ARC 4709C
UTILITIES DIVISION[199]
Adopted and Filed
Rule making related to planning and reporting for rate-regulated utilities
The Utilities Board hereby rescinds Chapter 35, “Energy Efficiency Planning and Cost Review,” and adopts a new Chapter 35, “Energy Efficiency and Demand Response Planning and Reporting for Natural Gas and Electric Utilities Required to Be Rate-Regulated,” Iowa Administrative Code.
Legal Authority for Rule Making
This rule making is adopted under the authority provided in Iowa Code sections 476.2 and 476.6(15).
State or Federal Law Implemented
This rule making implements, in whole or in part, Iowa Code sections 476.2 and 476.6(15).
Purpose and Summary
The Board reviewed Chapter 35 as part of its five-year comprehensive review in accordance with Iowa Code section 17A.7(2). The purpose of the comprehensive review is to identify and update rules that are outdated, redundant, or inconsistent with statutes or other administrative rules.  During the course of the Board’s comprehensive review of Chapter 35 and the promulgation of this rule making, the Legislature passed and the Governor signed legislation (2018 Iowa Acts, chapter 1135 and 2019 Iowa Acts, chapter 89, section 39) amending the energy efficiency provisions of Iowa Code chapter 476.
The Board issued an order adopting rule making on September 9, 2019. The order is available on the Board’s electronic filing system, efs.iowa.gov, under Docket No.	RMU-2016-0018.
Public Comment and Changes to Rule Making
Notice of Intended Action for this rule making was published in the Iowa Administrative Bulletin on February 13, 2019, as ARC 4285C. An oral presentation was held on March 13, 2019, at 9 a.m.	in the Board Hearing Room, 1375 East Court Avenue, Des Moines, Iowa.
At the oral presentation, participating stakeholders requested the Board hold a workshop. On April 26, 2019, the Board held a workshop and issued an order allowing for the submission of additional written comments.
Following publication of the Notice of Intended Action, the Board received written comments from Interstate Power and Light Company, the Iowa Business Energy Coalition, Black Hills/Iowa Gas Utility Company, LLC d/b/a Black Hills Energy, MidAmerican Energy Company, the Environmental Law and Policy Center and the Iowa Environmental Council, and the Large Energy Group.
The Board made a number of changes from the Notice, most of which were made either at the request of stakeholders or to ensure consistency with Iowa Code chapter 476 as amended. The majority of changes were shared with stakeholders, and stakeholders were provided opportunities to comment on the changes prior to adoption. In rules 199—35.3(476), 199—35.4(476), 199—35.6(476), 199—35.7(476), 199—35.9(476), and 199—35.10(476), the Board made minor clarifying changes to provide for greater internal consistency and to make the rules easier to read and understand. In rule 199—35.2(476), the Board added definitions for “annual Iowa retail rate revenue,” “economic potential,” “energy savings performance standards,” and “non-energy benefits,” and made minor changes to other definitions at the request of stakeholders or to improve clarity. Based on stakeholder consensus, in rule 199—35.5(476), the Board reinserted a number of provisions, which are contained in current Chapter 35 and which the Board had proposed to delete (e.g., the electric utility provisions in current rule 199—35.9(476) have been inserted in paragraph 35.5(4)“m,” the natural gas provisions in current rule 199—35.10(476) have been inserted in paragraph 35.5(4)“n,” and the pilot program provisions of current subrule 35.8(10) have been inserted in paragraph 35.5(4)“h”). Finally, in rule 199—35.11(476), the Board added a clause at the end of subrules 35.11(1) and 35.11(2) providing that a prudence review may be based on discovery conducted in review of a utility’s annual reports.
After reviewing the stakeholder comments and the legislative amendments, the Board rescinds current Chapter 35 and adopts a new Chapter 35 that reflects changes made to ensure consistency with Iowa Code chapter 476 as amended and other Board administrative rules.
Adoption of Rule Making
This rule making was adopted by the Board on September 9, 2019.
Fiscal Impact
Because the amendments update existing rules in light of statutory changes, it is anticipated that this rule making will have no fiscal impact.
Jobs Impact
After analysis and review of this rule making, no impact on jobs has been found.
Waivers
Any person who believes that the application of the discretionary provisions of this rule making would result in hardship or injustice to that person may petition the Board for a waiver of the discretionary provisions, if any.
