(4) The
following information shall be provided by the utility with its energy
efficiency and demand response plan:
a. A
summary of the energy efficiency and demand response plans and results of the
assessment of potential written in a nontechnical style for the benefit of the
general public.
b. The assessment
of potential study.
c.
Cost-effectiveness test analysis.
(1) The
utility shall analyze cost-effectiveness for the plan as a whole and for each
proposed program, using the total resource cost, societal, utility cost, and
ratepayer impact and participant tests. If the utility uses a test other than
the societal test as the criterion for determining cost-effectiveness of
utility implementation of energy efficiency measures, the utility shall
describe and justify its use of the alternative test or combination of tests
and compare the resulting impacts with the impacts resulting from the societal
test. The utility shall describe and justify the level or levels of
cost-effectiveness, if greater or less than a cost-effectiveness ratio of 1.0,
to be used as a threshold for determining cost-effectiveness of programs. The
utility's threshold of cost-effectiveness for its plan as a whole shall be a
cost-effectiveness ratio of 1.0 or greater.
(2) The utility's analyses shall use inputs
or factors reasonably expected to influence cost-effective implementation of
programs, including escalation rates and avoided costs for each cost and
benefit component of the cost-effectiveness test, to reflect changes over the
useful lives of the programs.
(3)
The utility shall provide the analyses, assumptions, inputs, and results of
cost-effectiveness tests, including the cost-effectiveness ratios and net
benefits, for the plans as a whole and for each program. Low-income,
tree-planting, educational programs, and assessments of consumers' needs for
information to make effective choices regarding energy use and energy
efficiency shall not be tested for cost-effectiveness unless the utility wishes
to present the results of cost-effectiveness tests for informational
purposes.
d. Descriptions
of each program. If a proposed program is identical to an existing program, the
utility may reference the program description currently in effect. A
description of each proposed program shall include:
(1) The name of the program.
(2) The customers the program
targets.
(3) The energy efficiency
or demand response measures promoted by the program.
(4) The proposed utility promotional
techniques, including the rebates or incentives offered through the
program.
(5) The proposed rates of
program participation or implementation of measures, including both eligible
and estimated actual participants.
e. The estimated annual energy and demand
savings for the plan and each program for each year the program is promoted by
the plan. The utility shall estimate gross and net capacity and energy savings,
accounting for free riders, take-back effects, spillover (free drivers), market
effects, and persistence of energy savings.
f. The budget for the plan and for each
program for each year of implementation or for each of the next five years of
implementation, whichever is less, itemized by proposed costs. The budget shall
be consistent with the accounting plan required pursuant to subrule 35.9(1).
The budget may include amounts collected pursuant to Iowa Code section
476.10A.
The requirements of paragraphs
"f" and
"g"
shall not apply to any energy efficiency plan or demand response plan approved
as of March 31, 2019, or modified under rule
199-35.10 (476) during the
five-year term of such plan.
g. The
plan and program budgets, which shall be categorized into:
(1) Overhead, which consists of:
1. Planning and design costs, which include
internal and third-party expenses associated with program development, design
for new programs, modifications to existing programs, the assessment of
potential, and the Iowa Technical Reference Manual.
2. Administrative costs, which include
internal and third-party expenses associated with program implementation and
support functions such as: fully loaded utility labor costs; office supplies
and technology costs associated with program operations and delivery; program
implementation costs; and labor costs for vendors required for successful
operation and implementation of programs.
3. Advertising and promotional costs, which
include internal and third-party labor and materials expenses associated with
program-specific marketing and training and demonstration aimed at promoting
energy efficiency awareness or the programs included in a utility's plan.
Advertising which is part of an approved energy efficiency or demand response
plan is deemed to be advertising required by the commission for purposes of
Iowa Code section 476.18(3).
4.
Monitoring and evaluation costs, which include internal and third-party
expenses associated with ongoing program review, prepayment verification
inspections, and evaluation, measurement and verification required to be
completed at least once during the five-year plan.
5. Education costs, which include internal
and third-party labor and material expenses associated with program-specific or
general energy efficiency education.
6. Miscellaneous costs, which are all other
costs related to the implementation of the plan which are not attributable to
any other cost category.
(2) Incentives, which consist of:
1. Customer incentives, which are utility
contributions provided to participants, such as rebates, direct-install
measures, energy audits, energy efficiency kits, and low-income weatherization.
