Current through Register Vol. 50, No. 9, March 1, 2024
RELATES TO: KRS Chapter 278
NECESSITY, FUNCTION, AND CONFORMITY:
KRS
278.040(3) provides that the
commission may adopt reasonable administrative regulations to implement the
provisions of KRS Chapter 278. This administrative regulation prescribes rules
for regular reporting and commission review of load forecasts and resource
plans of the state's electric utilities to meet future demand with an adequate
and reliable supply of electricity at the lowest possible cost for all
customers within their service areas, and satisfy all related state and federal
laws and regulations.
Section 1.
General Provisions.
(1) This administrative
regulation shall apply to electric utilities under commission jurisdiction
except a distribution company with less than $10,000,000 annual revenue or a
distribution cooperative organized under KRS Chapter 279.
(2) Each electric utility shall file
triennially with the commission an integrated resource plan. The plan shall
include historical and projected demand, resource, and financial data, and
other operating performance and system information, and shall discuss the
facts, assumptions, and conclusions, upon which the plan is based and the
actions it proposes.
(3) Each
electric utility shall file ten (10) bound copies and one (1) unbound,
reproducible copy of its integrated resource plan with the
commission.
Section 2.
Filing Schedule.
(1) Each electric utility
shall file its integrated resource plan according to a staggered schedule which
provides for the filing of integrated resource plans one (1) every six (6)
months beginning nine (9) months from the effective date of this administrative
regulation.
(a) The integrated resource plans
shall be filed at the specified times following the effective date of this
administrative regulation:
1. Kentucky
Utilities Company shall file nine (9) months from the effective date;
2. Kentucky Power Company shall file fifteen
(15) months from the effective date;
3. East Kentucky Power Cooperative, Inc.
shall file twenty-one (21) months from the effective date;
4. The Union Light, Heat & Power Company
shall file twenty-seven (27) months from the effective date;
5. Big Rivers Electric Corporation shall file
thirty-three (33) months from the effective date; and
6. Louisville Gas & Electric Company
shall file thirty-nine (39) months from the effective date.
(b) The schedule shall provide at
such time as all electric utilities have filed integrated resource plans, the
sequence shall repeat.
(c) The
schedule shall remain in effect until changed by the commission on its own
motion or on motion of one (1) or more electric utilities for good cause shown.
Good cause may include a change in a utility's financial or resource
conditions.
(d) If any filing date
falls on a weekend or holiday, the plan shall be submitted on the first
business day following the scheduled filing date.
(2) Immediately upon filing of an integrated
resource plan, each utility shall provide notice to intervenors in its last
integrated resource plan review proceeding, that its plan has been filed and is
available from the utility upon request.
(3) Upon receipt of a utility's integrated
resource plan, the commission shall establish a review schedule which may
include interrogatories, comments, informal conferences, and staff
reports.
Section 3.
Waiver. A utility may file a motion requesting a waiver of specific provisions
of this administrative regulation. Any request shall be made no later than
ninety (90) days prior to the date established for filing the integrated
resource plan. The commission shall rule on the request within thirty (30)
days. The motion shall clearly identify the provision from which the utility
seeks a waiver and provide justification for the requested relief which shall
include an estimate of costs and benefits of compliance with the specific
provision. Notice shall be given in the manner provided in Section 2(2) of this
administrative regulation.
Section
4. Format.
(1) The integrated
resource plan shall be clearly and concisely organized so that it is evident to
the commission that the utility has complied with reporting requirements
described in subsequent sections.
(2) Each plan filed shall identify the
individuals responsible for its preparation, who shall be available to respond
to inquiries during the commission's review of the plan.
Section 5. Plan Summary. The plan shall
contain a summary which discusses the utility's projected load growth and the
resources planned to meet that growth. The summary shall include at a minimum:
(1) Description of the utility, its
customers, service territory, current facilities, and planning
objectives;
(2) Description of
models, methods, data, and key assumptions used to develop the results
contained in the plan;
(3) Summary
of forecasts of energy and peak demand, and key economic and demographic
assumptions or projections underlying these forecasts;
(4) Summary of the utility's planned resource
acquisitions including improvements in operating efficiency of existing
facilities, demand-side programs, nonutility sources of generation, new power
plants, transmission improvements, bulk power purchases and sales, and
interconnections with other utilities;
(5) Steps to be taken during the next three
(3) years to implement the plan;
(6) Discussion of key issues or uncertainties
that could affect successful implementation of the plan.