Review by Administrative Rules Review Committee
The Administrative Rules Review Committee, a bipartisan legislative committee which oversees rule making by executive branch agencies, may, on its own motion or on written request by any individual or group, review this rule making at its regular monthly meeting or at a special meeting. The Committee’s meetings are open to the public, and interested persons may be heard as provided in Iowa Code section 17A.8(6).
Effective Date
This rule making will become effective on November 13, 2019.
The following rule-making action is adopted:
	Rescind 199—Chapter 35 and adopt the following new chapter in lieu thereof:
CHAPTER 35
ENERGY EFFICIENCY AND DEMAND RESPONSE PLANNING AND REPORTING FOR NATURAL GAS AND ELECTRIC UTILITIES REQUIRED TO BE RATE-REGULATED
199—35.1(476) Authority and purpose. These rules are intended to implement Iowa Code sections 476.6(13) and 476.6(15) relating to the energy efficiency and demand response plans and reports filed by the natural gas and electric utilities required by statute to be rate-regulated. The purpose of these rules is to establish requirements for energy efficiency and demand response plans, modifications, prudence reviews, and cost-recovery tariffs.
199—35.2(476) Definitions. The following words and terms, when used in this chapter, shall have the meanings shown below:
“Annual Iowa retail rate revenue” means the utility’s expected revenue forecast based on customer growth rate, usage per customer, volumes, margin rate, customer charge rate, and the cost of generation or fuel.
“Assessment of potential” means development of cost-effective energy and capacity savings available from actual and projected customer usage by applying commercially available technology and improved operating practices to energy-using equipment and buildings and considering market factors including, but not limited to, the effects of rate impacts, the need to capture lost opportunities, the non-energy benefits of measures, and the strategic value of energy efficiency and demand response to the utility.
“Avoided cost” means the cost the utility would have to pay to provide energy and capacity from alternative sources of supply available to utilities as calculated pursuant to subparagraphs 35.5(4)“m”(7) and 35.5(4)“n”(4).
“Cost-effectiveness tests” means one of the five acceptable economic tests used to compare the present value of applicable benefits to the present value of applicable costs of an energy efficiency or demand response program or plan. The tests are the participant test, the ratepayer impact test, the societal test, the total resource cost test, and the utility cost test. A program or plan passes a cost-effectiveness test if the cost-effectiveness ratio is equal to or greater than one.
“Customer incentive” means an amount or amounts provided to or on behalf of customers for the purpose of having customers participate in energy efficiency programs. Incentives include, but are not limited to, rebates, loan subsidies, payments to dealers, rate credits, bill credits, the cost of energy audits, the cost of equipment given to customers, and the cost of installing such equipment. Customer incentives do not include the cost of information provided by the utility, nor do they include customers’ bill reductions associated with reduced energy usage due to the implementation of energy efficiency programs. For the purposes of energy efficiency pricing strategies, “incentive” means the difference between a customer’s bill on an energy efficiency customized rate and the customer’s bill on a traditional rate considering factors such as the elasticity of demand.
“Demand response” means changes in a customer’s consumption pattern in response to changes in the price of electricity over time, or in response to incentive payments to induce reduced consumption during periods of high wholesale prices or when system reliability is jeopardized.
“Economic potential” means the energy and capacity savings that result in future years when measures are adopted or applied by customers at the time it is economical to do so. For purposes of this chapter, economic potential may be determined by comparing the utility’s avoided cost savings to the incremental cost of the measure.
“Energy efficiency measures” means activities on the customers’ side of the meter which reduce customers’ energy use or demand including, but not limited to, end-use efficiency improvements or pricing strategies.
“Energy savings performance standards” means those standards which shall be cost-effectively achieved, with the exception of programs for qualified low-income persons, tree-planting programs, educational programs, and assessments of consumers’ needs for information to make effective choices regarding energy use and energy efficiency, and includes the annual capacity savings stated either in kilowatt per day (kW/day) or in dekatherm per day (dth/day) or in thousand cubic feet per day (Mcf/day) and the annual energy savings stated in either kilowatt hour (kWh) or dth or Mcf.
“Free riders” means program participants who would have implemented energy efficiency measures or practices even without the program.
