
+/-, less any lands necessary for Niagara
Mohawk's FERC Project purposes. (This
amounts to a donation of $92,000 in value.)
(vii) Niagara Mohawk commits to negotiate in good
faith with the State of New York for the sale
of a conservation and development rights
easement for 2200+/- acres of land on the
northern side of Rainbow Falls Reservoir.
(viii) Niagara Mohawk commits to negotiate in good
faith with the State of New York for the sale
of fee interest in the 135 +/-acres on the
easterly and westerly sides of Stark
Reservoir.
(ix) Niagara Mohawk commits to negotiate in good
faith with the State of New York for the sale
of a conservation and development rights
easement for 1639 +/- acres of land
surrounding Blake Reservoir.
(x) Niagara Mohawk commits to negotiate in good
faith with the State of New York for the sale
of a conservation and development rights
easement for a 1943 +/- acres of land on Five
Falls and South Colton Reservoir.
(xi) The Company will develop 10 MW of wind power
generation and 1.6 MW of photovoltaic
generation that will be funded through
available third party funds/grants and the
SBC funding provided for in this agreement
(See Section 7.1.1). The SBC funding will be
based on the debt service of the cost of the
facilities in excess of third party funding,
subject to an amortization schedule within
the five years of the Agreement. Any
electricity produced from these facilities
will be sold to a third party marketer for
resale under a competitive bidding process
designed to attract purchasers engaged in
green pricing offers in the retail market.
At the end of the fifth year, the Company
will seek bids to sell these facilities to
the market. Any proceeds from the sale of
the electricity and the sale of the
facilities will go to fund future SBC
projects. T&D facilities constructed to
connect these projects to the system will be
amortized over the projected life of the
projects and recovered as part of the project
cost during the first five years of this
Agreement and as part of T&D revenue
requirements after the first five years.
Nothing in this paragraph shall limit the
third party administrator's ability to
override this provision.
(xii) A portion of the SBC will be used to fund
existing long-term ecological monitoring
programs such as the Adirondack Lake Survey
(ALS). The parties expect that these
activities will be funded by the Statewide
SBC administrator in proportion to
contributions from each utility. In the
event that other utilities' SBC funds are not
available, then funding sufficient to
continue the ALS shall be made available from
the SBC established in this agreement (not to
exceed 5% of available funds). Nothing in
this paragraph shall limit the third party
administrator's ability to override this
provision.
(xiii) The Company will continue to offer
information to all customers regarding
available energy efficiency services (e.g.,
bill stuffers and referrals to companies
offering energy audits and other services)
and facilitate customer access to energy
efficiency products and services available in
the market by third party product vendors and
service providers (e.g., by arranging
manufacturers' rebates). These activities
shall be carried out in a manner which does
not give preferential treatment to any energy
service provider.
(xiv) The Company will support legislation or state
agency rulemaking which would upgrade New
York State building codes to meet the 1995
Model Energy Codes and ASHRAE Standard 90.1.
The Company believes that the implementation
of such legislation or state agency
rulemaking should consider the economic
impact to the State of New York of the
building codes.
(xv) The Company will support the inclusion of
environmental protection provisions in
federal utility restructuring legislation,
insofar as congressional consideration of
such provisions does not unduly delay
progress toward creating a deregulated and
open competitive market for electricity in
the United States. With regard to such
environmental measures:
a) The Company will support establishment
of a national system benefits trust
(national wires charge), with the
understanding that such a trust would
not be constituted in a manner which
would competitively disadvantage
companies in a state that has
established a parallel, state-level
system benefits charge.
b) The Company will support nationwide
"environmental comparability"
requirement for fossil generating units
for nitrogen oxides (NOx) emissions
(i.e., a uniform generation performance
standard implemented in combination with
an emissions "cap and trade" program),
with the understanding such a standard
would apply uniformly throughout the
entire United States and with the
understanding such a standard would be
phased in so that its imposition would
not unreasonably devalue current fossil
generation assets.
c) The Company will support national
environmental disclosure requirements
for emissions that would apply to all
energy retailers, with the understanding
such disclosure requirements would be
practical and not unreasonably
burdensome to administer. Niagara
Mohawk recognizes that in a competitive
market, some retailers may choose to go
beyond the minimum requirements with
respect to characterizing the
environmental aspects of the energy they
provide.
d) The Company will support a clean energy
portfolio standard that requires all
vendors to have a minimum amount of
renewables and other non-emitting or
ultra low emitting (e.g., fuel cells)
energy sources in their generating mix
and that avoids unintended and
undesirable economic incentives; i.e.,
the Company will support a standard that
would prevent any bypass of the
requirement and utilizes a renewable
energy credits purchase provision.
(xvi) The Company and Staff agree that customer
choice would be enhanced by the availability
of environmental information concerning the
power being provided to them. To effectuate
such disclosure, the Company and Staff agree
to work with load serving entities and others
to develop and implement, where feasible,
meaningful and cost-effective, an approach to
providing customers with fuel mix and
emission characteristics of the generation
sources relied on by the load serving entity.
Such an approach would facilitate informed
customer choice, promote resource diversity
and improve environmental quality.
(xvii) To the extent the accounting for such
revenues is not otherwise provided herein,
all revenues derived from sales will be
accounted for in accordance with the Uniform
System of Accounts.
SECTION 8.0
RETAIL ACCESS
8.1 CONDITIONS NECESSARY FOR RETAIL ACCESS
In addition to other conditions described in this
agreement, retail choice depends upon proper metering
and appropriate billing and settlement procedures.
8.1.1 PROPER METERING
As described in Section 8.3, it is essential that
proper metering, meter reading and billing be performed
to insure the integrity of the new retail access
system. In addition, the parties agree that customers
will pay all incremental costs associated with these
requirements as provided by Niagara Mohawk.
8.1.2 BILLING AND SETTLEMENT PROCEDURES CONSISTENT
WITH MARKET
Billing and settlement procedures that are consistent
with the demands of the market must be established.
Niagara Mohawk will prepare its settlement and billing
system to accommodate retail access within a wholesale
electricity market and bulk power transmission system
operated by an independent system operator and one or
more power exchanges. The billing and settlement
system described in Section 8.3 supporting the retail
access schedule will be designed and developed to
function within the market structure proposed by the
member systems of the New York Power Pool in their
January 31, 1997 FERC filing.() The FERC proceeding
to review this filing is in progress and the timing of
a decision is therefore uncertain.
Until the ISO and the other new market institutions are
in operation, RegCo will develop methods to facilitate
wholesale settlement with marketers and ESCos within
the framework of the New York Power Pool. When the new
institutions are in place, RegCo will modify its
settlement approaches to ensure consistency with the
new market environment. In the event that key features
of the market structure are modified substantially from
those proposed in the filing, the Company reserves the
right to petition the Commission for approval to adjust
the schedule for retail access to permit corresponding
changes to be incorporated into the billing and
settlement systems. Key features include, but are not
limited to, the two settlement system, locational based
marginal pricing and the ISO Open Access Transmission
Tariff.
8.2 RETAIL ACCESS TIMETABLE
Retail access for customers in Niagara Mohawk's service
territory will be offered on a schedule shown in Table
8-1. As described below, customers will receive access
in several phases.
8.2.1 FARM & FOOD PROCESSOR (DAIRYLEA) PILOT
On February 25, 1997 the Public Service Commission
issued an order () to Niagara Mohawk and three other
utilities to develop retail access programs for
commercial farms and food processors. In response to
that order, on April 11, 1997 NMPC filed its proposal
(), including a draft tariff. On June 23, 1997, the
Commission issued an order () to implement the
program, requiring a tariff filing by August 4, 1997
and the commencement of retail deliveries by November
1, 1997. On September 18, 1997 the Commission issued
an additional order directing certain changes to the
August tariff filing. ()
The Company's plan to introduce retail access has been
designed to accommodate the Farm & Food Processor
(F&FP) pilot program. Table 8-1 includes the F&FP
program for illustrative purposes only. If
implementation of the F&FP program is delayed due to
rehearing, litigation, or other causes, the timetable
for retail access for other customers will not be
affected.
Reflecting the Commission's desire for expedited
implementation, the F&FP proposal utilizes methods that
Niagara Mohawk does not necessarily propose to use when
retail access is extended to its other customers. The
Company does not view the methods used for the pilot as
precedent-setting or binding in any way.
Customers participating in the F&FP program will be
offered the option to be removed from the pilot and
served under the full retail access program when other
customers of their rate class, size, and voltage
delivery become eligible for retail access.
It is the intent of the Parties that this agreement and
the Dairylea Pilot fulfills the obligation of the
Company in cases 94-E-0385 et al. and 95-E-0924.
8.2.2 GROUP 1
Group 1 consists of all customers in rate class SC-3A
served at transmission voltages (greater than 60 kV),
plus customers in rate class SC-4 served at
transmission voltages with demands served by Niagara
Mohawk of 2 MW or more. The timing of retail choice
for these customers will be no later than one month
after the PowerChoice Implementation Date.
8.2.3 GROUP 2
Group 2 consists of all remaining SC-3A and SC-4
customers with peak demands of 2 MW or more. The
timing of retail choice for these customers will be no
later than seven months after the PowerChoice
Implementation Date.
