Electric Utility Renewable Energy Standard Requirements

PURPOSE: This rule sets the definitions, structure, operation, and procedures relevant to compliance with the Renewable Energy Standard. (1) Definitions. For the purpose of this rule— (A) Calendar year means a period of three hundred sixty-five (365) days (or three hundred sixty-six (366) days for leap years) that includes January 1 of the year and all subsequent days through and including December 31 of the same year; (B) Co-fire means simultaneously using multiple fuels in a single generating unit to produce electricity; (C) Commission means the Public Service Commission of the state of Missouri; (D) Customer-generator means the owner, lessee, or operator of an electric energy generation unit that meets all of the following criteria: 1. Is powered by a renewable energy resource; 2. Is located on premises that are owned, operated, leased, or otherwise controlled by the party as retail account holder and which corresponds to the service address for the retail account; 3. Is interconnected and operates in parallel phase and synchronization with an electric utility and has been approved for interconnection by said electric utility; and 4. Meets all applicable safety, performance, interconnection, and reliability standards of the net metering rule, 4 CSR 240-20.065(1)(C)6. and 4 CSR 240-20.065(1)(C)7. (E) Division means the Division of Energy, Department of Economic Development; (F) Electric utility means an electrical corporation as defined in section 386.020, RSMo; (G) General rate proceeding means a general rate proceeding before the commission where the commission considers all relevant factors that may affect the costs or rates and charges of the electric utility when setting rates; (H) Green pricing program means a voluntary program that provides an electric utility’s retail customers an opportunity to purchase renewable energy or renewable energy credits (RECs); (I) OPC means the Office of the Public Counsel; (J) Operational means all of the major components of the on-site solar photovoltaic system have been purchased and installed on the customer generator’s premises, and the production of rated net electrical generation has been measured by the utility. If a customer has satisfied all of the System AND INSURANCE Completion Requirements by June 30 of indicated years, but the electric utility is not able to complete all of the electric utility’s steps needed to establish an Operational Date on or before June 30, the rebate rate will be determined as though the Operational Date was June 30. If it is subsequently determined that the customer or the System did not satisfy all Completion Requirements required of the customer on or before June 30, the rebate rate will be determined based on the Operational Date; (K) PVWattsTM means the site specific data calculator that uses hourly typical meteorological year weather data and a photovoltaic performance model to estimate annual energy production and costs savings for a photovoltaic system; (L) Rate class means a customer class defined in an electric utility’s tariff. Generally, rate classes include Residential, Small General Service, Large General Service, and Large Power Service, but may include additional rate classes. Each rate class includes all customers served under all variations of the rate schedules available to that class; (M) REC, Renewable Energy Credit, or Renewable Energy Certificate means a tradable certificate, that is either certified by an entity approved as an acceptable authority by the commission or as validated through the commission’s approved REC tracking system or a generator’s attestation. RECs validated through an attestation must be signed by an authorized individual of the company that owns the renewable energy resource. Such attestation shall contain the name and address of the generator, the type of renewable energy resource technology, and the time and date of the generation. A REC represents that one (1) megawatt-hour of electricity has been generated from renewable energy resources. RECs include, but are not limited to, solar renewable energy credits. A REC expires three (3) years from the date the electricity associated with that REC was generated; (N) Renewable energy resource(s) means electric energy, produced from the following: 1. Wind; 2. Solar, including solar thermal sources utilized to generate electricity, photovoltaic cells, or photovoltaic panels; 3. Dedicated crops grown for energy production; 4. Cellulosic agricultural residues; 5. Plant residues; 6. Methane from landfills, from agricultural operations or wastewater treatment; 7. Thermal depolymerization or pyrolysis for converting waste material to energy; 8. Clean and untreated wood, such as pallets; 9. Hydropower (not including pumped storage) that does not require a new diversion or impoundment of water and that has generator nameplate ratings of ten (10) megawatts or less; 10. Fuel cells using hydrogen produced by any of the renewable energy technologies in paragraphs 1. through 9. of this subsection; and 11. Other sources of energy not including nuclear that become available after November 4, 2008, and are certified as renewable by rule by the division; (O) RES or Renewable Energy Standard means sections 393.1025 and 393.1030, RSMo; (P) RESRAM or Renewable Energy Standard Rate Adjustment Mechanism means a mechanism that allows periodic rate adjustments to recover prudently incurred RES compliance costs and pass-through to customers the benefits of any savings achieved in meeting the requirements of the Renewable Energy Standard; (Q) RES compliance costs means prudently incurred costs, both capital and expense, directly related to compliance with the Renewable Energy Standard. Prudently incurred costs do not include any increased costs resulting from negligent or wrongful acts or omissions by the electric utility; (R) RES portfolio requirements mean the numeric values and other requirements established by section 393.1030.1, RSMo, which are— 1. No less than two percent (2%) in each calendar year 2011 through 2013; 2. No less than five percent (5%) in each calendar year 2014 through 2017; 3. No less than ten percent (10%) in each calendar year 2018 through 2020; and 4. No less than fifteen percent (15%) in each calendar year beginning in 2021. 