“Marginal energy cost” means the cost associated with supplying the next Mcf or dth of natural gas for a natural gas utility and the energy or fuel cost associated with generating or purchasing the next kWh of electricity for an electric utility.
“Market effects” means a change in the structure of a market or the behavior of participants in a market that is reflective of an increase (or decrease) in the adoption of energy-efficient products, services, or practices and is related to market intervention(s) (e.g., programs).
“Net benefits” means the present value of benefits less the present value of costs as defined in the cost-effectiveness test.
“Non-energy benefits” means the many and diverse benefits produced by energy efficiency in addition to energy and demand savings as used and applied in the Iowa Technical Reference Manual. The beneficiaries of these benefits can be utility systems, participants and society.
“Participant test” means an economic test used to compare the present value of benefits to the present value of costs over the useful life of an energy efficiency or demand response measure or program from the participant’s perspective. Present values are calculated using a discount rate appropriate to the class of customers to which the energy efficiency or demand response measure or program is targeted. Benefits are the sum of the present values of the customers’ bill reductions, tax credits, non-energy benefits and customer incentives for each year of the useful life of an energy efficiency or demand response measure or program. Costs are the sum of present values of the customer participation costs (including initial capital costs, ongoing operations and maintenance costs, removal costs less a salvage value of existing equipment, and the value of the customer’s time in arranging installation, if significant) and any resulting bill increases for each year of the useful life of the measure or program. The calculation of bill increases and decreases must account for any time-differentiated rates to the customer or class of customers being analyzed.
“Persistence of energy savings” means the savings due to changed operating hours, human behavior, interactive factors, and the degradation in equipment efficiency over the life of the measure compared to the baseline.
“Process-oriented industrial assessment” means an analysis which promotes the adoption of energy efficiency measures by examining the facilities, operations and equipment of an industrial customer in which energy efficiency opportunities may be embedded.
“Ratepayer impact test” means an economic test used to compare the present value of the benefits to the present value of the costs over the useful life of an energy efficiency or demand response measure or program from a rate level or utility bill perspective. Present values are calculated using the utility’s discount rate. Benefits are the sum of the present values of utility avoided capacity and energy costs (excluding the externality factor) and any revenue gains due to the energy efficiency or demand response measure or program for each year of the useful life of the measure or program. Costs are the sum of the present values of utility increased supply costs, revenue losses due to the energy efficiency or demand response measures, utility program costs, and customer incentives for each year of the useful life of the measure or program. The calculation of utility avoided capacity and energy, increased utility supply costs, and revenue gains and losses must use the utility costing periods.
“Societal test” means an economic test used to compare the present value of the benefits to the present value of the costs over the useful life of an energy efficiency or demand response measure or program from a societal perspective. Present values are calculated using a 12-month average of the 10-year and 30-year Treasury Bond rate as the discount rate. The average shall be calculated using the most recent 12 months at the time the utility calculates its cost-effectiveness tests for its energy efficiency or demand response plan. Benefits are the sum of the present values of the utility avoided supply, non-energy benefits, and energy costs including the effects of externalities. Costs are the sum of the present values of utility program costs (excluding customer incentives), participant costs, and any increased utility supply costs for each year of the useful life of the measure or program. The calculation of utility avoided capacity and energy and increased utility supply costs must use the utility costing periods.
“Spillover (free drivers)” means the reduction in energy consumption or demand, or the reduction in both, caused by the presence of an energy efficiency or demand response program, beyond the program-related gross savings of the participants and without financial or technical assistance from the program. The term “free drivers” may be used for individuals who have spillover effects.
“Take-back effect” means a tendency to increase energy use in a facility, or for an appliance, as a result of increased efficiency of energy use. For example, a customer’s installation of high-efficiency light bulbs and the subsequent longer operation of lights constitutes “taking back” some of the energy otherwise saved by the efficient lighting.
“Total resource cost test” means an economic test used to compare the present value of the benefits to the present value of the costs over the useful life of an energy efficiency or demand response measure or program from a resource perspective. Present values are calculated using a 12-month average of the 10-year and 30-year Treasury Bond rate as the discount rate. The average shall be calculated using the most recent 12 months at the time the utility calculates its cost-effectiveness tests for its energy efficiency or demand response plan. Benefits are the sum of the present values of the utility avoided supply, energy costs, non-energy benefits, and federal tax credits. Costs are the sum of the present values of utility program costs (excluding customer incentives), participant costs, and any increased utility supply costs for each year of the useful life of the measure or program. The calculation of utility avoided capacity and energy and increased utility supply costs must use the utility costing periods.