8.2.4 GROUP 3
Group 3 consists of all remaining customers served at
transmission and subtransmission voltage levels (22 kV
and above). This group will become eligible no later
than May 1, 1999.
8.2.5 GROUP 4
Group 4 consists of all remaining residential customers
not already participating in the Farm and Food
Processor pilot program. Retail access for these
residential customers will begin no later than April 2,
1999, and will be completed no later than December 31,
1999. All parties agree to work on a good faith basis
during 1998 to develop a residential phase-in plan,
which includes processes and procedures that achieve as
smooth and workable a transition as possible, taking
into account different ways to resolve the POLR
obligation, and the desire to minimize financial impact
on the Company, ensure customer satisfaction, and
address the needs of marketers and ESCos. The plan
will be completed by December 31, 1998. As part of the
residential retail access phase-in plan, the Company
commits to developing, in consultation with other
parties, and implementing an outreach and education
program to help residential customers understand and
act upon their right to choose their energy supplier.
The Company reserves the right to conduct a pilot of
retail access in a defined geographic area, but, if it
chooses to do so, the pilot will not have the effect of
delaying the schedule for residential customers, nor
will it delay the possibility for earlier access for
residential customers.
8.2.6 GROUP 5
Group 5 consists of all remaining non-residential
customers except for 25 cycle customers. These
customers will receive retail access no later than
August 1, 1999. If the Company chooses to conduct an
area pilot, this date will not be affected, nor will
the pilot delay the possibility of earlier access for
this group of customers.
8.2.7 CUSTOMERS WITH SPECIAL CONTRACTS
Unless otherwise provided for in their contracts,
customers with special contracts will become eligible
for retail access when the later of the following
occurs: (a) the customer groups to which they belong
become eligible (as shown in Table 8-1), or (b) their
contracts expire.
8.2.8 MONITORING PROGRESS THROUGH TIME
Over the longer-term, all parties agree to work
together on a good faith basis during 1998 and 1999 to
evaluate the response of customers to retail access,
both here and in other areas, to determine whether the
transition process is working well or should be
modified. Alternatives that could be considered
include but are not necessarily limited to: (i)
alternative ways of satisfying the POLR responsibility,
(ii) whether a fixed CTC option should be offered to a
larger number of customers, (and, in particular,
whether a fixed CTC is needed for residential
customers), (iii) whether a mandatory balloting process
should be employed to require customers to choose their
supplier, and (iv) the mandatory assignment of
customers to alternate suppliers. The parties will
also consider whether a viable competitive market
exists, including a fully functioning ISO.
8.2.9 CONTINGENCIES
The dates for initiating access for residential and
small non-residential customers are not formally linked
to having an operational statewide Independent System
Operator (ISO). However, the Company retains the right
to petition the Commission to alter the schedule if the
ISO that is ultimately implemented differs
substantially from the proposal filed with FERC on
January 31, 1997 by the members of the New York Power
Pool, and if implementing the revised ISO proposal on
the current schedule would likely cause serious
implementation problems (such as major cost shifting or
mass confusion). In addition, the dates for retail
access for customers in groups 3, 4 and 5 are
contingent upon timely receipt of regulatory approvals
from the PSC. (A delay of several months should not
affect the residential and small non-residential access
timetable unless such a delay affects the ability of
the Company to implement the MRA and the overall
settlement.)
8.3 RETAIL ACCESS SETTLEMENT METHOD
To enable retail access within its service territory,
RegCo will develop a billing and settlement system that
will provide the following features. These features
will be modified as necessary to comply with any
Commission orders regarding billing and metering in a
restructured market environment but this Agreement does
not limit any Party's rights to challenge or otherwise
petition for relief from any proposed policy in the
Generic Proceeding.
- RegCo will bill customers taking service from its
transmission and distribution systems for services
provided by the Company.
- ESCos will have the option of billing their
customers directly for the services they provide,
or requesting RegCo to provide billing services
for them for a fee.
- ESCos will be able to arrange physical bilateral
purchases with wholesale suppliers, and RegCo will
handle the scheduling of these transactions with
the NYPP or ISO, as the case may be at different
points in time.
- ESCos will be able to purchase power from the spot
markets, as administered by power exchanges and/or
the ISO, and RegCo will provide any ESCo
interfaces that may not otherwise be accommodated
by these institutions.
- All charges incurred by RegCo as a consequence of
its role in providing interfaces for ESCos with
power exchanges or the ISO shall be passed along
to the ESCos responsible for those costs. This
includes any charges or costs for losses (),
transmission services, ancillary services,
balancing, uplift, transmission congestion rents,
etc.
- RegCo will meter or determine through load shape
methods all customer loads by hour, location, and
voltage for the purposes of determining total load
for each ESCo by those categories. Loads for
customers receiving power directly from RegCo will
be determined in the same method to ensure that no
cross-subsidization occurs.
- RegCo will be permitted to include reasonable
charges for the services it provides in the
administration of the retail access system. These
charges will be included in the tariffs filed by
the Company, implementing the terms of this
Settlement Agreement.
Figure 8-1 illustrates the approach RegCo intends to
take in performing these functions. Should the
statewide ISO and/or power exchanges, when operational,
provide settlement services that enable ESCos to
interact directly with those institutions, RegCo will
modify or discontinue use of those features of this
settlement system as appropriate.
8.3.1 FORECASTING AND SCHEDULING REQUIREMENTS
ESCos or their agents will be required to submit to
RegCo at least a day in advance (or multiple days in
advance for weekends and holidays) hourly bilateral
scheduled deliveries including the source of generation
supply and location of the load being supplied. When
the power exchanges and the ISO are operational, ESCos
will also be required to provide hourly load forecasts,
and specify what portion of their forecasted loads
should be served from the day-ahead energy market.
RegCo will accommodate load management bids provided by
ESCos to the extent possible within the bidding
provisions of the power exchanges and the ISO.
8.3.2 METERING REQUIREMENTS
In order to facilitate retail access, all customers in
classes SC-3 and above will be required to have a meter
whose capabilities are at least equivalent to a single
directional meter with a recorder capable of
registering hourly (or shorter) integrated readings
(interval metering), whether or not they choose an
alternate supplier. The incremental costs of metering
will be borne by these customers.
All other customers will be permitted to continue to
utilize existing kWh meters. For settlement purposes,
RegCo will use load shapes applicable to the customer's
class to estimate hourly usage. Since load shapes have
not been used in RegCo's area for this purpose, the
company reserves the right to modify the specific
techniques as necessary to attain reasonable and
accurate results. Customer classes may be subdivided
if deemed necessary to ensure that representative load
shapes are applied. Any customer not otherwise
required to have interval metering may request that
interval metering be installed provided that the
customer bears the incremental costs of such metering.
RegCo will adjust its methodology for the application
of load shapes and/or interval meters as necessary
based on experience, and in conformance with Commission
orders resulting from the ongoing metering and billing
efforts in the Competitive Opportunities Proceeding.
In the event that meter availability or installation
resources result in some customers in the SC-3 class
not having hourly metering at the time they otherwise
would become eligible for retail access, access will be
permitted and load shapes utilized on an interim basis
until the metering is in place.
8.3.3 SERVICES NOT COVERED BY THE SETTLEMENT SYSTEM
Certain services acquired by ESCos will not be included
in the settlement system. RegCo will not be involved
in payments between ESCos and generators for bilateral
transactions between them. The ISO may have installed
reserve requirements that all load serving entities
must fulfill; RegCo does not intend to serve as a
broker for the acquisition of installed capacity for
ESCos (although ESCos will be free to separately
negotiate for purchase of installed capacity from
Niagara Mohawk or its subsidiaries, if desired). In
general, RegCo does not intend to include in its
settlement system any service for which appropriate
billing and payment methods are available directly
between supplier and ESCo.
8.3.4 NONDISCRIMINATORY TREATMENT OF CUSTOMERS
RegCo will implement the curtailment procedures of NYPP
or the ISO (as applicable) consistent with its existing
transmission arrangements and will not discriminate
between those bilateral transactions serving ESCo
customers and those serving RegCo customers.
RegCo will conform to all operating criteria and
guidelines established by the ISO and the PSC. RegCo
will not discriminate in any way in providing reliable
service to customers that receive energy supply from
RegCo or those that are supplied from ESCos. Customers
of RegCo and customers of ESCos will be subject to the
same emergency load curtailment provisions.
8.3.5 AUDITING OF THE SETTLEMENT FUNCTION
To ensure that the settlement functions performed by
RegCo to facilitate retail access are being performed
in accordance with appropriate procedures that treat
all market participants equitably, audits of these
functions may be performed under the direction of the
PSC. The scope of these audits shall be limited to
those functions and procedures related to the
determination and assessment of charges to the ESCos
obtaining retail access through RegCo. All audits
shall be performed either by the Staff of the PSC, or
by an independent auditing firm with a national
practice selected by the PSC.
Any incremental costs associated with the auditing of
the settlement functions that are incurred by RegCo
shall be borne by all ESCos serving retail load
through RegCo's retail access framework, and RegCo
itself, in proportion to the total energy served by
these entities in the three-month period preceding the
commencement of the audit. Incremental costs shall
include auditor costs invoiced directly to RegCo,
auditor costs invoiced separately to RegCo by the PSC,
and any RegCo costs incurred specifically in response
to audit requirements.