Section 6. Significant Changes. All
integrated resource plans, shall have a summary of significant changes since
the plan most recently filed. This summary shall describe, in narrative and
tabular form, changes in load forecasts, resource plans, assumptions, or
methodologies from the previous plan. Where appropriate, the utility may also
use graphic displays to illustrate changes.
Section 7. Load Forecasts. The plan shall
include historical and forecasted information regarding loads.
(1) The information shall be provided for the
total system and, where available, disaggregated by the following customer
classes:
(a) Residential heating;
(b) Residential nonheating;
(c) Total residential (total of paragraphs
(a) and (b) of this subsection);
(d) Commercial;
(e) Industrial;
(f) Sales for resale;
(g) Utility use and other.
The utility shall also provide data at any greater level of
disaggregation available.
(2) The utility shall provide the following
historical information for the base year, which shall be the most recent
calendar year for which actual energy sales and system peak demand data are
available, and the four (4) years preceding the base year:
(a) Average annual number of customers by
class as defined in subsection (1) of this section;
(b) Recorded and weather-normalized annual
energy sales and generation for the system, and sales disaggregated by class as
defined in subsection (1) of this section;
(c) Recorded and weather-normalized
coincident peak demand in summer and winter for the system;
(d) Total energy sales and coincident peak
demand to retail and wholesale customers for which the utility has firm,
contractual commitments;
(e) Total
energy sales and coincident peak demand to retail and wholesale customers for
which service is provided under an interruptible or curtailable contract or
tariff or under some other nonfirm basis;
(f) Annual energy losses for the
system;
(g) Identification and
description of existing demand-side programs and an estimate of their impact on
utility sales and coincident peak demands including utility or government
sponsored conservation and load management programs;
(h) Any other data or exhibits, such as load
duration curves or average energy usage per customer, which illustrate
historical changes in load or load characteristics.
(3) For each of the fifteen (15) years
succeeding the base year, the utility shall provide a base load forecast it
considers most likely to occur and, to the extent available, alternate
forecasts representing lower and upper ranges of expected future growth of the
load on its system. Forecasts shall not include load impacts of additional,
future demand-side programs or customer generation included as part of planned
resource acquisitions estimated separately and reported in Section 8(4) of this
administrative regulation. Forecasts shall include the utility's estimates of
existing and continuing demand-side programs as described in subsection (5) of
this section.
(4) The following
information shall be filed for each forecast:
(a) Annual energy sales and generation for
the system and sales disaggregated by class as defined in subsection (1) of
this section;
(b) Summer and winter
coincident peak demand for the system;
(c) If available for the first two (2) years
of the forecast, monthly forecasts of energy sales and generation for the
system and disaggregated by class as defined in subsection (1) of this section
and system peak demand;
(d) The
impact of existing and continuing demand-side programs on both energy sales and
system peak demands, including utility and government sponsored conservation
and load management programs;
(e)
Any other data or exhibits which illustrate projected changes in load or load
characteristics.
(5) The
additional following data shall be provided for the integrated system, when the
utility is part of a multistate integrated utility system, and for the selling
company, when the utility purchases fifty (50) percent of its energy from
another company:
(a) For the base year and the
four (4) years preceding the base year:
1.
Recorded and weather normalized annual energy sales and generation;
2. Recorded and weather-normalized coincident
peak demand in summer and winter.
(b) For each of the fifteen (15) years
succeeding the base year:
1. Forecasted annual
energy sales and generation;
2.
Forecasted summer and winter coincident peak demand.
(6) A utility shall file all
updates of load forecasts with the commission when they are adopted by the
utility.
(7) The plan shall include
a complete description and discussion of:
(a)
All data sets used in producing the forecasts;
(b) Key assumptions and judgments used in
producing forecasts and determining their reasonableness;
(c) The general methodological approach taken
to load forecasting (for example, econometric, or structural) and the model
design, model specification, and estimation of key model parameters (for
example, price elasticities of demand or average energy usage per type of
appliance);
(d) The utility's
treatment and assessment of load forecast uncertainty;
(e) The extent to which the utility's load
forecasting methods and models explicitly address and incorporate the following
factors:
1. Changes in prices of electricity
and prices of competing fuels;
2.