“Useful life” means the number of years an energy efficiency measure will produce benefits.
“Utility cost test” means an economic test used to compare the present value of the benefits to the present value of the costs over the useful life of an energy efficiency or demand response measure or program from the utility revenue requirement perspective. Present values are calculated using the utility’s discount rate. Benefits are the sum of the present values of each year’s utility avoided capacity, non-energy benefits, and energy costs (excluding the externality factor) over the useful life of the measure or program. Costs are the sum of the present values of the utility’s program costs, customer incentives, and any increased utility supply costs for each year of the useful life of the measure or program. The calculation of utility avoided capacity and energy and increased utility supply costs must use the utility costing periods.
199—35.3(476) Energy efficiency and demand response plan filing.
	35.3(1) Each electric and natural gas utility shall file a five-year energy efficiency plan. Each electric utility shall file a five-year demand response plan. Combination electric and natural gas utilities may file combined assessments of potential and energy efficiency and demand response plans. Combined plans shall separately specify which energy efficiency programs and costs are attributable to the electric operation, which are attributable to the natural gas operation, and which are attributable to both. If a combination utility files separate plans, the board may consolidate the plans for purposes of review and hearing.
	35.3(2) Written notice of the energy efficiency and demand response plans. No more than 62 days prior to filing its energy efficiency and demand response plans, a utility shall deliver a written notice of its plan filing to all affected customers. The notice shall be submitted to the board for approval not less than 45 days prior to the proposed notification of customers. Additional information not related to the energy efficiency and demand response plans shall be kept to a minimum and shall not distract from the required content. The form of the notice, once approved by the board, may not be altered except to include the rate and bill impact dollars and percentages. The type size and quality shall be easily legible. The notice shall, at a minimum, include the following elements:
	a. 	A statement that the utility will be filing energy efficiency and demand response plans with the board.
	b. 	A brief identification of the proposed energy efficiency and demand response programs, a description of benefits and savings associated with the energy efficiency and demand response plans, and the estimated annual cost of the proposed energy efficiency and demand response programs during the five-year budget time frame.
	c. 	The estimated annual rate and bill impacts of the proposed energy efficiency and demand response plans on each class of customer, and the estimated annual jurisdictional rate impact for each major customer grouping in dollars and as a percentage, with the proposed actual increases to be filed at the time of notice to customers. The utility may represent the estimated annual rate and bill impact dollars and percentages with blank spaces; however, the board may require the utility to submit additional information necessary for review of the proposed form of notice. A copy of the notice with the final annual rate and bill impact dollars and percentages shall be filed with the board at the time of customer notification.
	d. 	A statement that the board will be conducting a contested case proceeding to review the application and that a customer may file comments in the board’s electronic filing system.
	e. 	The telephone numbers, websites, email addresses, and mailing addresses of the utility, the board, and the consumer advocate, for the customer to contact with questions.
199—35.4(476) Assessment of potential and collaboration.
	35.4(1) Assessment of potential. The utility shall conduct an assessment of potential study to determine the cost-effective energy and capacity savings available from actual and projected customer usage by applying commercially available technology and improved operating practices to energy-using equipment and buildings. The utility’s assessment shall address the potential energy and capacity savings in each of ten years subsequent to the year the assessment is filed. Economic and impact analyses of measures shall address benefits and costs over the entire estimated useful lives of energy efficiency measures.
	35.4(2) Collaboration. A utility shall offer interested persons the opportunity to participate in the development of its energy efficiency and demand response plans. At a minimum, a utility shall provide the opportunity for interested persons to offer suggestions for programs and for the assessment of potential and to review and comment on a draft of the assessment of potential and energy efficiency and demand response plans proposed to be submitted by the utility. The utility may analyze proposals from participants to help determine the effects of the proposals on its plan. A participant shall have the responsibility to provide sufficient supporting information to enable the utility to analyze the participant’s proposal. The opportunity to participate shall commence at least 180 days prior to the date the utility submits its energy efficiency and demand response plans and assessment of potential to the board.