All data provided for audit purposes to the PSC or to
another auditor shall be regarded as confidential and
shall not be disclosed to any market participant, or to
the general public, unless such data is already
accessible to the public through separately established
regulations or procedures except as otherwise decided
by the Commission or its records access officer. Audit
reports and findings, excluding confidential data,
shall be made available to all market participants and
the general public.
8.4 Reciprocity Assurances
Full retail access in Niagara Mohawk's service
territory may occur before comparable access is
available in other electric utilities' service
territories. Other energy service providers may gain
access to customers in Niagara Mohawk's service
territory before Niagara Mohawk is able to gain
comparable access to customers in other electric
utilities' service territories. If there is such a
disparity in the companies' relative degrees of access,
Niagara Mohawk is concerned that it could experience
substantial financial disadvantage. However, as part
of this settlement, the Company agrees there will be no
restrictions on commodity sales to retail customers
unless the Company petitions the Commission for relief
and the Commission approves the restriction.
TABLE 8-1 RETAIL ACCESS PHASE-IN SCHEDULE AND STATISTICS
SALES
TIMING REVENUE --------------------------
OF --------------- CUMULATIVE
NUMBER OF RETAIL % OF % OF % OF
GROUP CUSTOMERS CHOICE $MILLIONS TOTAL MWH TOTAL TOTAL
- -------------------------------------------------------------------------------------
FARM & FOOD
PROCESSOR PILOT
Commercial
Farms (1) 22,237 41.8 1.4 384,025 1.3
11/1/97
Food Processors (2) 589 44.0 1.4 479,000 1.7
- -------------------------------------------------------------------------------------
F&FP Pilot Total 22,826 85.9 2.8 863,025 3.0 3.0
- -------------------------------------------------------------------------------------
GROUP 1
Tramission level 98 t+1 mo. 348.0 11.2 4.590,144 16.0 19.0
SC-3A and SC-4
customers (3)
- -------------------------------------------------------------------------------------
GROUP 2
All remaining 158 t+7 mo. 213.7 6.9 2,517,270 8.8 27.8
customers > 2 MW
- -------------------------------------------------------------------------------------
GROUP 3
All remaining 229 68.8 2.2 800,879 2.8 30.6
transmission and 5/1/99
subtransmission
level customers (4)
- -------------------------------------------------------------------------------------
GROUP 4 Phased in,
All remaining 1,402,657 4/2/99 1,200.1 38.8 9,440,920 32.9 63.5
residential through
customers 12/31/99
- -------------------------------------------------------------------------------------
GROUP 5
All remaining 149,706 1,179.2 38.1 10,482,296 36.5 100.0
non-residential 8/1/99
customers (5)
- -------------------------------------------------------------------------------------
TOTALS 1,575,674 3,095.6 100.0 28,694,534 100.0 100.0
/TABLE
NOTES ON TABLE 8-1
Statistics are based on 1998 forecast data. Revenue
estimates reflect Base Rate for 1998.
Customers with special contracts will not become eligible
until expiration of their contracts. The table estimates do
not reflect possible delayed eligibility due to special
contracts.
t = The PowerChoice Implementation Date
1. Rough estimates based on full participation of all
customers currently shown in Company records as farms.
Actual participation is likely to be lower; however,
the Company does not have sufficient data to more
accurately predict actual eligibility or participation
prior to program implementation.
2. Assumes eligibility and participation of all customers
with SIC codes of 2000 to 2099; special contract rates,
economic development discounts, or optional pricing
schedules may make some customers ineligible.
3. SC-4 customers must also have 2 MW of NMPC demand to
qualify. Transmission level is above 60 kV.
4. Subtransmission level is above 22 kV.
5. Excludes 25 Hz Cycle customers.
SECTION 9.0
CORPORATE STRUCTURE AND AFFILIATE RULES
9.1 PROPOSED CORPORATE STRUCTURE
Niagara Mohawk shall separate its existing operations,
as indicated below or as described in any petition
filed by Niagara Mohawk within one year of the approval
of this settlement proposing the formation of a holding
company in substantially the same structure described
below:
HOLDCO: The HoldCo may be, at the Company's
option, a legally distinct entity that directly
owns no state or federal jurisdictional assets
and, therefore, is unregulated or a functionally
separate unit serving the same purposes of a
holding company.
REGCO: RegCo shall be a wholly owned subsidiary
of HoldCo or a utility parent owning in whole or
in part one or more regulated and/or unregulated
subsidiaries. The RegCo shall carry on the full
range of Niagara Mohawk's regulated transmission
and electric and gas distribution services. To
the extent not carried on through a statewide
nuclear operating company and subject to the other
provisions of this settlement regarding nuclear
assets, Niagara Mohawk's nuclear operations may
remain a part of RegCo.
PLUM STREET ENTERPRISES/UNREGULATED AFFILIATES:
Niagara Mohawk may form unregulated or lightly
regulated affiliates, which may be owned, in whole
or in part, by HoldCo or may be a subsidiary of a
utility parent under either proposed corporate
structure. If Niagara Mohawk seeks to form
subsidiaries of RegCo, it will be subject to all
applicable regulatory requirements including
Section 107 and 69 of the Public Service Law.
TRANSITION GENCO: Niagara Mohawk may form all
subsidiaries necessary to effectuate the fossil
and hydro asset auction contemplated in this
settlement. Prior to that auction, Niagara Mohawk
may maintain its current functional unbundling of
its fossil and hydro generation business.
9.2 RULES GOVERNING AFFILIATE TRANSACTIONS
9.2.1 ORGANIZATION
9.2.1.1 SEPARATION AND LOCATION
RegCo, HoldCo, and the HoldCo's other subsidiaries
will each be operated as separate entities and
will maintain separate books and records of
account. HoldCo's unregulated subsidiaries and
RegCo will operate from physically separate
buildings. RegCo and HoldCo may occupy the same
building.
9.2.1.2 BOARD OF DIRECTORS MEMBERSHIP AND
FIDUCIARY DUTY
A majority of the RegCo Board of Directors will be
Outside Directors (i.e., neither an officer nor
director of HoldCo or any HoldCo unregulated
affiliate).
In any calendar year RegCo will limit dividends
paid to HoldCo as follows:
DIVIDEND LIMITATION: NET INCOME AVAILABLE
YEARS FOR COMMON DIVIDENDS PLUS:
1998 $ 50 million
1999 $ 75 million
2000 $100 million
2001 $100 million
2002 $100 million
2003 $ 80 million
2004 $ 60 milion
2005 $ 40 million
2006 $ 20 million
2007 and beyond $ 0
The calculation of net income will exclude any
one-time, non-cash accounting charges, and will
exclude any one-time dividends to HoldCo
attributable to major transactions such as asset
sales, the transfer of generating assets
associated with HoldCo and subsidiary formation as
necessary to implement the terms of this
settlement, or securitization.
Notwithstanding the above, if the Company files
for rates for years 2003, 2004, 2005, 2006, or
2007, the measure for the dividend limitation will
be reassessed in the context of the rate filing.
9.2.1.3 COST ALLOCATION
Appropriate cost allocation procedures will be
followed by HoldCo and its affiliates to assure
the proper allocation on a fully distributed
basis, to HoldCo, RegCo, PSE or other affiliates
of the costs of any HoldCo personnel, property or
services used by RegCo or other affiliates or
HoldCo.
A complete manual of cost allocation guidelines
will be developed and filed with the Director of
the Office of Accounting and Finance of the
Department of Public Service. All amendments and
supplements to these guidelines will be filed
thirty days prior to the effective date of such
amendments and supplements. The cost to develop
these guidelines, accounting, auditing and
monitoring systems for affiliates will be paid by
shareholders.
9.2.2 TRANSFER OF NON-GENERATION ASSETS
Transfers of non-generation assets (or rights to use
such assets) from RegCo to an affiliate will be priced
at the higher of book value or fair market value.
9.2.3 TRANSFER OF SERVICES
RegCo may provide tariffed and corporate services (such
as corporate governance, administrative, legal and
accounting) to HoldCo and HoldCo's other subsidiaries.
The provision of corporate services shall be subject to
a written contract that, as applicable, identifies the
personnel, assets, and services which will be provided.
The services will be provided on a fully loaded cost
basis. Such services may be provided by RegCo so long
as RegCo's total assets are equal to or greater than
85% of the consolidated total assets of HoldCo.
At such time as RegCo's total assets are less than 85%
of the consolidated total assets of HoldCo, corporate
services may not be provided by RegCo to HoldCo and its
other subsidiaries; however, HoldCo may provide
corporate services to RegCo and its other subsidiaries
at any time provided that such services are priced at
not higher than fully loaded cost and are pursuant to a
written contract that, as applicable, identifies the
personnel, assets, and services to be provided. RegCo
will not purchase any other products or services from
HoldCo or its unregulated affiliates unless these are
purchased as a result of a fair and open competitive
bidding process.
To the extent that the Company does not move the
function to RegCo, the existing Energy Services and Gas
Services contracts with Plum Street will be subject to
a fair and open competitive bidding process by December
31, 2000, or at the renewal or expiration dates of the
current agreements, whichever is earlier. Any such
contract will be filed with the Public Service
Commission in accordance with Public Service Law
Section 110. The Company will meet with Staff to
determine which, if any, functions should return to
RegCo. Furthermore, any generic order regarding the
provision of these services will supersede this
agreement.