Changes in population and economic conditions in the utility's service
territory and general region;
3.
Development and potential market penetration of new appliances, equipment, and
technologies that use electricity or competing fuels; and
4. Continuation of existing company and
government sponsored conservation and load management or other demand-side
programs.
(f) Research
and development efforts underway or planned to improve performance, efficiency,
or capabilities of the utility's load forecasting methods; and
(g) Description of and schedule for efforts
underway or planned to develop end-use load and market data for analyzing
demand-side resource options including load research and market research
studies, customer appliance saturation studies, and conservation and load
management program pilot or demonstration projects.
Technical discussions, descriptions, and supporting
documentation shall be contained in a technical appendix.
Section 8. Resource
Assessment and Acquisition Plan.
(1) The plan
shall include the utility's resource assessment and acquisition plan for
providing an adequate and reliable supply of electricity to meet forecasted
electricity requirements at the lowest possible cost. The plan shall consider
the potential impacts of selected, key uncertainties and shall include
assessment of potentially cost-effective resource options available to the
utility.
(2) The utility shall
describe and discuss all options considered for inclusion in the plan
including:
(a) Improvements to and more
efficient utilization of existing utility generation, transmission, and
distribution facilities;
(b)
Conservation and load management or other demand-side programs not already in
place;
(c) Expansion of generating
facilities, including assessment of economic opportunities for coordination
with other utilities in constructing and operating new units; and
(d) Assessment of nonutility generation,
including generating capacity provided by cogeneration, technologies relying on
renewable resources, and other nonutility sources.
(3) The following information regarding the
utility's existing and planned resources shall be provided. A utility which
operates as part of a multistate integrated system shall submit the following
information for its operations within Kentucky and for the multistate utility
system of which it is a part. A utility which purchases fifty (50) percent or
more of its energy needs from another company shall submit the following
information for its operations within Kentucky and for the company from which
it purchases its energy needs.
(a) A map of
existing and planned generating facilities, transmission facilities with a
voltage rating of sixty-nine (69) kilovolts or greater, indicating their type
and capacity, and locations and capacities of all interconnections with other
utilities. The utility shall discuss any known, significant conditions which
restrict transfer capabilities with other utilities.
(b) A list of all existing and planned
electric generating facilities which the utility plans to have in service in
the base year or during any of the fifteen (15) years of the forecast period,
including for each facility:
1. Plant
name;
2. Unit number(s);
3. Existing or proposed location;
4. Status (existing, planned, under
construction, etc.);
5. Actual or
projected commercial operation date;
6. Type of facility;
7. Net dependable capability, summer and
winter;
8. Entitlement if jointly
owned or unit purchase;
9. Primary
and secondary fuel types, by unit;
10. Fuel storage capacity;
11. Scheduled upgrades, deratings, and
retirement dates;
12. Actual and
projected cost and operating information for the base year (for existing units)
or first full year of operations (for new units) and the basis for projecting
the information to each of the fifteen (15) forecast years (for example, cost
escalation rates). All cost data shall be expressed in nominal and real base
year dollars.
a. Capacity and availability
factors;
b. Anticipated annual
average heat rate;
c. Costs of
fuel(s) per millions of British thermal units (MMBtu);
d. Estimate of capital costs for planned
units (total and per kilowatt of rated capacity);
e. Variable and fixed operating and
maintenance costs;
f. Capital and
operating and maintenance cost escalation factors;
g. Projected average variable and total
electricity production costs (in cents per kilowatt-hour).
(c) Description of purchases,
sales, or exchanges of electricity during the base year or which the utility
expects to enter during any of the fifteen (15) forecast years of the
plan.
(d) Description of existing
and projected amounts of electric energy and generating capacity from
cogeneration, self-generation, technologies relying on renewable resources, and
other nonutility sources available for purchase by the utility during the base
year or during any of the fifteen (15) forecast years of the plan.