199—35.5(476) Energy efficiency and demand response plan requirements.
	35.5(1) The utility shall file with the board 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.
	35.5(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 board’s filing standards located on the board’s electronic filing website.
	35.5(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.
	35.5(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 board 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 board 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 weather-normalization 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 board 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 board 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.
199—35.6(476) Contested case proceeding.
	35.6(1) The board shall conduct a contested case proceeding for the purpose of developing specific capacity and energy savings performance standards for each utility required to be rate-regulated and reviewing energy efficiency and demand response plans and budgets designed to achieve those savings.
	35.6(2) Within 30 days after filing, each application for approval of an energy efficiency and demand response plan that is submitted with the information and supporting documentation required by this chapter, and complies with the filing requirements of 199—Chapter 14, shall be docketed as a contested case proceeding. The Iowa economic development authority shall be considered a party to the proceeding. The proceeding shall follow the applicable provisions of 199—Chapter 7.
	35.6(3) The board shall not require or allow a natural gas utility to adopt an energy efficiency plan that results in projected cumulative average annual costs that exceed 1.5 percent of the natural gas utility’s expected annual Iowa retail rate revenue, shall not require or allow an electric utility to adopt an energy efficiency plan that results in projected cumulative average annual costs that exceed 2 percent of the electric utility’s expected annual Iowa retail rate revenue, and shall not require or allow an electric utility to adopt a demand response plan that results in projected cumulative average annual costs that exceed 2 percent of the electric utility’s expected annual Iowa retail rate revenue. With the filing of its application for approval of its energy efficiency plan, each utility shall provide, for the board’s review, a calculation of the percent of the utility’s expected annual Iowa retail rate revenue, which the utility shall determine by dividing the total projected budget for the five-year plan by the total projected Iowa retail rate revenues for the five-year plan period. The calculation of a utility’s percent of Iowa retail rate revenue may be subject to confidential treatment under Iowa Code chapters 22 and 550 upon request of the utility and as determined by the board based on the board’s review of such request.
199—35.7(476) Exemptions from participation.
	35.7(1) The utility shall allow customers to request exemption from participating in the utility’s electric energy efficiency plan if the combined ratepayer impact test for the utility’s approved five-year electric energy efficiency and demand response plan is less than 1.0. The utility shall file a draft customer notice within 20 days following the board’s approval of the utility’s five-year energy efficiency plan. The form of the notice, once approved by the board, may not be altered except to include the rate and bill impact dollars and percentages. The type size and quality shall be easily legible. The notice shall, at a minimum, provide the following elements:
	a. 	A brief statement informing all customers that they are eligible to request an exemption from participation in the utility’s electric energy efficiency plan.
	b. 	The estimated annual rate and bill impacts of the approved electric energy efficiency plan on each class of customers and an estimate of the annual jurisdictional rate impact for each major customer grouping in dollars and as a percentage, with the proposed actual increases to be filed at the time of notice to customers. The utility may represent the estimated annual rate and bill impact dollars and percentages with blank spaces; however, the board may require the utility to submit additional information necessary for review of the proposed form of notice. A copy of the notice with the final annual rate and bill impact dollars and percentages shall be filed with the board at the time of customer notification.
	c. 	A statement that customers requesting to be exempt from participation in the electric energy efficiency plan will not be eligible to participate in any utility-sponsored electric energy efficiency programs and will not be eligible to receive rebates from the utility for electric energy efficiency programs during the five-year plan cycle, beginning January 1 of the first year of the five-year plan cycle.
	d. 	An explanation that customers requesting to be exempt from participation in the electric energy efficiency plan will no longer be assessed the energy efficiency cost recovery factor for the electric energy efficiency programs on their utility bills.
	e. 	An explanation that customers requesting to be exempt from participation in the electric energy efficiency plan will be eligible to participate in demand response and natural gas energy efficiency programs and will be assessed costs related to those programs on their utility bills.
	f. 	A statement that the exemption from participation in the electric energy efficiency plan is applicable for the five-year plan cycle. The ability to request an exemption from participation in future electric energy efficiency plans will depend on the specifics of the utility’s energy efficiency plan and demand response plan filing as approved by the board.
	g. 	The utility’s telephone number, website address, and email address the customer should use to request an exemption from participation in the electric energy efficiency plan.
	h. 	A deadline by which customers must request an exemption. The deadline shall not be less than 30 days from the date of the notice.