The RegCo, the HoldCo and the unregulated affiliates
may be covered by common property/casualty and other
business insurance policies. The costs of such
policies shall be allocated among the RegCo, the HoldCo
and the unregulated affiliates in an equitable manner
as defined in the cost allocation manual.
9.2.4 SPECIAL SERVICES
The Company through RegCo will not provide or offer to
provide services to customers that are normally
provided by Energy Services Companies (ESCos) such as
energy audits, energy efficiency equipment, etc.
without prior Commission approval except as provided
for in Section 7.2 (xiii). The Company will be allowed
to provide operation, maintenance and construction
services to customer's equipment at a customer's
explicit request that is related to energy delivery
services (Rule 28 of P.S.C. 207). Any such services
provided by the Company will be subject to the
following:
(1) Under no circumstances will such customer-requested services provided
by RegCo to individual customers impose a cost on other utility
ratepayers. Customers will be charged fully
loaded rates for these services.
(2) The Company will provide these services on a
first-come, first-served basis to customers who
request them on non-discriminatory terms and
conditions, i.e., similarly situated customers
would be charged the same rates.
(3) The Company will make customers aware if there are
other entities that may be able to provide the
requested services.
(4) The utility will maintain records relative to all
such services, including scope of work, copies of
customer requests including acknowledgment that
the customer was aware of alternate suppliers,
revenues received, any profits made as a result of
providing the services, and identifying any direct
or indirect benefits to other ratepayers that the
Company estimates was derived from the provision
of the service.
(5) The Company will provide the Commission in Year 3
an analysis of the impact of the Company providing
such service and the Commission will then decide
if the Company will be allowed to continue the
provision of such services.
(6) RegCo will not hire any additional employees or
purchase additional equipment in order to provide
these services.
To the extent the Company's current or planned
provision of the services described above requires
Commission authorization pursuant to Public Service Law
Section 107, that authorization is in the public
interest and in approving this settlement, the
Commission thereby grants that authorization for the
term of this settlement.
9.2.5 HUMAN RESOURCES
9.2.5.1 SEPARATION OF EMPLOYEES AND OFFICERS
RegCo and the unregulated subsidiaries will have
separate operating employees. Operating officers
(i.e., those officers providing other than
corporate services) of RegCo will not be operating
officers of any of the unregulated subsidiaries.
Officers of HoldCo may be officers of RegCo or an
unregulated affiliate, provided that a HoldCo
officer may not be an officer of both RegCo and an
unregulated affiliate.
9.2.5.2 EMPLOYEE TRANSFERS
If a RegCo employee accepts a position with an
unregulated subsidiary, he or she will be required
to resign from RegCo unless there is a conflict
with the collective bargaining agreement in which
case the collective bargaining agreement would
control. Any such employee shall be prohibited
from copying or taking any non-public customer or
competitively sensitive market information from
RegCo.
Employees may be transferred from RegCo to an
affiliate. Transferred employees may not be
reemployed by RegCo for a minimum of one year
after transfer. Employees returning to RegCo may
not be transferred again to an unregulated
affiliate for a minimum of one year. RegCo will
file annual reports to the Commission, beginning
45 days after the end of the first calendar
quarter following formation of HoldCo showing
transfers between RegCo and unregulated affiliates
by employee name, former company, former position,
new company, new position, and salary or
annualized base compensation. There will not be
any temporary employee transfers between RegCo,
HoldCo and any HoldCo unregulated affiliates.
9.2.5.3 EMPLOYEE LOANS IN AN EMERGENCY
The foregoing provisions in no way restrict any
affiliate from loaning employees to RegCo to
respond to an emergency that threatens the safety
or reliability of service to consumers.
9.2.5.4 COMPENSATION FOR TRANSFERS
An employee transfer credit equal to 25% of the
employees salary will be applied to reduce any
stranded costs. This fee will apply for all
transfers except for (i) the initial transfer of
RegCo employees to HoldCo on or within the 30 days
after the formation of HoldCo, (ii) the transfer
of RegCo employees from one regulated subsidiary
to another regulated subsidiary, (iii) the
transfer of RegCo employees to an affiliate if
their function is no longer regulated, (iv) any
represented or other employee covered by a
collective bargaining agreement targeted by a
layoff in the one year following the
implementation date of PowerChoice, and (v) the
transfer of employees involved in the performance
of corporate services to HoldCo when RegCo no
longer constitutes more than 85% of HoldCo's
assets as per section 9.2.3. Transfer charges for
employees transferred to Plum Street to date are
reflected in rate levels.
9.2.5.5 EMPLOYEE COMPENSATION AND BENEFITS
The compensation of RegCo employees may not be
tied to the performance of any of the unregulated
subsidiaries, provided, however, that stock of the
HoldCo may be used as an element of compensation
and the compensation of common officers of the
HoldCo and RegCo may be based upon the operations
of the HoldCo and RegCo.
Employees of HoldCo, RegCo and the unregulated
subsidiaries may participate in common pension and
benefit plans.
9.2.5.6 LEGAL REPRESENTATION
The affiliates of HoldCo other than RegCo and
Canadian Niagara shall have their own Chief Legal
Officer/General Counsel, who shall report to the
affiliate's management and not be an employee or
officer of RegCo. The same law firm may represent
RegCo and any affiliate on any matter other than
transactions between RegCo and that affiliate. On
any matter not involving such an intracorporate
transaction in which the interests of RegCo's may
be adverse to the interests of an affiliate, RegCo
will take appropriate steps to ensure that RegCo's
interests are vigorously and independently
protected (such steps, by way of example and not
limitation, could include having separate
attorneys if a single law firm is used and
creating a Chinese wall between such attorneys).
With respect to all matters handled by outside
counsel, HoldCo and its affiliates shall instruct
outside counsel to take all reasonable steps to
ensure the non-public customer and competitively
sensitive information in the possession of RegCo
is not communicated to an affiliate.
9.2.6 MAINTAINING FINANCIAL INTEGRITY
Niagara Mohawk will agree to the following financial
restrictions: (i) RegCo assets will not be used as
collateral for affiliate debt; and (ii) debt and equity
requirements will be established for RegCo through the
regulatory process. RegCo will not provide any
financial assistance to its affiliates through loans,
loan guarantees, letters of credit or other
commitments.
Nothing in these restrictions will prevent Niagara
Mohawk from transferring funds from its Opinac
affiliate to any other affiliate at any time without
Commission authorization.
9.2.7 ACCESS TO BOOKS, RECORDS AND REPORTS
Staff will have full access, on reasonable notice, and
subject to resolution of confidentiality and privilege
(e.g., attorney client, attorney work product, self
critical) issues, to: 1) the books and records of
HoldCo and the HoldCo majority owned subsidiaries; and
2) the books and records of all other HoldCo
subsidiaries to the extent necessary to audit and
monitor any transactions which have occurred between
the RegCo and such subsidiaries.
9.2.8 REPORTING
Annually, RegCo will file reports on: Transfers of
assets, cost allocations, employee transfers and
employees in common benefit plans. Quarterly, HoldCo
will file a list of all SEC filings with the
Commission.
9.3 STANDARDS OF COMPETITIVE CONDUCT
The following standards of competitive conduct shall
govern RegCo's relationship with any unregulated
affiliates.
9.3.1 USE OF CORPORATE NAME AND ROYALTIES
The rate plan in this settlement shall be in lieu of
any and all "royalty" payments that could or might be
asserted to be payable by any affiliate or imputed to
the RegCo or credited to RegCo customers at any time,
including after the expiration of this settlement.
There are no restrictions on any affiliate using the
same name, trade names, trademarks, service names,
service marks or a derivative of a name of the HoldCo
or RegCo, or in identifying itself as being affiliated
with the HoldCo or RegCo.
Promotional material may identify the affiliate as
being affiliated with RegCo or HoldCo.
9.3.2 SALES LEADS
RegCo will not provide sales leads involving customers
in its service territory to any affiliate.
9.3.3 CUSTOMER INQUIRIES
If a customer requests information about securing any
service or product offered by ESCos, the RegCo may
provide a list of all known ESCos operating in the area
which may include its unregulated affiliate.
9.3.4 NO ADVANTAGE GAINED BY DEALING WITH AFFILIATE
RegCo will refrain from giving any appearance that
RegCo speaks on behalf of an affiliate or that an
affiliate speaks on behalf of the RegCo. RegCo will
not participate in any joint promotion or marketing
with its affiliates.
The RegCo will not represent to any customer, supplier
or third party that an advantage may accrue to such
customer, supplier or third party in the use of the
RegCo's services as a result of that customer, supplier
or third party dealing with any affiliate.
RegCo's affiliates will not represent to any customer,
supplier or third party that an advantage may accrue to
such customer, supplier or third party in the use of
the affiliate services as a result of that customer,
supplier or third party dealing with RegCo.
These provisions do not restrict the use of the name of
HoldCo or RegCo as set forth in Section 9.3.1.