5. At least two percent (2%) of each RES portfolio requirement listed in this section shall be derived from solar energy. The RES portfolio requirements for solar energy are— A. No less than four-hundredths percent (0.04%) in each calendar year 2011 through 2013; B. No less than one-tenth percent (0.1%) in each calendar year 2014 through 2017; C. No less than two-tenths percent (0.2%) in each calendar year 2018 through 2020; and D. No less than three-tenths percent (0.3%) in each calendar year beginning in 2021; (S) The RES revenue requirement means the following: 1. All expensed RES compliance costs (other than taxes and depreciation associated with capital projects) that are included in the electric utility’s revenue requirement in the proceeding in which the RESRAM is established, continued, modified, or discontinued; and 2. The costs (i.e., the return, taxes, and depreciation) of any capital projects whose primary purpose is to permit the electric utility to comply with any RES requirement. The costs of such capital projects shall be those identified on the electric utility’s books and records as of the last day of the test year, as updated, utilized in the proceeding in which the RESRAM is established, continued, modified, or discontinued; (T) Solar renewable energy credit or S-REC means a REC created by generation of electric energy from solar thermal sources, photovoltaic cells, and photovoltaic panels; (U) Staff means all commission employees, except the secretary to the commission, general counsel, technical advisory staff as defined by section 386.135, RSMo, hearing officer, or administrative or regulatory law judge; (V) Standard Test Conditions means solar incidence of one (1) kilowatt (kW) per square meter and a cell or panel temperature of twenty-five degrees centigrade (25 °C) for measuring the capability of solar electrical generating equipment; (W) Total retail electric sales, or total retail electric energy usage, means the megawatt-hours (MWh) of electricity delivered in a specified time period by an electric utility to its Missouri retail customers as reflected in the retail customers’ monthly billing statements; and (X) Utility renewable energy resources mean those renewable energy resources that are owned, controlled, or purchased by the electric utility. (2) Requirements. Pursuant to the provisions of this rule and sections 393.1025 and 393.1030, RSMo, all electric utilities must generate or purchase RECs and S-RECs associated with electricity from renewable energy resources in sufficient quantity to meet the RES portfolio requirements (renewable and solar) on a calendar year basis. Utility renewable energy resources utilized for compliance with this rule must include the RECs or S-RECs associated with the generation. The RES portfolio requirements are based on total retail electric sales of the electric utility. The requirements set forth in this rule shall not preclude an electric utility from recovering all of its prudently incurred investment and costs incurred for renewable energy resources that exceed the requirements or limits of this rule but are consistent with the prudent implementation of any resource acquisition strategy the electric utility developed in compliance with 4 CSR 240-22, Electric Utility Resource Planning. RECs or S-RECs produced from these additional renewable energy resources may count toward the RES portfolio requirements. (A) Reserved* (B) The amount of renewable energy resources or RECs that can be counted towards meeting the RES portfolio requirements are as follows: 1. If the facility generating the renewable energy resource is located in Missouri, the allowed amount is the kilowatt-hours (kWhs) generated by the applicable generating facility, multiplied by one and twenty-five hundredths (1.25) to effectuate the credit pursuant to section 393.1030.1, RSMo and subsection (3)(G) of this rule; and 2. Reserved*; 3. RECs created by the operation of customer-generator facilities and acquired by the Missouri electric utility shall qualify for RES compliance if the customer-generator is a Missouri electric energy retail customer, regardless of the amount of energy the customer-generator provides to the associated retail electric provider through net metering in accordance with 4 CSR 240-20.065, Net Metering. RECs are created by the operation of the customer-generator facility, even if a significant amount or the total amount of electrical energy is consumed on-site at the location of the customer-generator. (C) If compliance with the RES portfolio requirements would cause the retail rates of an electric utility to increase on average in excess of one percent (1%) as calculated per section (5) of this rule, then compliance with those mandates shall be limited so that the cost of them would not cause retail rates of the electric utility to increase on average one percent (1%) as calculated per section (5) of this rule. (D) If an electric utility is not required to meet the RES portfolio requirements in a calendar year, because doing so would cause retail rates to increase on average in excess of one percent (1%) as calculated per section (5) of this rule, then the RES portfolio requirement for solar energy shall be no less than two percent (2%) of the renewable energy resources that can be acquired subject to the one percent (1%) average retail rates limit as calculated per section (5) of this rule. (E) If an electric utility intends to accept proposals for renewable energy resources to be owned by the electric utility or an affiliate of the electric utility, it shall comply with the necessary requirements of 4 CSR 240-20.015, Affiliate Transactions. (3) RECs and S-RECs. Subject to the requirements of section (2) of this rule, RECs and S-RECs shall be utilized to satisfy the RES requirements of this rule. S-RECs shall be utilized to comply with the RES portfolio requirements for solar energy and may be utilized to comply with the RES portfolio requirements for other renewable energy resources. (A) The REC or S-REC creation is linked to the associated renewable energy resource. For purposes of retaining RECs or S-RECs, the utility, person, or entity responsible for creation of the REC or S-REC must maintain verifiable records that prove the creation date. The electric utility shall comply with the requirement of this subsection through the registration of the REC in the commission’s approved REC tracking system. (B) A REC may only be used once to comply with this rule. RECs or S-RECs used to comply with this rule may not also be used to satisfy any other nonfederal renewable energy standard or requirement. Electric utilities may not use RECs or S-RECs retired under a green pricing program to comply with this rule. RECs and S-RECs may be used to comply with the RES portfolio requirements of this rule for a calendar year in which it expired so long as it was valid at any time in that year. (C) Customer-generators own the RECs and S-RECs associated with their customer-generated net-metered renewable energy resources; however, if a customer generator receives a solar rebate, the customer-generator transfers to the electric utility all right, title, and interest in and to the RECs associated with the new or expanded solar electric system that qualifies the customer-generator for the solar rebate for a period of ten (10) years from the date the electric utility confirms the customer-generator’s solar electric system is operational. 