	35.7(2) The utility shall deliver the approved notice to all affected customers within 30 days of the board approving the notice.
199—35.8(476) Annual reporting requirements. Each utility shall file by May 1 of each year an energy efficiency annual report which shall include the utility’s energy efficiency and demand response spending compared to the approved budgets, actual demand and energy savings compared to the performance standards approved by the board, cost-effectiveness results for the prior calendar year, the results of any monitoring and verification activities, any additional information pertinent to the implementation or performance of the energy efficiency or demand response plan for the previous calendar year such as changes in outside firms used to implement energy efficiency programs, updates on pilot projects, and other information as required by board order.
199—35.9(476) Energy efficiency and demand response cost recovery. Each utility shall be allowed to recover the authorized energy efficiency and demand response plan expenditures adjusted for any overcollections or undercollections calculated on an annual basis. The utility may propose to recover the portion of the costs of process-oriented industrial assessments related to energy efficiency.
	35.9(1) Accounting for costs. Each utility shall maintain accounting plans and procedures to account for all energy efficiency and demand response costs.
	a. 	Each utility shall maintain a subaccount system, work order system, or accounting system which identifies individual costs by each program.
	b. 	Each utility shall maintain accurate employee, equipment, material, and other records which identify all amounts related to each individual energy efficiency or demand response program.
	35.9(2) Automatic adjustment mechanism. Each utility shall file by June 1 of each year energy efficiency and demand response costs proposed to be recovered in rates for the 12-month recovery period beginning at the start of the first utility billing month at least 30 days following board approval.
	35.9(3) Energy efficiency cost recovery (EECR) and demand response cost recovery (DRCR) factors. Each utility shall calculate an EECR factor to recover the costs associated with the energy efficiency plan, and each electric utility shall also calculate a DRCR factor to recover costs associated with the demand response plan. The utility shall calculate EECR/DRCR factors separately for each customer classification or grouping previously approved by the board. A utility shall not use customer classifications or allocations of indirect or other related costs, other than those previously approved by the board, without filing for a modification of the energy efficiency and demand response plan and receiving board approval. Each utility may elect to file its first EECR and DRCR factors up to 120 days after November 13, 2019.
	a. 	EECR/DRCR factors shall be calculated according to the following formula:

EECR/DRCR factor	=	authorized recovery + overcollection/undercollection	
		annual sales units	
	b. 	EECR/DRCR factor is the energy efficiency or demand response recovery amount per unit of sales.
	c. 	Authorized recovery is the difference between the actual energy efficiency or demand response expenditures by customer class for the previous calendar year and the approved energy efficiency or demand response budget by customer class for the previous calendar year plus the approved energy efficiency or demand response budget by customer class for the current calendar year.
	d. 	Overcollection or undercollection is the actual amount recovered by customer class for the previous recovery period less the amount authorized to be recovered by customer class for the previous recovery period. This may also include adjustments ordered by the board in prudence reviews.
	e. 	Annual sales units are the estimated sales for the 12-month recovery period for customers who have not requested an exemption as allowed by rule 199—35.7(476).
	35.9(4) Filing requirements. Each utility proposing to recover energy efficiency or demand response costs through an automatic adjustment mechanism shall provide the following information:
	a. 	The filing shall restate the derivation of each EECR/DRCR factor previously approved by the board.
	b. 	The filing shall include new EECR/DRCR factors based on allocation methods and customer classifications and groupings approved by the board in previous proceedings.
	c. 	The filing shall include all worksheets and detailed supporting data used to determine new EECR/DRCR factors. Information already on file with the board may be incorporated by reference in the filing.
	d. 	The filing shall include a reconciliation comparing the amounts actually collected by the previous EECR/DRCR factors to the amounts expended. Overcollection or undercollection shall be used to compute adjustment factors.
	e. 	If the board has determined in a prudence review that previously recovered energy efficiency or demand response costs were imprudently incurred, adjustment factors shall include reductions for these amounts.
	35.9(5) Tariff sheets. Upon approval of the new EECR/DRCR factors, the utility shall file separate tariff sheets for board approval to implement the EECR/DRCR factors in the utility’s rates.