9.3.5 NO RATE DISCRIMINATION
All similarly situated customers, including ESCos and
customers of ESCos, whether affiliated or unaffiliated,
will pay the same rates for the RegCo's utility
services. If there is discretion in the application of
any tariff provision, RegCo must not offer its
affiliate more favorable terms and conditions than it
has offered to all similarly situated competitors of
the affiliate.
9.3.6 FERC JURISDICTION
Transactions subject to FERC's jurisdiction will be
governed by FERC's orders or standards as applicable.
9.3.7 CUSTOMER INFORMATION
RegCo will provide 24 months of a customer's data to
that customer or its authorized ESCo at no charge,
except as provided by law consistent with the
Commission orders in the Generic Proceeding related to
Metering and Billing (94-E-0952). Additional customer
billing information will be provided to a customer for
a reasonable fee to be established pursuant to a
tariff. If the Company releases other information, it
will do so for a fee and on a non-discriminatory basis.
9.3.8 OTHER INFORMATION
Other customer or market information in the Company's
possession will be released as necessary, as authorized
or required under FERC and PSC regulations, subject to
protection of confidential information and recovery of
attendant costs. RegCo will not disclose to any
affiliate any market information relative to its
service territory, which is not otherwise public, that
it has not disclosed contemporaneously on an equal
basis to all potential competitors of its affiliate.
9.3.9 COMPLAINT PROCEDURES
Any competitor or customer of RegCo or competitor of
any HoldCo subsidiary who believes that RegCo or HoldCo
or its subsidiaries has violated these principles may
file a complaint with the PSC and serve a copy on the
Company which shall respond in writing in fourteen
business days, with a copy to the PSC. Thereafter, the
complainant and the Company shall meet to resolve the
complaint informally. If no resolution can be reached
within thirty days after RegCo's response, either party
may notify the Secretary of the PSC. The Secretary
shall send a copy of such notice to the other party,
and shall promptly address the complaint pursuant to
the Commission's complaint procedures.
If the Commission determines, per the procedure
outlined above or as a result of its own investigation,
that the RegCo or HoldCo has violated these standards,
it shall provide the RegCo/HoldCo an opportunity to
remedy such conduct or explain why such conduct is not
a violation. If the RegCo/HoldCo fails to remedy such
conduct within a reasonable time after receiving such
notice, the Commission may take such remedial action
for which it has authority under the Public Service
Law.
9.4 MISCELLANEOUS
9.4.1 APPLICABILITY OF SETTLEMENT STANDARDS OF CONDUCT
The standards of conduct set forth in this Agreement
will apply in lieu of any existing generic standards of
conduct (e.g., the interim gas standards established in
Case 93-G-0932) and in lieu of any future generic
standards of conduct established by the Commission
during the term of this Agreement. Before the
Commission makes any changes to these standards, either
through a generic or specific Company proceeding, it
will consider the Company's specific circumstances,
including its performance under the existing standards.
9.4.2 ANNUAL MEETING
Senior management of RegCo and HoldCo will meet
annually with senior Commission Staff to discuss the
Company's plans related to capital attraction and
financial performance.
9.4.3 TRAINING AND CERTIFICATION
HoldCo and RegCo shall conduct training on these
principles for officers, directors and senior managers.
The officers, directors and senior managers of HoldCo,
RegCo, and unregulated affiliates shall certify
familiarity with these principles within forty-five
days of PSC approval. New officers, directors and
senior management should similarly certify familiarity
within 45 days after taking their positions.
On an annual basis, designated officers should provide
certification to the PSC of the companies' adherence to
these standards.
9.4.4 TELERGY
The rate plan and standards of conduct in this
settlement shall constitute settlement of the issues
that have arisen with regard to or resulting from the
so-called "Telergy" venture, including those identified
in Case No. 96-M-0138 pertaining to adequate
compensation for the use of Niagara Mohawk's rights-of-way, and use
of "Telergy" Calling Cards.
9.5 MERGERS AND ACQUISITIONS
9.5.1 RECOVERY OF PREMIUM
Pursuant to a petition filed jointly or individually by
the Company, Niagara Mohawk shall have the flexibility
to retain, on a cumulative basis, all savings
associated with the acquisition or merger with another
utility for a period of five years from the date of
closing of any such merger or acquisition up to the
amount of acquisition premium paid over the lesser of
book value or fair market value of assets merged or
acquired. Savings in excess of that recovery will be
disposed of by order of the Commission.
9.5.2 RELATIONSHIP TO DIVESTITURE
Because the PSC will review merger applications under
the Public Service Law, nothing in this agreement will
limit the Company's ability to merge with or be
acquired by another entity owning generation.
9.5.3 APPLICABILITY OF THIS AGREEMENT POST MERGER
The provisions of this agreement shall continue in any
merged entity.
9.5.4 EXPEDITED REVIEW
Staff and the Commission will give expedited review and
treatment to any petition by RegCo or HoldCo in
connection with a merger with another utility.
SECTION 10.0
SUPPLIER OF LAST RESORT
OBLIGATION AND IMPLEMENTATION
10.1 OBLIGATION TO SERVE
The Public Service Law requires regulated utilities to
provide safe and adequate electric service at just and
reasonable rates. RegCo will maintain an obligation to
provide the electricity commodity to all customers
during the term of this settlement, as further
described in Section 4.0. The Company agrees to work
with other parties, in the continuing proceedings in
Case 94-E-0952 and other forums as appropriate, to
develop a definition of the obligation to serve that is
consistent with a competitive generation market and a
competitive energy services market.
10.2 IMPLEMENTATION
10.2.1 ENERGY SERVICE PROVIDERS, MARKETERS AND BROKERS
Niagara Mohawk will accept financial risk for the
performance of energy service companies if the
Company is allowed to employ reasonable standards of
operational conduct and acceptable standards of
commercial credit worthiness. To the extent that
Niagara Mohawk has incurred costs to provide energy
to balance an ESCo's customers loads, it will
collect its costs for doing so from that ESCo and/or
from customers as provided for below. Niagara
Mohawk's ESCo will have the same requirements as
other ESCos.
As discussed in Section 8.3 RegCo will bill
customers directly for transmission and distribution
services. An ESCO will have the option of billing
customers for its services directly (two bill model)
or having RegCo bill on its behalf (one bill model).
Under the one bill model, issues concerning
operational conduct and credit worthiness can be
addressed in the commercial terms established under
service level contracts with the ESCos. Therefore,
no additional credit or security requirements shall
apply.
With respect to the two bill model, the Company has
a greater level of business risk from balancing
services. This business risk can be mitigated by
establishment of reasonable standards of operational
performance and credit worthiness. The following
procedures address these operational business risks:
- ESCos are required to maintain a credit
requirement with the Company or provide
adequate security in lieu of such credit
requirement, in an amount that is equal to or
greater than the summation of the kilowatthours
of all customers under each ESCo's service,
multiplied by the Company's highest monthly
average on peak energy buy back rate during the
preceding twelve month period (the current rate
under S.C. 6 is $.02333 per kilowatthour).
The Company reserves the right to revise the
rate as appropriate to reflect changes in
tariff provisions. This credit requirement
will be updated on a continuous basis.
- A customer's kilowatthour summation for credit
requirement purposes only, will be determined
by computing the two highest monthly billing
cycle kilowatthour consumptions or the highest
bi-monthly billing cycle kilowatthour
consumptions over the prior twelve-month period
for the eligible customers. If a prior twelve-month
period does not exist, the kilowatthour
summation will be determined by computing the
two highest kilowatthour consumptions or the
highest bi-monthly kilowatthour consumptions
over the prior twelve-month period for an
"average customer" of the same rate class and
voltage level of the eligible customer.
The application of these ESCo credit worthiness
standards will be accomplished by performing
the evaluation as described more fully in
Section 10.2.3.2 of this settlement.
- An interim imbalance billing may be presented
to the ESCo with payment due within 21 days of
receipt of the billing when actual deliveries
fall below 75% of the required scheduled
deliveries during a seven day period. If
payment from the ESCo is not received, the
Company may institute an expedited proceeding
with the PSC to revoke or suspend the ESCo's
eligibility, and to propose a transition plan
to convert the ESCo's customers to an
alternative supplier. The Company expects a
decision on this petition to be completed
within 23 days of such filing.
- To the extent that the PSC does not respond to
the petition request or alters the conversion
date of the ESCo's customers, beyond sixty days
from the beginning of the period that generated
the interim imbalance bill or 23 days from the
filing of the petition with the PSC, whichever
is greater, the Company will not be at risk of
loss associated with imbalance services for
those customers from this date through the
conversion date set forth in the PSC decision.
The Company would seek to recover such losses
first, from any remaining security from the
ESCo, second through the transition plan for
the ESCo's customers as approved by the PSC,
and lastly from ratepayers in general,
consistent with deferral provisions contained
in Section 2.0 Rate Plan of this settlement.
The Company will continue to use its best
efforts to pursue recovery of all losses from
the ESCo and to the extent additional
recoveries are achieved, such recoveries will
be offset against deferrals.
These procedures will be revised as necessary upon
the establishment of a fully operational ISO and
Power Exchange.