(e) For each existing and new conservation
and load management or other demand-side programs included in the plan:
1. Targeted classes and end-uses;
2. Expected duration of the
program;
3. Projected energy
changes by season, and summer and winter peak demand changes;
4. Projected cost, including any incentive
payments and program administrative costs; and
5. Projected cost savings, including savings
in utility's generation, transmission and distribution costs.
(4) The utility shall
describe and discuss its resource assessment and acquisition plan which shall
consist of resource options which produce adequate and reliable means to meet
annual and seasonal peak demands and total energy requirements identified in
the base load forecast at the lowest possible cost. The utility shall provide
the following information for the base year and for each year covered by the
forecast:
(a) On total resource capacity
available at the winter and summer peak:
1.
Forecast peak load;
2. Capacity
from existing resources before consideration of retirements;
3. Capacity from planned utility-owned
generating plant capacity additions;
4. Capacity available from firm purchases
from other utilities;
5. Capacity
available from firm purchases from nonutility sources of generation;
6. Reductions or increases in peak demand
from new conservation and load management or other demand-side
programs;
7. Committed capacity
sales to wholesale customers coincident with peak;
8. Planned retirements;
9. Reserve requirements;
10. Capacity excess or deficit;
11. Capacity or reserve margin.
(b) On planned annual generation:
1. Total forecast firm energy
requirements;
2. Energy from
existing and planned utility generating resources disaggregated by primary fuel
type;
3. Energy from firm purchases
from other utilities;
4. Energy
from firm purchases from nonutility sources of generation; and
5. Reductions or increases in energy from new
conservation and load management or other demand-side programs;
(c) For each of the fifteen (15)
years covered by the plan, the utility shall provide estimates of total energy
input in primary fuels by fuel type and total generation by primary fuel type
required to meet load. Primary fuels shall be organized by standard categories
(coal, gas, etc.) and quantified on the basis of physical units (for example,
barrels or tons) as well as in MMBtu.
(5) The resource assessment and acquisition
plan shall include a description and discussion of:
(a) General methodological approach, models,
data sets, and information used by the company;
(b) Key assumption and judgments used in the
assessment and how uncertainties in those assumptions and judgments were
incorporated into analyses;
(c)
Criteria (for example, present value of revenue requirements, capital
requirements, environmental impacts, flexibility, diversity) used to screen
each resource alternative including demand-side programs, and criteria used to
select the final mix of resources presented in the acquisition plan;
(d) Criteria used in determining the
appropriate level of reliability and the required reserve or capacity margin,
and discussion of how these determinations have influenced selection of
options;
(e) Existing and projected
research efforts and programs which are directed at developing data for future
assessments and refinements of analyses;
(f) Actions to be undertaken during the
fifteen (15) years covered by the plan to meet the requirements of the Clean
Air Act amendments of 1990, and how these actions affect the utility's resource
assessment; and
(g) Consideration
given by the utility to market forces and competition in the development of the
plan.
Technical discussion, descriptions and supporting documentation
shall be contained in a technical appendix.
Section 9. Financial Information.
The integrated resource plan shall, at a minimum, include and discuss the
following financial information:
(1) Present
(base year) value of revenue requirements stated in dollar terms;
(2) Discount rate used in present value
calculations;
(3) Nominal and real
revenue requirements by year; and
(4) Average system rates (revenues per
kilowatt hour) by year.
Section
10. Notice. Each utility which files an integrated resource plan
shall publish, in a form prescribed by the commission, notice of its filing in
a newspaper of general circulation in the utility's service area. The notice
shall be published not more than thirty (30) days after the filing date of the
report.
Section 11. Procedures for
Review of the Integrated Resource Plan.
(1)
Upon receipt of a utility's integrated resource plan, the commission shall
develop a procedural schedule which allows for submission of written
interrogatories to the utility by staff and intervenors, written comments by
staff and intervenors, and responses to interrogatories and comments by the
utility.
(2) The commission may
convene conferences to discuss the filed plan and all other matters relative to
review of the plan.
(3) Based upon
its review of a utility's plan and all related information, the commission
staff shall issue a report summarizing its review and offering suggestions and
recommendations to the utility for subsequent filings.
(4) A utility shall respond to the staff's
comments and recommendations in its next integrated resource plan
filing.
STATUTORY AUTHORITY:
KRS
278.040(3),
278.230(3)