1. All standard offer contracts between electric utilities and the owners of net-metered renewable resources that are entered into after the effective date of these rules shall clearly specify who owns the RECs or S-RECs associated with the energy generated by the net-metered generation resource, and when the ownership will change, if it will. 2. Electric metering associated with net-metered renewable resources shall meet the meter accuracy and testing requirements of 4 CSR 240-10.030, Standards of Quality. (D) RECs that are generated with fuel cell energy using hydrogen derived from a renewable energy resource are eligible for compliance purposes only to the extent that the energy used to generate the hydrogen did not create RECs. (E) If an eligible renewable energy fuel source is co-fired with an ineligible fuel source, only the proportion of the electrical energy output associated with the eligible renewable energy fuel source shall be permitted to count toward compliance with the RES portfolio requirements. For co-fired generation of electricity, the renewable energy resources shall be determined by multiplying the electricity output by the direct proportion of the as-fired British thermal unit (BTU) content of the fuel burned that is a source of renewable energy resources as defined in this rule to the as-fired BTU content of the total fuel burned. (F) All electric utilities shall use a commission designated common central third-party registry for REC accounting for RES portfolio requirements, unless otherwise ordered for good cause shown. (G) RECs created by the generation of electricity by a renewable energy resource physically located in the state of Missouri shall count as one and twenty-five hundredths (1.25) RECs for purposes of compliance with this rule. This additional credit shall not be tracked in the tracking systems specified in subsection (F) of this section. This additional credit of twenty-five hundredths (0.25) shall be recognized when the electric utility files its annual compliance report in accordance with section (7) of this rule. (H) RECs created by the generation of electricity at a facility that subsequently fails to meet the requirements for renewable energy resources are valid if they were created before the date at which the facility is decertified. (I) Electric utilities required to comply with this rule may purchase or sell RECs, either bilaterally or in any open market system, inside or outside the state, without prior commission approval. (J) For compliance purposes, electric utilities shall retire RECs in sufficient quantities to meet the RES portfolio requirements AND INSURANCE of this rule. The RECs shall be retired during the calendar year for which compliance is sought. Electric utilities may retire RECs from January 1 through April 15 of the following year, following the calendar year for which compliance is being sought and designate those retired RECs as counting towards the requirements of that previous calendar year. Any RECs retired in this manner shall be specifically annotated in the registry designated in accordance with subsection (F) of this section and the annual compliance report filed in accordance with section (7) of this rule. RECs retired from January 1 through April 15 of the following year, to be counted towards compliance for the previous calendar year in accordance with this subsection shall not exceed ten percent (10%) of the total RECs necessary to be retired for compliance for that calendar year. (K) RECs may be aggregated with other RECs for compliance purposes. RECs shall be issued in whole increments. Any fractional RECs, aggregated or non-aggregated, remaining after certificate issuance will be carried forward to the next reporting period for the specific facility(ies). REC aggregation may be performed by electric utilities, customer-generators, or others. (L) Fractional RECs may be aggregated with other fractional RECs and utilized for compliance with this rule. (4) Solar Rebate. Pursuant to sections 393.1030 and 393.1670, RSMo, and this rule, electric utilities shall include in their tariffs a provision regarding retail account holder rebates for solar electric systems. These rebates shall be available to Missouri electric utility retail account holders who install new or expanded solar electric systems comprised of photovoltaic cells or photovoltaic panels. As used in this section, customer means retail account holder. (A) The retail account holder must be an active account on the electric utility’s system and in good payment standing. (B) The solar electric system must be permanently installed on the account holder’s premises. As installed, the solar electric system shall be situated in a location where a minimum of eighty-five percent (85%) of the solar resource is available to the system as verified by the customer or the customer’s installer at the time of installation. (C) The installed solar electric system must remain in place on the account holder’s (customer-generator’s) premises for ten (10) years unless determined otherwise by the commission. (D) Solar electric systems installed by retail account holders must consist of equipment that is commercially available and factory new when installed on the original account holder’s premises, and the principal system components (i.e., photovoltaic modules and inverters) shall be covered by a functional warranty from the manufacturer for a minimum period of ten (10) years, unless determined otherwise by the commission, with the exception of solar battery components. Rebuilt, used, or refurbished equipment is not eligible to receive the rebate. 1. Solar rebates made available prior to January 1, 2019, shall be limited to twenty-five (25) kW for any applicable retail account. Retail accounts which have been awarded rebates for an aggregate of less than twenty-five (25) kW shall qualify to apply for rebates for system expansions up to an aggregate of twenty-five (25) kW. Systems greater than twenty-five (25) kW but less than one hundred (100) kW in size shall be eligible for a solar rebate up to the twenty-five (25) kW limit of this section. 2. Solar rebates for systems that become operational after January 1, 2019 shall be available for new or expanded solar electric systems up to twenty-five (25) kW for residential customers and one hundred and fifty (150) kW for non-residential customers. Residential net-metered or interconnected solar electric systems greater than twenty-five (25) kW but less than one hundred (100) kW in size shall be eligible for a solar rebate up to the twenty-five (25) kW limit of this section. Customers shall be eligible for rebates on new or expanded systems for the increment of new or expanded capacity and not for capacity on which rebates offered under any other provision of law have previously been paid, up to the system kilowatt limits outlined in this section. (E) Solar electric systems which are less than 100 kW in size shall meet all requirements of 4 CSR 240-20.065, Net Metering, or all the requirements a customer-generator must meet under 4 CSR 240-20.100(1)(D). (F) The electric utility may physically audit customer-generator owned solar electric systems for which it has paid a solar rebate pursuant to this section, at any reasonable time, with prior notice of at least three (3) business days provided to the retail account holder. (G) For the purpose of determining the amount of solar rebate, the solar electric system wattage rating shall be established as the direct current wattage rating provided by the original manufacturer with respect to standard test conditions. (H) Standard Offer Contracts. 1. The electric utility may, at its discretion, offer a standard contract for the purchase of S-RECs created by the customer-generator’s installed solar electric system. 