This includes nonrebate contributions to participants, such as loan subsidies,
payments to dealers, rate credits, and bill credits.
2. Equipment costs, which include
program-specific costs associated with hardware purchased by the utility and
given to customers to facilitate the customer's participation in the
program.
3. Installation costs,
which include internal and third-party labor associated with installation or
replacement of equipment provided to participants, such as the installation of
direct-install measures or load control devices.
Cost categories shall be further described by the following
subcategories: classifications of persons to be working on energy efficiency
and demand response programs, full-time equivalents, dollar amounts of labor
costs, and the name of outside firm(s) employed and a description of service(s)
to be provided.
h. A description of a pilot project as a
program, if the pilot project is justified by the utility. Pilot projects shall
explore areas of innovative or unproven approaches, as provided in Iowa Code
section 476.1. The proposed evaluation procedures for the pilot program shall
be included.
i. The rate impacts
and average bill impacts, by customer class, resulting from the plan.
j. The utility's forecasted electric or
natural gas or electric and natural gas annual Iowa retail rate revenue for
each of the five plan years. The utility shall identify all adjustments and
eliminations to its revenue forecasts, and identify the Federal Energy
Regulatory Commission (FERC) accounts used to develop its forecasts.
k. A monitoring and evaluation plan. The
utility shall describe how it proposes to monitor and evaluate the
implementation of its proposed programs and plan and shall show how it will
accumulate and validate the information needed to measure the plan's
performance against the standards. The utility shall include a timeline that
outlines each phase of the monitoring and evaluation plan. The utility shall
propose a format for monitoring reports and describe how annual results will be
reported to the commission on a detailed, accurate and timely basis.
l. A summary of collaborative efforts and a
summary of collaboration participants' suggestions, utility responses to the
suggestions, and specific reasons for including or declining to include the
suggestions in the utility's energy efficiency or demand response
plans.
m. These additional
requirements for electric utilities:
(1) Load
forecast. Information specifying forecasted demand and energy use on a
calendar-year basis, which shall include:
1. A
statement, in numerical terms, of the utility's current 20-year forecasts
including reserve margin for summer and winter peak demand and for annual
energy requirements. The forecasts shall not include the effects of the
proposed programs in paragraph 35.5(4)"d," but shall include
the effects to date of current ongoing utility energy efficiency
programs.
2. The date and amount of
the utility's highest peak demand within the past five years, stated on both an
actual and a weather-normalized basis. The utility shall include an explanation
of the weathernormalization procedure.
3. A comparison of the forecasts made for
each of the previous five years to the actual and weather-normalized demand in
each of the previous five years.
4.
An explanation of all significant methods and data used, as well as assumptions
made, in the current 20-year forecast. The utility shall file all forecasts of
variables used in its demand and energy forecasts and shall separately identify
all sources of variables used, such as implicit price deflator, electricity
prices by customer class, gross domestic product, sales by customer class,
number of customers by class, fuel price forecasts for each fuel type, and
other inputs.
5. A statement of the
margin of error for each assumption or forecast.
6. An explanation of the results of
sensitivity analyses performed, including a specific statement of the degree of
sensitivity of estimated need for capacity to potential errors in assumptions,
forecasts and data. The utility may present the results and an explanation of
other methods of assessing forecast uncertainty.
(2) Class load data. Load data for each class
of customer that is served under a separate rate schedule or is identified as a
separate customer class and accounts for 10 percent or more of the utility's
demand in kW at the time of the monthly system peak for every month in the
year. If those figures are not available, the data shall be provided for each
class of customer that accounts for 10 percent of the utility's electric sales
in kWh for any month in the reporting period. The data shall be based on a
sample metering of customers that is designed to achieve a statistically
expected accuracy of plus or minus 10 percent at the 90 percent confidence
level for loads during the yearly system peak hour(s). These data must appear
in all filings, except as provided for in numbered paragraph
35.5(4)
"m"(2)"3."
1. The
following information shall be provided for each month of the previous year:
* Total system class maximum demand (in kW), number of
customers in the class, and system class sales (in kWh);
* Jurisdictional class contribution (in kW) to the monthly
maximum system coincident demand as allocated to jurisdiction;
* Total class contribution (in kW) to the monthly maximum
system coincident demand, if not previously reported;
* Total system class maximum demand (in kW) allocated to
jurisdiction, if not previously reported; and
* Hourly total system class loads for a typical weekday, a
typical weekend day, the day of the class maximum demand, and the day of the
system peak.
