807 KAR 5:058.
Integrated resource planning by electric utilities.
RELATES TO: KRS
Chapter 278
STATUTORY
AUTHORITY: KRS 278.040(3), 278.230(3)
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. (17 Ky.R. 1289; Am. 1720; eff. 12-18-90; 21
Ky.R. 2799; 22 Ky.R. 287; eff. 7-21-95.)