2. If the electric utility chooses to offer a standard offer contract, the electric utility shall file tariff sheets detailing the provision of the contract no later than November 1 each year for the following compliance year. Workpapers documenting the purchase prices shall be submitted with the tariff filing. (I) No customer-generator is required by this rule to sell any or all S-RECs to the electric utility; however, a condition of receiving a solar rebate from an electric utility is that all right, title, and interest in and to the RECs associated with the new or expanded solar electric system that qualifies the customer-generator for the solar rebate is transferred to the electric utility paying the rebate for a period of ten (10) years from the date the electric utility confirms the customer-generator’s solar electric system is operational. (J) Electric utilities that have acquired S-RECs under a one- (1-) time lump sum payment in accordance with subsection (H) of this section or as a result of the solar rebate S-RECs transferred through the solar rebate may continue to account for purchased S-RECs even if the owner of the solar electric system ceases to operate the system or the system is decertified as a renewable energy resource. S-RECs originated under this subsection shall only be utilized by the original purchasing utility for compliance with this rule. S-RECs originated under this subsection shall not be sold or traded. (K) Electric utilities that have purchased S-RECs under a one- (1-) time lump sum payment or otherwise have acquired right, title, and interest in and to S-RECs associated with solar rebates annually shall estimate, using PVWatts, or actually measure the S-RECs generated from the customer-generator’s operational solar electric system. (L) The electric utility shall provide the solar rebate payment to qualified customer-generators within thirty (30) days of confirming the customer-generator’s solar electric system is operational. (M) Any future payment of valid solar rebate applications, queued for payment prior to August 28, 2018, shall not count toward the annual or aggregate limits prescribed in section 393.1670(1), RSMo. (N) For electric utilities with less than two hundred thousand (200,000) Missouri retail customers— 1. Solar rebate payments made prior to January 1, 2019 shall be limited to twenty-five (25) kW for both residential and non-residential customers; and 2. In the event the limit has been reached, the electric utility shall continue to process and pay solar rebates until the electric utility meets or exceeds the retail rate impact limits of section (5) of this rule. However, these solar rebates shall be limited to twenty-five (25) kW for both residential and non-residential customers. (O) An electric utility may, through its tariff, require applications for solar rebates to be submitted up to one hundred eighty-two (182) days prior to the June 30 operational dates. The electric utility will pay the pre-June 30 rebate amount as defined in this subsection to customer-generators who comply with the submission and system operational requirements on or before June 30 of the following year. Customer-generators that fail to meet the submission or system operational requirements on or before the June 30 date will receive the post-June 30 rebate amount if the electric utility confirms their solar electric systems are operational within one (1) year of their application. If a customer has satisfied all of the System Completion Requirements by June 30 of indicated years, but the electric utility is not able to complete all of the electric utility’s steps needed to establish an Operational Date on or before June 30, the rebate rate will be determined as though the Operational Date was June 30. If it is subsequently determined that the customer or the System did not satisfy all Completion Requirements required of the customer on or before June 30, the rebate rate will be determined based on the Operational Date. (P) Unless the commission orders otherwise, if the electric utility meets or exceeds the retail rate impact limits of section (5) of this rule, the solar rebates shall be paid as determined by the solar system operational date. Any solar rebate applications that are not honored in a particular calendar year due to the requirements of this subsection shall be considered in the following calendar year. (Q) An electric utility shall maintain on its website, current information related to— 1. The electric utility’s solar rebate application and review processes, including standards for determining application eligibility; 2. The solar rebate amount associated with pending applications that have been submitted, but not yet reviewed; 3. The current level of solar rebate payments; and 4. The rebate amount associated with applications that are approved, but where the solar electric system is not yet operational. (5) Retail Rate Impact. (A) The retail rate impact (RRI), as calculated in subsection (5) (B), may not exceed one percent (1%) for prudent costs of renewable energy resources directly attributable to RES compliance. The retail rate impact shall be calculated annually on an incremental basis for each planning year based on procurement or development of renewable energy resources averaged over the succeeding ten- (10-) year period. The retail rate impact shall exclude renewable energy resources owned or under contract prior to September 30, 2010. (B) The RES retail rate impact shall be determined by subtracting the total retail revenue requirement incorporating an incremental non-renewable generation and purchased power portfolio from the total retail revenue requirement including an incremental RES-compliant generation and purchased power portfolio. 1. The non-renewable generation and purchased power portfolio shall be determined by adding, to the utility’s existing generation and purchased power resource portfolio excluding all renewable resources, additional non-renewable resources sufficient to meet the utility’s needs on a least-cost basis for the next ten (10) years. 2. The RES-compliant portfolio shall be determined by adding to the utility’s existing generation and purchased power resource portfolio an amount of least cost renewable resources sufficient to achieve the portfolio requirements set forth in section (2) of this rule and an amount of least-cost non-renewable resources, the combination of which is sufficient to meet the utility’s needs for the next ten (10) years. 3. The cost of the RES-compliant portfolio shall also include the positive or negative cumulative carry-forward amount as determined in subsection (5)(G). 