2. The company
shall file an explanation, with all supporting workpapers and source documents,
as to how class maximum demand and class contribution to the maximum system
coincident demand were allocated to jurisdiction.
3. The load data for each class of customer
described above may be gathered by a multijurisdictional utility on a uniform
integrated system basis rather than on a jurisdictional basis. Adjustments for
substantive and unique jurisdictional characteristics, if any, may be proposed.
The load data for each class of customer shall be collected continuously and
filed annually, except for the period associated with necessary interruptions
during any year to modify existing or implement new data collection methods.
Data filed for the period of interruption shall be estimated. An explanation of
the estimation technique shall be filed with the data. To the extent consistent
with sound sampling and the required accuracy standards, an electric public
utility is not required to annually change the customers being
sampled.
(3) Existing
capacity and firm commitments. Information specifying the existing generating
capacity and firm commitments to provide service. The utility shall include in
its filing a copy of its most recent load and capability report submitted to
Midcontinent Independent System Operator, Inc. (MISO).
1. For each generating unit owned or leased
by the utility, in whole or in part, the energy efficiency and demand response
plan shall include the following information:
* Both summer and winter net generating capability ratings as
reported to the North American Electric Reliability Corporation (NERC).
* The estimated remaining time before the unit will be
retired or require life extension.
2. For each commitment to own or lease future
generating firm capacity, the plan shall include the following information:
* The type of generating capacity.
* The anticipated in-service year of the capacity.
* The anticipated life of the generating capacity.
* Both summer and winter net generating capability ratings as
reported to the NERC.
3. For
each capacity purchase commitment which is for a period of six months or
longer, the plan shall include the following information:
* The entity with whom commitments have been made and the
time periods for each commitment.
* The capacity levels in each year for the
commitment.
4. For each
capacity sale commitment which is for a period of six months or longer, the
plan shall include the following information:
* The entity with whom a commitment has been made and the
time periods for the commitment.
* The capacity levels in each year.
* The capacity payments to be received per kW per year in
each year.
* The energy payments to be received per kWh per year.
* Any other payments the utility receives in each
year.
(4) Capacity
surpluses and shortfalls. Information identifying projected capacity surpluses
and shortfalls over the 20-year planning horizon, which shall include:
1. A numerical and graphical representation
of the utility's 20-year planning horizon comparing forecasted demand in each
year from subparagraph 35.5(4)"m"(1) to committed capacity in
each year from numbered paragraphs 35.5(4)"m"(3)"1" to
35.5(4)"m"(3)"4." Forecasted peak demand shall include reserve
requirements.
2. For each year of
the 20-year planning horizon, the plan shall list in megawatts (MW) the amount
by which committed capacity either exceeds or falls below the forecasted
demand.
(5) Capacity
outside the utility's system. Information about capacity outside of the
utility's system that could meet its future needs including, but not limited
to, cogeneration and independent power producers, expected to be available to
the utility during each of the 20 years in the planning horizon. The utility
shall include in its filing a copy of its most recent load and capability
report submitted to MISO.
(6)
Future supply options and costs. Information about future supply options and
their costs identified by the utility as the most effective means of satisfying
all projected capacity shortfalls in the 20-year planning horizon in
subparagraph 35.5(4)
"m"(4), which shall include:
1. The following information which describes
each future supply option as applicable:
* The anticipated year the supply option would be
needed.
* The anticipated type of supply option, by fuel.
* The anticipated net capacity of the supply
option.
2. The utility shall
use the actual capacity cost of any capacity purchase identified in numbered
paragraph 35.5(4)"m"(6)"1" and shall provide the anticipated
annual cost per net kW per year.
3.
The utility shall use the installed cost of a combustion turbine as a proxy for
the capacity cost of any power plant identified in numbered paragraph
35.5(4)
"m"(6)"1." For the first power plant option specified
in numbered paragraph 35.5(4)
"m"(6)"1," the following
information shall be provided:
* The anticipated life.
* The anticipated total capital costs per net kW, including
allowance for funds used during construction (AFUDC) if applicable.
* The anticipated revenue requirement of the capital costs
per net kW per year.
* The anticipated revenue requirement of the annual fixed
operations and maintenance costs, including property taxes, per net kW for each
year of the 20-year planning horizon.