10.2.2 CUSTOMER OPERATIONS PROCEDURES
To facilitate the Company's operations under the rate
plan, provisions of Part 11, Part 13, Part 140 and Part
273 of 16 NYCRR and the requirements for a plain
language bill format adopted in Case 28080, Order
Requiring Gas and Electric Utilities to File Revised
Billing Formats (Oct. 31, 1985), are waived to the
extent that any such provisions are inconsistent with
the Company's ability to:
a. institute non-discriminatory procedures which
require an applicant to provide reasonable proof
of the applicant's identity as a condition of
service;
b. modify its bill content and format in response to
industry restructuring; provided, however, the
Company's bills will contain the following:
- an explanation of how bills may be paid
- total charges due
- due date
- unit price of energy consumed or other
appropriate itemization of charges (including
sales taxes and other informative tax
itemization)
- complete name and address of customer
- unique account number or customer number
assigned to the customer
- meter readings
- period of time associated with each product
or service
- name of entity rendering bill
- local or toll-free telephone number customers
may call with inquiries
- plain language
- basis of calculations of billed amounts
- late payment charges that apply
- estimated reads, if applicable
- posting of cash receipts to previous balance
c. include non-tariffed items in a bill; provided,
however, that customer payments are credited first
to tariffed items and service cannot be terminated
for failure to pay non-tariffed items.
Niagara Mohawk will be permitted to disclose to other
service providers: whether or not a deposit could be
requested from the customers by Niagara Mohawk due to
delinquency, as defined in 16 NYCRR Section 11.12(d)(2)
or in 16 NYCRR Section 13.1(b)(13), or for any reason
provided in 16 NYCRR Section 13.7(a)(1); whether or not
a customer could be denied service by Niagara Mohawk
due to unpaid bills on an existing or prior account;
or, whether a customer's service could be terminated by
Niagara Mohawk provided that:
- such information is to be used by other service
providers only for the purposes of determining
whether unregulated energy services will be
provided to the customer, whether a deposit will
be collected from such customer, or for other
purposes approved by the Commission; and,
- such information request is made by a service
provider in response to a bona fide request from
the customer to the service provider for electric
service or with other customer consent.
The Company will be permitted to accept credit card
payments for utility service, provided, however, that
any costs imposed on Niagara Mohawk associated with the
receipt of payment by credit card are to be considered
among the general costs of doing business and will not
be a separate additional charge to the customers whose
payments are made by credit card.
10.2.3 CREDIT AND COLLECTION MATTERS
10.2.3.1 CUSTOMER CREDITWORTHINESS
Change to Parts 11 and 13 of the Commission's
Regulations are expected to be made and
necessary for the Company to mitigate its
risks of being the supplier of last resort.
In Case 96-M-0706, for example, the Company
proposes changes to the Regulations,
including (1) requiring payment in full of
security deposits prior to initiation of
service for some customers; (2) requiring
alternate payment plans for certain
applicants and for customers who have
defaulted on deferred payment agreements
(DPA); (3) requiring completed applications
for service; (4) increasing minimum DPA
payments and down payments; (5) revising the
standards for determining financial need; (6)
allowing utilities to deny service under
certain circumstances to those who have
breached DPAs; and (7) reducing the duration
of DPAs. The Company plans to pursue changes
as described above as part of the generic
proceeding covering these issues, however, it
reserves the right to petition for further
waiver of such rules as necessary.
10.2.3.2 ESCO CREDITWORTHINESS EVALUATION
Niagara Mohawk will establish credit limits
or security requirements for all energy
suppliers prior to their serving customers on
Niagara Mohawk's system by applying, on a
consistent, non-discriminatory basis, the
same financial evaluation standards it
currently employs in determining
creditworthiness of energy suppliers
providing supply services to its gas
transportation customers (See Appendix G).
Energy suppliers will be notified of the
established credit limit within two weeks of
receipt of a completed credit application
accompanied by the two most current years of
audited financial statements. Credit limits
must be maintained and will be reviewed
continually.
If an entity is assigned a credit limit that
is not sufficient to meet the requirements of
this section, it may meet the requirements by
paying any outstanding balances due to
Niagara Mohawk and providing security in the
form of (1) an advance deposit; (2) an
irrevocable letter of credit in such form,
and drawn upon such bank, as are satisfactory
to Niagara Mohawk; (3) a security interest in
collateral satisfactory to Niagara Mohawk; or
(4) a guarantee, in form acceptable to
Niagara Mohawk, by another entity which is
assigned a credit limit adequate to meet the
requirements of this section (e.g., parental
guarantee). Such security must be in an
amount at least sufficient to cover the
difference between the credit limit assigned
to the entity by Niagara Mohawk and the
credit limit required by this section.
In the event the level of credit indicates
security is no longer required, and in
conjunction with a creditworthiness
evaluation, such security will be returned in
kind, within two weeks of such determination.
Security deposits held by Niagara Mohawk
Power Corporation for energy suppliers will
accrue interest at the Commission's "Other
Customer Capital Rate." If Niagara Mohawk is
unable to establish a credit limit based on
information available from acceptable
financial reporting agencies or commercial
credit reporting organizations, and the
financial statements noted above, an energy
supplier must provide such supplemental
financial and credit information as Niagara
Mohawk may deem necessary. This may include
information as to the energy supplier's legal
structure; its officers, partners, or
proprietors; trade references; recent
financial statements; and such other credit
information as might reasonably be required
in the exercise of due diligence by a
potential creditor of the energy supplier.
10.2.4 TERMINATION DECISIONS
RegCo will serve as the supplier of last resort, thus
it will make all service termination decisions
associated with non-payment of amounts owed to the
Company. Its termination decisions will continue to be
guided by regulation.
RegCo will not charge for a customer's initial switch
from RegCo to an alternative energy supplier. If a
competitive ESCo wants to discontinue electric service,
it will notify the customer and RegCo of the
termination in writing at least 21 days before the
customer's next cycle meter reading date. If a
customer wants to discontinue service from an ESCo, it
will notify the ESCo and RegCo of the termination in
writing at least 21 days before the customer's next
meter reading date. If, after receiving the ESCo's
written termination notice, or sending its own written
termination notice, the customer has not contacted
RegCo or some other ESCo during the 21 day period,
service would thereafter be provided by RegCo. RegCo
will charge customers a switching charge that fully
reflects all incremental costs as provided under
tariffs. RegCo also will charge customers who return
to RegCo for commodity service rates for energy supply
according to the rates for their applicable rate class.
Any other charges associated with the discontinuance
and/or reconnection of service will be borne by the
ESCo. RegCo may recover those charges from the ESCo by
acquiring a commensurate amount of the ESCo's security
and receiving a replacement amount of security from the
ESCo.
10.2.5 COST RECOVERY
RegCo's revenue sources may be in jeopardy to the
extent welfare reform on the state and federal levels
limits public assistance and Home Energy Assistance
Program benefits that customers now use to pay their
utility bills. RegCo may incur a revenue shortfall
from those sources that is not currently being
mitigated. To mitigate that shortfall, RegCo has the
right to petition for recovery of losses consistent
with the treatment of deferrals as described in Section
2.0, Rate Plan of this settlement.
SECTION 11.0
REGULATORY CHANGES AND APPROVALS
11.1 ELIMINATION OF CERTAIN REGULATORY REQUIREMENTS
11.1.1 REGULATORY REPORTING REQUIREMENTS
Niagara Mohawk will continue its participation in the
Reporting Requirements Working Group of Case 94-E-0952
- Competitive Opportunities Proceeding - Phase II.
The reporting requirements that may be established in
Case 94-E-0952 by a final, Commission order or an order
which has not been stayed pending appeal will apply
during the term of this Agreement.
11.1.2 TREATMENT OF FUTURE REFUNDS
The Company is subject to ongoing examinations by
federal and state tax authorities. No amounts have
been provided for in the financial forecast for
resolution, either resulting in a refund or liability,
of these examinations. To the extent that refunds or
payments, including interest and penalties and net of
any deferred taxes, individually exceed $500,000, the
Company will defer such refund or payment for
disposition in rates after the term of the settlement
agreement. When available, new deferred debits will be
netted against new deferred credits arising during the
term of this settlement agreement.
In addition, the Company expects to receive a tax
benefit resulting from the offset of the common stock,
equity, and cash it will provide under the MRA against
tax amounts paid in past and future years, as described
in Section 2.3.4.
During the term of this settlement, the treatment
described above covers all refunds and tax benefits
that might otherwise have been passed back to
customers. Thus, in approving this settlement, the
Commission thereby approves the treatment of all such
refunds and the total amount of the tax benefit
described above. The Company will not be required to
file any formal notice of tax refunds under Section
89.3 of the Commission's Regulations (16 NYCRR Section
89.3). No hearings will be held pursuant to Section
113(2). However, the Company will provide Staff with
documentation and supporting workpapers of any such tax
refunds on a timely basis. This settlement constitutes
full compliance with the provisions of Section 113(2)
and the Commission's Regulations.
11.2 REGULATORY APPROVALS
11.2.1 COMMERCIALIZATION OF PRODUCTS AND
TECHNOLOGIES DEVELOPED AS A RESULT OF
RESEARCH AND DEVELOPMENT
During the term of this Agreement, Niagara Mohawk will
not defer and true up its cost of investment in
research and development (R&D) activities. Nor will
the Company defer and true up any royalty revenue it
receives from commercialization of products and
technologies that emerge from such R&D activities.