4. Assumptions regarding projected renewable energy resource additions will utilize the most recent electric utility resource planning analysis. These comparisons will be conducted utilizing incremental revenue requirement for new renewable energy resources, less the avoided cost for non-renewable energy resources due to the addition of renewable energy resources. Such avoided costs shall be limited to those that may be included in a utility’s revenue requirement for setting rates In addition, the projected impact on revenue requirements by non-renewable energy resources shall include the expected value of greenhouse gas emissions compliance costs, assuming that such costs are made at the expected value of the cost per ton of greenhouse gas emissions allowances, cost per ton of a greenhouse gas emissions tax (e.g., a carbon tax), or the cost per ton of greenhouse gas emissions reductions for any greenhouse gas emission reduction technology that is applicable to the utility’s generation portfolio, whichever is lower. Calculations of the expected value of costs associated with greenhouse gas emissions shall be derived by applying the probability of the occurrence of future greenhouse gas regulations to expected level(s) of costs per ton associated with those regulations over the next ten (10) years. The impact on revenue requirements by non-renewable energy resources shall also include consideration of environmental risks other than those related to regulation or greenhouse gases. Any costs included to reflect consideration of such risks shall be limited to those that may be included in a utility’s revenue requirement for setting rates. Any variables utilized in the modeling shall be consistent with values established in prior rate proceedings, electric utility resource planning filings, or RES compliance plans, unless specific justification is provided for deviations. In no event shall the calculation of rate impact double count the cost of fuel or environmental compliance cost savings. (C) Solar rebates payments made during any calendar year in accordance with section (4) of this rule shall be included in the cost of generation from renewable energy resources. (D) For purposes of the determination in accordance with subsection (B) of this section, if the revenue requirement including the RES-compliant resource mix, averaged over the ten- (10-) year period, exceeds the revenue requirement that includes the non-renewable resource mix by more than one percent (1%), the utility shall adjust downward the proportion of renewable resources so that the average annual revenue requirement differential does not exceed one percent (1%). In making this adjustment, the solar requirement shall be in accordance with subsection (2)(D) of this rule. Prudently incurred costs to comply with the RES portfolio requirements, and passing this rate impact test, may be recovered in accordance with section (6) of this rule or through a rate proceeding outside or in a general rate case. When adjusting AND INSURANCE downward the proportion of renewable energy resources, in accordance with this subsection, the utility shall give first priority to reducing or eliminating the amount of RECs not associated with electricity delivered to Missouri customers. (E) Costs or benefits attributed to compliance with a federal renewable energy standard or portfolio requirement shall be considered as part of compliance with the Missouri RES if they would otherwise qualify under the Missouri RES without regard to the federal requirements. (F) If the electric utility determines the maximum average retail rate increase provided for in section (5) will be reached in any calendar year, the electric utility may cease paying rebates to the extent necessary to avoid exceeding the maximum average retail rate increase by filing a request with the commission, at least sixty (60) days in advance, to suspend the solar rebate provisions in its tariff for the remainder of the calendar year. 1. The filing with the commission to suspend the electric corporation’s solar rebate tariff provision shall include: A. Its calculation reflecting that the maximum average retail rate increase will be reached with supporting documentation; B. A proposed procedural schedule; and C. A description of the process that it will use to cease or conclude the solar rebate payments to solar customers if the commission suspends its solar rebate tariff provision. 2. The commission shall rule on the suspension filing within sixty (60) days of the date it is filed. If the commission determines the maximum average retail rate increase will be reached, the commission shall suspend solar rebate payments. The commission will not suspend payment of solar rebates unless it expressly finds that the electric utility has accurately calculated the retail rate impact in the manner prescribed by this section (5). 3. The electric utility shall continue to process and pay applicable solar rebates until a final commission ruling. A. If continuing to pay solar rebates causes the electric utility to exceed the maximum average retail rate increase, the excess payments shall not be considered to have been imprudently incurred for that reason. (G) The utility shall calculate for each actual compliance year an annual carry-forward amount, illustration included herein as Attachment A. This amount shall be calculated as the positive or negative difference between the actual costs of RES compliance and an amount equal to the one percent (1%) cap, as calculated in subsection (5)(B), for the non-renewable generation and purchased power portfolio from its most recent annual RES compliance plan filed pursuant to subsection (7) (B) of this rule. The positive or negative cumulative carry-forward amount shall be calculated by accumulating the annual positive or negative annual carry-forward amounts. The initial cumulative carry-forward amount shall be equal to the sum of the annual carry-forward amounts for the period January 1, 2015, through December 31, 2015. Any annual carry-forward amounts shall be based on the revenue requirements analysis included in the utility’s Annual RES Compliance Plan filed pursuant to subsection (8)(B) for each respective year. The positive or negative cumulative carry-forward amount shall be included in the cost of the RES-compliant portfolio for purposes of calculating the retail rate impact, as calculated in subsection (5)(B). Nothing in this subsection shall authorize recovery in excess of the one percent (1%) cap, as defined in subsection (5)(B). (H) If in reliance on a calculation of the RRI as provided for herein, an electric utility commits to fund a utility-owned renewable energy resource, or contracts to acquire energy or capacity from a renewable energy resource that, based on the relied-upon RRI calculation would not cause the electric utility to exceed such RRI, then the prudently incurred costs of such renewable energy resource and such energy and capacity shall constitute RES compliance costs even if including such costs in later calculations will cause the electric utility to exceed the RRI calculated at a later time. To the extent the prudently incurred costs of a utility-owned renewable energy resource, or contracted for energy or capacity from a renewable energy resource, cause an electric utility to exceed the RRI calculated at a later time, such excess sum shall be included in the determination of the carry-forward amount in accordance with subsection (5)(G). (I) Not withstanding anything in subsection (5)(H), until June 30, 2020, if the maximum average retail rate increase, as calculated pursuant to subsection (5)(B) would be less than or equal to one percent (1%) if an electric utility’s investment in solar-related projects initiated, owned, or operated by the electric utility is ignored for purposes of calculating the increase, then additional solar rebates shall be made available and included in rates in an amount up to the amount that would produce a retail rate increase equal to the difference between a one percent (1%) retail rate increase and the retail rate increase calculated when ignoring an electric utility’s