* The anticipated net present value of the revenue
requirements per net kW.
* The anticipated revenue requirement per net kW per year
calculated by utilization of an economic carrying charge.
* The after-tax discount rate used to calculate the revenue
requirement per net kW per year over the life of the supply option.
* Adjustment rates (for example, inflation or escalation
rates) used to derive each future cost in numbered paragraph
35.5(4)"m"(6)"3."
4. The capacity costs of the new supply
options allocated to costing periods. The utility shall describe its method of
allocating capacity costs to costing periods. The utility shall specify the
hours, days, and weeks which constitute its costing periods. For each supply
option identified in numbered paragraph 35.5(4)
"m"(6)"1," the
plan shall include:
* The anticipated annual cost per net kW per year of capacity
purchases from numbered paragraph 35.5(4)"m"(6)"2" allocated
to each costing period if it is the highest cost supply option in that
year.
* The anticipated total revenue requirement per net kW per
year from numbered paragraph 35.5(4)"m"(6)"3" allocated to
each costing period if it is the highest cost supply option in that
year.
(7) Avoided
capacity and energy costs. Avoided capacity costs shall be based on the future
supply option with the highest value for each year in the 20-year planning
horizon identified in numbered paragraph 35.5(4)
"m"(6).
Avoided energy costs shall be based on the marginal costs of the utility's
generating units or purchases. The utility shall use the same costing periods
identified in numbered paragraph 35.5(4)
"m"(6)"2" when
calculating avoided capacity and energy costs. A party may submit, and the
commission shall consider, alternative avoided capacity and energy costs
derived by an alternative method. A party submitting alternative avoided costs
shall also submit an explanation of the alternative method.
1. Avoided capacity costs. Calculations of
avoided capacity costs in each costing period shall be based on the following
formula:
AVOIDED CAPACITY COST = C × (1 + RM) × (1 + DLF)
× (1 + EF)
C (capacity) is the greater of NC or RC.
NC (new capacity) is the value of future capacity purchase
costs or future capacity costs expressed in dollars per net kW per year of the
utility's new supply options from numbered paragraphs
35.5(4)"m"(6) "2" and "3" in each costing period.
RC (resalable capacity) is the value of existing capacity
expressed in dollars per net kW per year that could be sold to other parties in
each costing period.
RM (reserve margin) is the generation reserve margin
criterion adopted by the utility.
DLF (demand loss factor) is the system demand loss factor
expressed as a fraction of the net power generated, purchased, or interchanged
in each costing period. For example, the peak system demand loss factor would
be equal to peak system power loss (MW) divided by the net system peak load
(MW) for each costing period.
EF (externality factor) is a 10 percent factor applied to
avoided capacity costs in each costing period to account for societal costs of
supplying energy. In addition, the utility may propose a different externality
factor but must document the factor's accuracy.
2. Avoided energy costs. Calculations of
avoided energy costs in each costing period shall be based on the following
formula:
AVOIDED ENERGY COSTS = MEC × (1 + ELF) × (1 +
EF)
MEC (marginal energy cost) is the marginal energy cost
expressed in dollars per kWh, inclusive of variable operations and maintenance
costs, for electricity in each costing period.
ELF (system energy loss factor) is the system energy loss
factor expressed as a fraction of net energy generated, purchased, or
interchanged in each costing period.
EF (externality factor) is a 10 percent factor applied to
avoided energy costs in each costing period to account for societal costs of
supplying energy. In addition, the utility may propose a different externality
factor but must submit documentation of the factor's accuracy.
n. Additional
requirements for natural gas utilities:
(1)
Forecast of demand and transportation volumes. Information specifying the
natural gas utility's demand and transportation volume forecasts, which
includes:
1. A statement in numerical terms of
the utility's current 12-month and five-year forecasts of total annual
throughput and peak day demand, including reserve margin, based on the
purchased gas adjustment (PGA) year by customer class. The forecasts shall not
include the effects of the proposed energy efficiency programs in paragraph
35.5(4)"d," but shall include the effects to date of current
ongoing utility energy efficiency programs.
2. A statement in numerical terms of the
utility's highest peak day demand and annual throughput for the past five years
by customer class.
3. A comparison
of the forecasts made for the preceding five years to the actual and
weather-normalized peak day demand and annual throughput by customer class,
including an explanation of the weather-normalization procedure.