The Company's affiliates may invest in
commercialization of R&D products and technologies
developed by RegCo consistent with affiliate rules
generally and with Sec. 9.2.2 specifically. If an
affiliate elects to invest, it will fairly compensate
RegCo, assume the business risk(s) and will be entitled
to the benefits associated with that investment.
11.2.2 PSL SECTIONS 69 AND 70 APPROVAL OF THE SALE,
LEASING, OR FINANCING OF BUILDING FACILITIES
Niagara Mohawk intends to implement an Occupancy Cost
Reduction Initiative ("OCRI"). The purpose of this
initiative is to reduce the total occupancy cost to,
and revenue requirements of, Niagara Mohawk, while
increasing corporate flexibility and enhancing
operational efficiency. One key objective of OCRI will
be to realign the Company's asset base to maximize
flexibility and minimize capital commitment as the
needs of the Company change. Niagara Mohawk wishes to
achieve this objective by disposing of least cost-effective space;
bringing all facilities to fully-utilized status; and extracting
capital from surplus assets.
Annexed hereto as Appendix H is a list of Niagara
Mohawk facilities that have been identified as
potential candidates for sale, leasing, or sale
leaseback transactions. For each facility, Appendix H
sets forth its associated net book value.
During the term of this Agreement, Niagara Mohawk will
observe the following procedures in connection with the
sale, leasing, or sale-leaseback of its Appendix H
facilities:
11.2.2.1 If and when a facility is no longer
needed to provide electric and gas
services, the Company will evaluate the
best utilization or disposition of the
facility, including, but not limited to,
sale to NM Holdings or sale or lease to
a third party.
11.2.2.2 In the event Niagara Mohawk decides to
sell or lease a facility, the Company
may utilize brokers or other service
providers to identify prospective buyers
or tenants. Niagara Mohawk will use
every effort to obtain the highest
market value for the facility based upon
independent appraisals and market
conditions. Any sale will require the
prior approval of Niagara Mohawk's Board
of Directors. Any lease will require
the approval of a Niagara Mohawk
officer.
11.2.2.3 Under no circumstances will the sale or
lease of a facility prevent Niagara
Mohawk from providing electric and gas
services to its customers, or from
otherwise being able to discharge its
public service responsibilities and to
meet its electric and gas load
requirements.
11.2.2.4 To the extent the accounting for such
revenues is not otherwise provided for
herein, all revenues derived from sales
will be accounted for in accordance with
the Uniform System of Accounts.
11.2.2.5 All contract documents will include
provisions limiting Niagara Mohawk's
liabilities, such as environmental
liabilities. In the case of lease
transactions, tenants will also be
required, inter alia, to maintain
insurance coverage, protect Niagara
Mohawk property, and observe all Niagara
Mohawk rules and regulations regarding
the use of the premises. Any initial
lease term shall not exceed five (5)
years.
11.2.2.6 Any sale-leaseback transaction will be
revenue neutral or will reduce revenue
requirements.
To the extent implementation of the OCRI requires
Commission authorization under Public Service Law
Sections 69 and 70, that authorization is in the
public interest for the sale, lease or financing
of facilities of $3 million or less. In
approving this settlement, the Commission thereby
grants that authorization for the term of this
settlement. Sale, lease or financing of
facilities in excess of $3 million will be
subject to a separate petition.
11.2.3 CONVERSION OF 25 CYCLE CUSTOMERS
In its Western Region, several of the Company's
customers maintain equipment that requires 25 cycle
electricity rather than the 60 cycle power the Company
provides elsewhere on its system. The Company will
eliminate 25 cycle service to all such customers on
December 31, 2007. Prior to that time, in the event of
failure of significant 25 cycle equipment, e.g.,
transformers, frequency changers, the Company will not
repair or replace such equipment unless it secures
agreements from the affected customer(s) to pay the
cost of such repair or replacement.
SECTION 12.0
LOW INCOME CUSTOMER ASSISTANCE PROGRAM (LICAP)
RegCo will seek, at the lowest possible cost, to assist low-income
customers who are unable to pay fully for their
electric and gas usage, and to thereby minimize
uncollectible accounts expense. As part of its provider of
last resort responsibilities, RegCo will pursue these
objectives by expanding the availability of Niagara Mohawk's
Low Income Customer Assistance Afford/Ability Plan to all
low-income customers who do not receive public assistance
and who, on the basis of objective criteria, are unable to
pay their full energy bills. Based on research conducted in
the Fall of 1995, it is estimated that approximately 29,000
customers will be eligible for services under the expanded
Afford/Ability Plan. RegCo expects to have enrolled
approximately 9,000 customers by the end of 1997 and to have
enrolled all eligible customers by 2001 with the program
continuing through the end of this Agreement.
RegCo will also offer Afford/Ability Plan services on a
pilot basis to a number of customers who receive public
assistance and have accounts that are in arrears, but whose
accounts are not paid directly by county departments of
social services. If the results indicate that
Afford/Ability Plan services are more cost effective than
current procedures for obtaining direct county payment of
utility bills, RegCo will further expand the Afford/Ability
Plan to include public assistance customers.
12.1 ELIGIBILITY CRITERIA
Current eligibility criteria for the Afford/Ability
Plan include receipt of Federal Home Energy Assistance
Program ("HEAP") grants, a negative cash flow (as
determined using Department of Social Services Form
3596), and a history of broken payment agreements.
Given the future uncertainty of the HEAP program, RegCo
may be required to implement alternative methods of
identifying and verifying eligible candidates for
Afford/Ability Plan services.
12.2 PROGRAM DESCRIPTION
The Afford/Ability Plan involves three steps. First,
based on the customer's financial circumstances as
measured by objective standards, the utility will agree
to accept partial payment for future energy use.
Second, the customer must agree to participate in an
energy use management program designed to reduce
overall usage. Program services include
weatherization, attendance at an energy services
workshop, an electric appliance retrofit analysis
(including, where appropriate, refrigerator
replacement) and an in-home energy service education
packet. To ensure cost-effectiveness, specific energy
use management services will be provided to customers
on the basis of the customer's previous usage and
location. While the investment per customer will vary
according to the package of services provided, the
total annual program cost for energy use management
services will approximate Niagara Mohawk's expenditure
for the former Utility Low Income Energy Efficiency
Program. Third, at the end of each year, the utility
will forgive a percentage of arrearages for those
Afford/Ability Plan customers who have made all their
agreed monthly payments. Continued participation in
the Afford/Ability Plan will require annual
recertification. It is a condition of recertification
that the customer has made all agreed partial payments
during the previous year.
12.3 PROGRAM FUNDING
The cost of the energy efficiency services outlined
above will be funded through the SBC. The costs
associated with arrears forgiveness for years one
through three under the program will be absorbed by the
Company except as otherwise provided for under Section
2.6.2. The costs of any other low income programs that
may be required by any new legislation or regulation or
of additional Afford/Ability Plan services that may be
offered as a result of the pilot study will also be
funded through SBC. The Afford/Ability Plan will be
evaluated on an ongoing basis to ensure that the
program remains cost effective. The Company will
budget expenditures under the LICAP Program to be
$4.377 million in 1998, $4.952 million in 1999 and
$5.598 million in 2000. Year four and five budgets
will be established in the proceedings that will set
rates for years four and five.
SECTION 13.0
MISCELLANEOUS
13.1 FORCE MAJEURE
If a circumstance occurs which, in the judgement of the
Company, threatens the Company's economic viability,
including its ability to access capital markets at
reasonable rates, or its ability to maintain safe and
adequate service, the Company will be permitted to
petition the Commission for relief from the terms of
this Agreement, including filing for an increase in its
prices.
13.2 COMMISSION AUTHORITY
Nothing in this Agreement shall be construed to limit
the Commission's authority to reduce the Company's
rates should it determine, in accordance with the
provisions of the Public Service Law, that the
established rates are in excess of just and reasonable
rates for the Company's electric service.
13.3 PROVISIONS NOT SEPARABLE: EFFECT OF COMMISSION
MODIFICATION
The parties have negotiated and accepted this agreement
in toto with each provision in consideration for, in
support of, and dependent on the others. If the
Commission does not approve this agreement in its
entirety, without modification, any signatory may
withdraw its acceptance of this agreement by serving
written notice on the other parties, and shall be free
to pursue its position in this proceeding without
prejudice.
If the Commission approves this Settlement Agreement or
modifies it in a manner acceptable to the parties, the
parties intend that this settlement thereafter be
implemented in accordance with its terms. If a
material modification is thereafter authorized or
required by the Commission that is unacceptable to any
party to this Settlement Agreement adversely affected
by such modification, then, in addition to any other
remedies a party may have, such party may withdraw from
the agreement and will not be bound thereafter to its
provisions.
13.4 PROVISIONS NOT PRECEDENT
The terms and provisions of this Agreement apply solely
to and are binding only in the context of the purposes
and results of this Agreement. None of the terms and
provisions of this Agreement and none of the positions
herein by any party may be referred to, cited or relied
upon by any other party in any fashion as precedent in
any other proceeding before this Commission or any
other regulatory agency or before any court of law
except in furtherance of the purposes and results of
this Agreement.