investment in solar projects initiated, owned, or operated by the electric utility. (J) Each electric utility shall calculate its actual calendar year RRI each year and shall file those calculations as part of its annual RES compliance plan. The electric utility may designate all or part of those calculations as highly confidential, proprietary, or public as appropriate under the commission’s rules. (6) Cost Recovery and Pass-through of Benefits. An electric utility outside or in a general rate proceeding may file an application and rate schedules with the commission to establish, continue, modify, or discontinue a Renewable Energy Standard Rate Adjustment Mechanism (RESRAM) that shall allow for the adjustment of its rates and charges to provide for recovery of prudently incurred costs or pass-through of benefits received as a result of compliance with the RES; provided that the average annual impact on retail customer rates does not exceed one percent (1%) over a ten- (10-) year period as set out in subsections (5)(A), (B) and (G). In all RESRAM applications, the increase in electric utility revenue requirements shall be calculated as the amount of additional RES compliance costs incurred since the electric utility’s last RESRAM application or general rate proceeding, net of any reduction in RES compliance costs included in the electric utility’s prior RESRAM application or general rate case, and any new RES compliance benefits. (A) For all RESRAM filings, except the initial filings by the electric utility, if the actual increase in utility revenue requirement is less than two percent (2%), subsection (B) of this section shall be utilized. If the actual increase in utility revenue requirement is equal to or greater than two percent (2%), subsection (C) of this section shall be utilized. For the initial filing by the electric utility in accordance with this section, subsection (B) of this section shall be utilized as well, except that the staff, and individuals or entities granted intervention by the commission, may file a report or comments no later than one hundred twenty (120) days after the electric utility files its application and rate schedules to establish a RESRAM. 1. The pass-through of benefits has no single-year cap or limit. 2. Any party in a rate proceeding in which a RESRAM is in effect or proposed may seek to continue as is, modify, or oppose the RESRAM. The commission shall approve, modify, or reject such applications and rate schedules to establish a RESRAM only after providing the opportunity for an evidentiary hearing. 3. If the electric utility incurs costs in complying with the RES that exceed the one percent (1%) rate limit determined in accordance with section (5) of this rule for any year, those excess costs may be carried forward to future years for cost recovery permitted under this rule. Any costs carried forward shall have a carrying cost applied to them monthly equal to the interest on those carried forward costs calculated at the electric utility’s short-term borrowing rate. These carried forward costs plus accrued carrying costs plus additional annual costs remain subject to the one percent (1%) rate limit for any subsequent years. In any calendar year that costs from a previous compliance year are carried forward, the carried forward costs will be considered for cost recovery prior to any new costs for the current calendar year. 4. For ownership investments in eligible renewable energy technologies in a RESRAM application, the electric utility shall be entitled to a rate of return equal to the electric utility’s most recent authorized rate of return on rate base. Recovery of the rate of return for investment in renewable energy technologies in a RESRAM application is subject to the one percent (1%) limit specified in section (5) of this rule. 5. Upon the filing of proposed rate schedules with the commission seeking to recover costs or pass-through benefits of RES compliance, the commission will provide general notice of the filing. 6. The electric utility shall provide the following notices to its customers, with such notices to be approved by the commission in accordance with paragraph 7. of this subsection before the notices are sent to customers: A. An initial, one- (1-) time notice to all potentially affected customers, such notice being sent to customers no later than when customers will receive their first bill that includes a RESRAM, explaining the utility’s RES compliance and identifying the statutory authority under which it is implementing a RESRAM; B. An annual notice to affected customers each year that a RESRAM is in effect explaining the continuation of its RESRAM and RES compliance; and C. A RESRAM line item on all customer bills, which informs the customers of the presence and amount of the RESRAM charge. 7. Along with the electric utility’s filing of proposed rate schedules to establish a RESRAM, the utility shall file the following items with the commission for approval or rejection, and the OPC may, within ten (10) days of the utility’s filing of this information, submit comments regarding these notices to the commission: A. An example of the notice required by subparagraph (A)6.A. of this section; B. An example of the notice required by subparagraph (A)6.B. of this section; and C. An example customer bill showing how the RESRAM will be described on affected customers’ bills in accordance with subparagraph (A)6.C. of this section. 8. An electric utility may effectuate a change in its RESRAM no more often than one (1) time during any calendar year, not including changes as a result of paragraph 11. of this subsection. 9. Submission of Surveillance Monitoring Reports. Each electric utility with an approved RESRAM shall submit to staff, OPC, and parties approved by the commission, a Surveillance Monitoring Report. The form of the Surveillance Monitoring Report is included herein. A. The Surveillance Monitoring Report shall be submitted within fifteen (15) days of the electric utility’s next scheduled United States Securities and Exchange Commission (SEC) 10-Q or 10-K filing with the initial submission within fifteen (15) days of the electric utility’s next scheduled SEC 10-Q or 10-K filing following the effective date of the commission order establishing the RESRAM. B. If the electric utility also has an approved fuel rate adjustment mechanism or environmental cost recovery mechanism (ECRM), the electric utility shall submit a single Surveillance Monitoring Report for the RESRAM, ECRM, the fuel rate adjustment mechanism, or any combination of the three (3). The electric utility shall designate on the single Surveillance Monitoring Report whether the submission is for RESRAM, ECRM, fuel rate adjustment mechanism, or any combination of the three (3). C. Upon a finding that a utility has knowingly or recklessly provided materially false or inaccurate information to the commission regarding the surveillance data prescribed in this paragraph, after notice and an opportunity for a hearing, the commission may suspend its RESRAM or order other appropriate remedies as provided by law. 10. The RESRAM charge will be calculated as a percentage of the customer’s energy charge for the applicable billing period. 