4. A forecast of the utility's demand for
transportation volume for both peak day demand and annual throughput for each
of the next five years.
5. The
existing contract deliverability by supplier, contract and rate schedule for
the length of each contract.
6. An
explanation of all significant methods and data used, as well as assumptions
made, in the current five-year forecast(s). The utility shall file all
forecasts of variables used in its demand and energy forecasts. If variables
are not forecasted, the utility shall indicate all sources of variable
inputs.
7. A statement of the
margin of error for each assumption or forecast.
8. An explanation of the results of the
sensitivity analysis performed by the utility, including a specific statement
of the degree of sensitivity of estimated need for capacity to potential errors
in assumptions, forecasts, and data.
(2) Capacity surpluses and shortfalls.
Information identifying projected capacity surpluses and shortfalls over the
five-year planning horizon, which includes a numerical and graphical
representation of the utility's five-year planning horizon comparing forecasted
peak day demand in each year from numbered paragraph
35.5(4)"n"(1) "1" to the total of existing contract
deliverability, from numbered paragraph 35.5(4)"n"(1) "5." The
comparison shall list in dth or Mcf any amount for any year that contract
deliverability falls below the forecast of peak day demand. Forecasted peak day
demand shall include reserve margin.
(3) Supply options. Information about new
supply options identified by the utility as the most effective means of
satisfying all projected capacity shortfall in the 12-month and five-year
planning horizons in subparagraph 35.5(4)
"n"(2). For each
supply option identified, the plan shall include:
1. The year the option would be
needed.
2. The type of
option.
3. The net peak day
capacity.
4. The estimated future
capacity costs per dth or Mcf of peak day demand of the options.
5. The estimated future energy costs per dth
or Mcf of each option in current dollars.
6. A description of the method used to
estimate future costs.
(4) Natural gas avoided capacity and energy
costs. Information regarding avoided costs shall specify the days and weeks
which constitute the utility's peak and off-peak periods. Avoided costs shall
be calculated for the peak and off-peak periods and adjusted for inflation to
derive an annual avoided cost over a 20-year period. In addition, all parties
may submit information specifying the hours, days, and weeks which constitute
alternative costing periods. A party may submit, and the commission shall
consider, alternative avoided capacity and energy costs derived by an
alternative method. A party submitting alternative avoided cost methodology
shall also submit an explanation of the alternative method.
1. Avoided capacity costs. Calculations of
avoided capacity costs in the peak and off-peak periods shall be based on the
following formula:
AVOIDED CAPACITY COSTS = [(D + OC) × (1 + RM)] ×
(1 + EF)
D (demand) is the greater of CD or FD.
CD (current demand cost) is the utility's average demand cost
expressed in dollars per dth or Mcf during peak and off-peak periods.
FD (future demand costs) is the utility's average future
demand cost over the 20-year period expressed in dollars per dth or Mcf when
supplying natural gas during peak and off-peak periods.
RM (reserve margin) is the reserve margin adopted by the
utility.
OC (other cost) is the value of any other costs per dth or
Mcf related to the acquisition of natural gas supply or transportation by the
utility over the 20-year period in the peak and off-peak periods.
EF (externality factor) is a 7.5 percent factor applied to
avoided capacity costs in the peak and off-peak periods to account for societal
costs of supplying energy. In addition, the utility may propose a different
externality factor but must submit documentation of the factor's
accuracy.
2. Avoided energy
costs. Calculations of avoided energy costs in the peak and off-peak periods on
a seasonal basis shall be based on the following formula:
AVOIDED ENERGY COSTS = (E + VOM) × (1 + EF)
E (energy costs) is the greater of ME or FE.
ME (current marginal energy costs) is the utility's current
marginal energy costs expressed in dollars per dth or Mcf during peak and
off-peak periods.
FE (future energy costs) is the utility's average future
energy costs over the 20-year period expressed in dollars per dth or Mcf during
peak and off-peak periods.
VOM (variable operations and maintenance costs) is the
utility's average variable operations and maintenance costs over the 20-year
period expressed in dollars per dth or Mcf during peak and off-peak
periods.
EF (externality factor) is a 7.5 percent factor applied to
avoided energy costs in the peak and off-peak periods to account for societal
costs of supplying energy. In addition, the utility may propose a different
externality factor but must submit documentation of the factor's
accuracy.