13.5 DISPUTE RESOLUTION
In the event of any disagreement over the
interpretation of this Settlement or the implementation
of any of the provisions of this Settlement, which
cannot be resolved informally among the Parties, such
disagreement shall be resolved in the following manner
unless otherwise provided herein: The Parties shall
promptly convene a conference and in good faith shall
attempt to resolve such disagreement. If any such
disagreement cannot be resolved by the Parties, any
Party may petition the Commission for relief on a
disputed matter.
13.6 WITHDRAWAL FROM LITIGATION
In consideration for the foregoing, the Company, upon
final approval of this Settlement by the Commission,
agrees to petition the Appellate Division of the
Supreme Court for permission to withdraw as a party to
the appeal in the Article 78 proceeding brought to
challenge Opinion 96-12, Energy Association v. Public
Service Commission (Sup. Ct. Albany Co. Index No. 5830-96).
The Company's withdrawal as a party to the Energy
Association case shall be effected through Stipulations
of Withdrawal, mutually agreed to by the Company and
the Commission. Until the aforementioned petition with
respect to the Energy Association case is granted, the
Company will discontinue its litigation activities to
the extent that it is able to do so without prejudicing
its rights in the Article 78 proceeding.
13.7 CONSTRUCTION OF TERMS
This Settlement Agreement was written to reflect
formation of a legally separate HoldCo. In the event
that the HoldCo is not a legally separate entity, the
terms and conditions of this Settlement shall be read
to give full effect to their meaning and intent.
13.8 STEAM HOST ISSUES
The parties to this Agreement recognize the need for
certain of the SIPPs and companies ("the Steam Hosts
Action Group" or "SHAG") that have contracts with those
SIPPS regarding steam/thermal arrangements in the post-MRA
period to conduct negotiations to reach a
satisfactory settlement of issues related to changes in
SIPP operations as a result of the MRA. The parties to
this Agreement acknowledge, among other priorities,
the importance to the economy of the State of New York
of addressing steam/thermal issues as expeditiously as
possible. The following parties - Empire State
Development by the Department of Economic Development,
the Job Development Authority and the Empire State
Development Corporation (Urban Development Corp.),
Niagara Mohawk Power Corporation, New York Power
Authority, Multiple Intervenors, the SHAG, and the
SIPPS, Joint Supporters and the National Association of
Energy Service Companies - specifically agree, in a
good faith effort, to pursue diligently ways to
minimize any economic or operational difficulties due
to changes in SIPP steam production which could occur
as a result of the MRA and to otherwise reach a
mutually satisfactory settlement of the issues.
No party to this Agreement shall be deemed to waive
(including, but not limited to, in connection with the
Commission's review of this Agreement), any right to
recommend to the Commission, or to oppose any such
recommendation or to take any other position
(including, but not limited to, with respect to
Commission jurisdiction), that the Commission undertake
any specific course of action regarding the resolution
of these negotiations between such SIPPs and SHAG,
except that all parties specifically waive any right to
challenge the prudence of the MRA, and the contracts
executed pursuant thereto.
SECTION 14.0
TERM OF THIS AGREEMENT
Except as otherwise provided herein, the term of this
Agreement shall be five years from the PowerChoice
Implementation Date.
EXHIBIT 99.2
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POWERCHOICE SETTLEMENT
POWERCHOICE SETTLEMENT EXPECTED TO SAVE 6,000 JOBS, SPUR
ECONOMY
Niagara Mohawk's Plan Calls for Lower Average Electricity
Prices,Competition and Customer Choice
Settlement is subject to Public Service Commission review
and public comment
SYRACUSE, Oct. 10 -- Niagara Mohawk Power Corp.'s
(NYSE:NMK) PowerChoice settlement, filed today with the
state Public Service Commission, is expected to save or
create 6,000 jobs in Upstate New York and spur economic
development by lowering average electricity prices and
creating a competitive electricity market.
"This settlement is another major step forward in
Niagara Mohawk's financial recovery and it exceeds the goals
of our original PowerChoice proposal," said William E.
Davis, Niagara Mohawk chairman and chief executive officer.
"While PowerChoice originally proposed to freeze average
residential and commercial electricity prices and cut
industrial prices, this settlement proposes to reduce
average prices for residential and commercial customers, as
well. In addition, all customers will be able to choose
their own electricity producer in a competitive market by
December 1999."
Niagara Mohawk said it filed the settlement today with
the understanding and expectation that it will be signed by
the staff of the Public Service Commission, Multiple
Intervenors, and other parties. The settlement must be
approved by the full Commission.
PRICE REDUCTIONS, JOB RETENTION
Under the settlement, all major customer classes will
see an average reduction in Niagara Mohawk's electricity
prices, which have not increased in two years. Residential
and commercial customer classes will see average cuts of
approximately 3.2 percent phased in over three years.
Industrial customers will see average reductions ranging up
to 25 percent for some customers. Those decreases include
discounts currently offered to some industrial customers
through flexible and optional rate programs.
"Industrial customers will see the largest decreases to
protect and create jobs in Upstate New York," Davis said.
"It is critical that we encourage large employers to stay in
our region and that we attract more quality jobs for Upstate
residents." He estimated that the proposed price cuts will
save or create about 6,000 jobs in Niagara Mohawk's service
area.
Davis added that keeping industrial customers on
Niagara Mohawk's system will also hold down prices for all
other customers. "When we lose large customers our fixed
costs must be spread over fewer kilowatt-hours," he said.
"That hurts all customers," Davis said. Commercial and
residential customers could see additional savings on top of
the 3.2 percent average price cut if the New York State
legislature passes Securitization legislation by early 1998
and if the legislature continues its efforts to further
reduce the state's high utility taxes.
To ensure that prices accurately reflect the true cost
of providing service, the PowerChoice settlement calls for
the energy portion of prices on residential bills to be
decreased while the fixed customer charge on bills will be
increased over three years. By the year 2000, the customer
charge will be about $17, lower than the basic service
charge for telephone or cable television service today.
This will result in a slight overall increase -- less than a
dollar in most cases -- in the bills of some customers,
primarily low-use accounts such as seasonal homes.
Customers who use more than 400 kilowatt-hours of
electricity a month will see bill reductions.
Davis said absent PowerChoice and the company's
agreement to terminate or restructure 29 independent power
producer contracts, Niagara Mohawk would have had to
continue to pursue price increases to meet growing costs,
primarily increasing IPP payments. That could have meant
residential electricity price increases of 10 percent to 15
percent through 2000.
STRANDED COST RECOVERY
Niagara Mohawk has agreed to absorb a portion of past
investments made to serve customers that would be
unrecoverable or "stranded" in the competitive market.
Remaining stranded costs would be recovered from all
customers, regardless of their energy supplier, through a
non-bypassable Competitive Transition Charge. The
settlement notes that recovering stranded costs in this way
ensures all customers are treated fairly and that no
customer or group of customers avoids stranded costs at the
expense of other customers.
CORPORATE STRUCTURE
As with Niagara Mohawk's original PowerChoice proposal,
the settlement calls for the company to separate its
generation business from its transmission and distribution
businesses. To accomplish this, the company will conduct an
auction of all non-nuclear generation assets as soon as
practicable. Shareholders will receive a portion of the
sale proceeds as an incentive to divest.
Niagara Mohawk's nuclear plants will remain part of the
company's regulated business and the company will continue
to improve efficiency at the plants through a statewide
solution such as the New York Nuclear Operating Company.
The settlement stipulates that absent a statewide solution,
Niagara Mohawk will file a detailed plan for analyzing
proposed solutions for its nuclear assets, including the
feasibility of an auction, transfer and/or divestiture.
Niagara Mohawk's core focus will remain on its
regulated transmission and distribution business. The
company also will continue to strengthen its delivery of
basic customer services associated with transmission and
distribution.SPECIAL PROGRAMS
The PowerChoice settlement calls for demand-side
management programs and research and development programs to
be administered by a third party. The cost of these
programs, which is currently reflected in electricity bills,
will be collected through a System Benefits Charge. The
company also will expand its Low-Income Customer Assistance
Program. In addition, the settlement calls for
environmental enhancements such as transferring land in the
Adirondack Park to the state and donating sulfur dioxide
allowances.
THE MASTER RESTRUCTURING AGREEMENT
Under the PowerChoice settlement, the parties recommend
PSC approval of the Master Restructuring Agreement signed by
Niagara Mohawk and 16 independent power producers on July 9,
1997. The MRA calls for Niagara Mohawk to pay approximately
$4 billion in cash and stock to terminate or restructure 29
IPP contracts that represent about 84 percent of the above-market
IPP costs reflected in customers' bills. Niagara
Mohawk will finance the agreement through new debt which
will be paid down over a seven- to eight-year period.
Davis said approval of the PowerChoice settlement and
consummation of the MRA will help restore Niagara Mohawk's
financial health and help revitalize the Upstate economy.
"Overall, Niagara Mohawk's financial condition should
stabilize and improve. Our cash flow will improve as a
result of the Master Restructuring Agreement and shareholder
value will improve as that debt is reduced. In addition,
the settlement provides a set of rules that will allow the
company to compete fairly in the new marketplace," Davis
said.
The settlement will be the subject of evidentiary and
public statement hearings before an administrative law
judge. The PSC will review the settlement and the judge's
analysis in open session before voting on the agreement.
The company hopes to obtain approval from the PSC by early
1998 and to consummate the MRA shortly thereafter.