11. Commission approval of proposed rate schedules, to establish or modify a RESRAM, shall in no way be binding upon the commission in determining the ratemaking treatment to be applied to RES compliance costs during a subsequent general rate proceeding when the commission may undertake to review the prudence of such costs. If the commission disallows, during a subsequent general rate proceeding, recovery of RES compliance costs previously in a RESRAM, or pass-through of benefits previously in a RESRAM, the electric utility shall offset its RESRAM in the future as necessary to recognize and account for any such costs or benefits. The offset amount shall include a calculation of interest at the electric utility’s short-term borrowing rate as calculated in subparagraph (A)26.A. of this section. The RESRAM offset will be designed to reconcile such disallowed costs or benefits within the six- (6-) month period immediately subsequent to any commission order regarding such disallowance. 12. At the end of each twelve- (12-) month period that a RESRAM is in effect, the electric utility shall reconcile the differences between the revenues resulting from the RESRAM and the pretax revenues as found by the commission for that period and shall submit the reconciliation to the commission with its next sequential proposed rate schedules for RESRAM continuation or modification. 13. An electric utility that has implemented a RESRAM shall file revised RESRAM rate schedules to reset the RESRAM charge to zero (0) when new base rates and charges become effective following a commission report and order establishing customer rates in a general rate proceeding that incorporates RES compliance costs or benefits previously reflected in a RESRAM in the utility’s base rates. If an over- or under-recovery of RESRAM revenues or over- or under-pass-through of RESRAM benefits exists after the RESRAM charge has been reset to zero (0), that amount of over- or under-recovery, or over- or underpass-through, shall be tracked in an account and considered in the next RESRAM filing of the electric utility. 14. Upon the inclusion of RES compliance cost or benefit pass-through previously reflected in a RESRAM into an electric utility’s base rates, the electric utility shall immediately thereafter reconcile any previously unreconciled RESRAM revenues AND INSURANCE or RESRAM benefits and track them as necessary to ensure that revenues or pass-through benefits resulting from the RESRAM match, as closely as possible, the appropriate pretax revenues or pass-through benefits as found by the commission for that period. 15. In addition to the information required by subsection (B) or (C) of this section, the electric utility shall also provide the following information when it files proposed rate schedules with the commission seeking to establish, modify, or reconcile a RESRAM: A. A description of all information posted on the utility’s website regarding the RESRAM; and B. A description of all instructions provided to personnel at the utility’s call center regarding how those personnel should respond to calls pertaining to the RESRAM. 16. RES compliance costs shall only be recovered through a RESRAM or as part of a general rate proceeding and shall not be considered for cost recovery through an environmental cost recovery mechanism, fuel adjustment clause, or interim energy charge. 17. Pre-existing adjustment mechanisms, tariffs, and regulatory plans. The provisions of this rule shall not affect— A. Any adjustment mechanism, rate schedule, tariff, incentive plan, or other ratemaking mechanism that was approved by the commission and in effect prior to September 30, 2010; and B. Any experimental regulatory plan that was approved by the commission and in effect prior to September 30, 2010; and C. The commission’s reports and orders in file numbers ET-2014-0059, ET-2014-0071, and ET-2014-0085. 18. Each electric utility with a RESRAM shall submit, with an affidavit attesting to the veracity of the information, the following information on a monthly basis to the manager of the auditing unit of the commission and to OPC. The information shall be submitted to the manager of the auditing department through the electronic filing and information system (EFIS). The following information shall be aggregated by month and supplied no later than sixty (60) days after the end of each month when the RESRAM is in effect. The first submission shall be made within sixty (60) days after the end of the first complete month after the RESRAM goes into effect. It shall contain, at a minimum— A. The revenues billed pursuant to the RESRAM by rate class and voltage level, as applicable; B. The revenues billed through the electric utility’s base rate allowance by rate class and voltage level; C. All significant factors that have affected the level of RESRAM revenues along with workpapers documenting these significant factors; D. The difference, by rate class and voltage level, as applicable, between the total billed RESRAM revenues and the projected RESRAM revenues; E. Any additional information the commission orders be provided; and F. To the extent any of the requested information outlined above is provided in response to another section, the information only needs to be provided once. 19. Information required to be filed with the commission or submitted to the manager of the auditing unit of the commission and to OPC in this section shall also be, in the same format, served on or submitted to any party to the related rate proceeding in which the RESRAM was approved by the commission, periodic adjustment proceeding, prudence review, or general rate case to modify, continue, or discontinue the same RESRAM, pursuant to the procedures in 4 CSR 240-2.135 for handling confidential information, including any commission order issued thereunder. 20. A person or entity granted intervention in a rate proceeding in which a RESRAM is approved by the commission shall be a party to any subsequent related periodic adjustment proceeding or prudence review, without the necessity of applying to the commission for intervention; and the commission shall issue an order identifying them. In any subsequent general rate proceeding, such person or entity must seek and be granted status as an intervenor to be a party to that case. Affidavits, testimony, information, reports, and workpapers to be filed or submitted in connection with a subsequent related periodic adjustment proceeding, prudence review, or general rate case to modify, continue, or discontinue the same RESRAM shall be served on or submitted to all parties from the prior related rate proceeding and on all parties from any subsequent related periodic adjustment proceeding, prudence review, or general rate case to modify, continue, or discontinue the same RESRAM, concurrently with filing the same with the commission or submitting the same to the manager of the auditing unit of the commission and OPC, pursuant to the procedures in 4 CSR 240-2.135 for handling confidential information, including any commission order issued thereunder. 