	35.9(6) Customers’ bills.
	a. 	Each electric and natural gas utility shall include the EECR factor, the customer’s usage, and the dollar amount charge on the customer’s bill. Customers who receive one bill for electric and natural gas service shall have a separate line item on the bill for the electric EECR and the natural gas EECR.
	b. 	Each electric utility shall represent the DRCR factor, the customer’s usage, and the dollar amount charge on the customer’s bill.
199—35.10(476) Modification of an approved plan.
	35.10(1) An approved energy efficiency plan or an approved demand response plan and associated budget may be modified if the modification is approved by the board.
	a. 	Electric utilities may request a modification to an approved energy efficiency plan due to changes in the funding as a result of customers requesting exemptions from the electric energy efficiency plan.
	b. 	Natural gas and electric utilities may request modification of an approved energy efficiency plan, or electric utilities may request modification of an approved demand response plan, for any reason.
	c. 	The board, on its own motion, may consider modification of the energy efficiency or demand response plan and budget.
	35.10(2)  All applications to modify shall be filed in the same docket in which the energy efficiency or demand response plan was approved. All parties to the docket in which the energy efficiency or demand response plan was approved shall be served copies of the application to modify and shall have 14 days to file an objection or agreement. Objections should be specifically related to the contents of the modification. Failure to file timely objection shall be deemed agreement.
	35.10(3)  Each application to modify an approved energy efficiency or demand response plan shall include:
	a. 	A statement of the proposed modification and the party’s interest in the modification.
	b. 	An analysis supporting the requested modification.
	c. 	An estimated implementation schedule for the modification.
	d. 	A statement of the effect of the modification on attainment of the utility’s performance standards and on projected results, including cost-effectiveness, of the utility’s implementation of its plan.
	35.10(4) If the board finds that any reasonable grounds exist to investigate the proposed modification, a procedural schedule shall be set and the board shall take action within 90 days after the modification request is filed.
	35.10(5) If an application to modify is filed and the board finds that there is no reason to investigate, then the board shall issue an order within 90 days after the modification request is filed stating the reasons for the board’s decision relating to the application.
	35.10(6) If the board rejects or modifies a utility’s plan, the board may require the utility to file a modified plan and may specify the minimum acceptable contents of the modified plan.
199—35.11(476) Prudence review.
	35.11(1) The board shall periodically conduct a contested case proceeding to evaluate the reasonableness and prudence of the utility’s implementation of energy efficiency and demand response plans and budgets. The prudence review shall be based upon the information filed by a utility in the annual report required by rule 199—35.8(476), or based on discovery conducted in review of the annual reports.
	35.11(2) The consumer advocate or another person may request the board to conduct a prudence review based upon the information filed by a utility in the annual report required by rule 199—35.8(476), or based on discovery conducted in review of the annual reports. The request to initiate the prudence review shall identify specific issues to be evaluated and may include a proposed procedural schedule.
	35.11(3) The board shall determine whether a contested case proceeding is necessary to address the issues raised in a request for a prudence review.
	35.11(4) Disallowance of past costs. If the board finds the utility did not take all reasonable and prudent actions to cost-effectively implement its energy efficiency or demand response programs, the board shall determine the amount in excess of those costs that would have been incurred under reasonable and prudent implementation. That amount shall be deducted from the next EECR/DRCR factors calculated pursuant to subrule 35.9(3) until the disallowed costs have been satisfied.
199—35.12(476) New structure energy conservation standards. A utility providing natural gas or electric service shall not provide service to any structure completed after April 1, 1984, unless the owner or builder of the structure has certified to the utility that the building conforms to the energy conservation requirements adopted under 661—Chapter 303. If this compliance is already being certified to a state or local agency, a copy of that certification shall be provided to the utility. If no state or local agency is monitoring compliance with these energy conservation standards, the owner or builder shall certify that the structure complies with the standards by signing a form provided by the utility. No certification will be required for structures that are not governed by 661—Chapter 303.
These rules are intended to implement Iowa Code section 476.6.
[Filed 9/10/19, effective 11/13/19]
[Published 10/9/19]
Editor’s Note: For replacement pages for IAC, see IAC Supplement 10/9/19.