Iowa Administrative Code › Agency 199 - Utilities Division › Utilities and Transportation Divisions › Chapter 35 - Energy Efficiency and Demand Response Planning and Reporting for Natural Gas and Electric Utilities Required to Be Rate-regulated › Rule 199-35.5 - Energy Efficiency and Demand Response Plan Requirements

Current through Register Vol. 47, No. 3, July 24, 2024
(1) The utility
				shall file with the commission an energy efficiency plan listing all proposed
				energy efficiency programs. An electric utility shall file a demand response
				plan listing all proposed demand response programs.
(2) The utility's energy efficiency and
				demand response plans shall be supported by testimony, exhibits, and workpapers
				including Microsoft Excel or similar software versions of exhibits and
				workpapers. The testimony, exhibits, and workpapers shall be filed in
				compliance with the commission's filing standards located on the commission's
				electronic filing website.
(3) A
				utility's plan shall include a range of programs which address all customer
				classes across its Iowa jurisdictional territory. At a minimum, the plan shall
				include a program for qualified low-income residential customers, including a
				cooperative program with any community action agency, as defined and listed on
				the Iowa department of human rights website, within the utility's service area
				to implement countywide or communitywide energy efficiency programs for
				qualified low-income persons. The utility shall consider including in its plan
				a program for tree-planting, educational programming, and assessments of
				consumers' needs for information to make effective choices regarding energy use
				and energy efficiency.
(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 Ã— (1 + RM) Ã— (1 + DLF)
				  Ã— (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 Ã— (1 + ELF) Ã— (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) Ã— (1 + RM)] Ã—
				  (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) Ã— (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.