21. A person or entity not a party to the rate proceeding in which the commission approves a RESRAM may timely apply to the commission for intervention, pursuant to sections 4 CSR 240-2.075(2) through (4) of the commission’s rule on intervention, respecting any related subsequent periodic adjustment proceeding, or prudence review, or, pursuant to sections 4 CSR 240-2.075(1) through (5), respecting any subsequent general rate case to modify, continue, or discontinue the same RESRAM. If no party to a subsequent periodic adjustment proceeding or prudence review objects within ten (10) days of the filing of an application for intervention, the applicant shall be deemed as having been granted intervention without a specific commission order granting intervention, unless, within the above-referenced ten- (10-) day period, the commission denies the application for intervention on its own motion. If an objection to the application for intervention is filed on or before the end of the above-referenced ten- (10-) day period, the commission shall rule on the application and the objection within ten (10) days of the filing of the objection. 22. The results of discovery from a rate proceeding where the commission may approve, modify, reject, continue, or discontinue a RESRAM, or from any subsequent periodic adjustment proceeding or prudence review relating to the same RESRAM, may be used without a party resubmitting the same discovery requests (data requests, interrogatories, requests for production, requests for admission, or depositions) in the subsequent proceeding to parties that produced the discovery in the prior proceeding, subject to a ruling by the commission concerning any evidentiary objection made in the subsequent proceeding. 23. If a party which submitted data requests relating to a proposed RESRAM in the rate proceeding where the RESRAM was established or in any subsequent related periodic adjustment proceeding or prudence review wants the responding party to whom the prior data requests were submitted to supplement or update that responding party’s prior responses for possible use in a subsequent related periodic adjustment proceeding, prudence review, or general rate case to modify, continue, or discontinue the same RESRAM, the party which previously submitted the data requests shall submit an additional data request to the responding party to whom the data requests were previously submitted which clearly identifies the particular data requests to be supplemented or updated and the particular period to be covered by the updated response. A responding party to a request to supplement or update shall supplement or update a data request response from a related rate proceeding where a RESRAM was established, reviewed for prudence, modified, continued, or discontinued, if the responding party has learned or subsequently learns that the data request response is in some material respect incomplete or incorrect. 24. Each rate proceeding where commission establishment, continuation, modification, or discontinuation of a RESRAM is the sole issue shall comprise a separate case. The same procedures for handling confidential information shall apply, pursuant to 4 CSR 240-2.135, as in the immediately preceding RESRAM case for the particular electric utility, unless otherwise directed by the commission on its own motion or as requested by a party and directed by the commission. 25. In addressing certain discovery matters and the provision of certain information by electric utilities, this rule is not intended to restrict the discovery rights of any party. 26. Prudence reviews respecting a RESRAM. A prudence review of the costs subject to the RESRAM shall be conducted no less frequently than at intervals established in the rate proceeding in which the RESRAM is established. A. All amounts ordered refunded by the commission shall include interest at the electric utility’s short-term borrowing rate. The interest shall be calculated on a monthly basis for each month the RESRAM rate is in effect, equal to the weighted average interest rate paid by the electric utility on short-term debt for that calendar month. This rate shall then be applied to a simple average of the same month’s beginning and ending cumulative RESRAM over-collection or under-collection balance. Each month’s accumulated interest shall be included in the RESRAM over-collection or under-collection balances on an ongoing basis. B. The staff shall submit a recommendation regarding its examination and analysis to the commission not later than one hundred eighty (180) days after the staff initiates its prudence audit. The staff shall file notice within ten (10) days of starting its prudence audit. The commission shall issue an order not later than two hundred ten (210) days after the staff commences its prudence audit if no party to the proceeding in which the prudence audit is occurring files, within one hundred ninety (190) days of the staff’s commencement of its prudence audit, a request for a hearing. (I) If the staff, OPC, or other party auditing the RESRAM believes that insufficient information has been supplied to make a recommendation regarding the prudence of the electric utility’s RESRAM, it may utilize discovery to obtain the information it seeks. If the electric utility does not timely supply the information, the party asserting the failure to provide the required information shall timely file a motion to compel with the commission. While the commission is considering the motion to compel, the processing time line shall be suspended. If the commission then issues an order requiring the information to be provided, the time necessary for the information to be provided shall further extend the processing time line. For good cause shown the commission may further suspend this time line. (II) If the time line is extended due to an electric utility’s failure to timely provide sufficient responses to discovery and a refund is due to the customers, the electric utility shall refund all imprudently incurred costs plus interest at the electric utility’s short-term borrowing rate. The interest shall be calculated on a monthly basis in the same manner as described in subparagraph (A)26.A. of this section. (B) RESRAM filing requirements for less than two percent (2%) actual increase in utility revenue requirements. 1. When an electric utility files proposed rate schedules pursuant to sections 393.1020 and 393.1030, RSMo, and the provisions of this rule, the commission staff shall conduct an examination of the proposed RESRAM. 2. The staff of the commission shall examine and analyze the information submitted by the electric utility to determine if the proposed RESRAM is in accordance with provisions of this rule and the statutes governing the RES and shall submit a report regarding its examination to the commission not later than sixty (60) days after the electric utility files its proposed rate schedules. 3. The commission may hold a hearing on the proposed rate schedules and shall issue an order to become effective not later than one hundred twenty (120) days after the electric utility files the proposed rate schedules. 4. If the commission finds that the proposed rate schedules or substitute filed rate schedules comply with the applicable requirements, the commission shall enter an order authorizing the electric utility to utilize said RESRAM rate schedules with an appropriate effective date, as determined by the commission. 5. At the time an electric utility files proposed rate schedules with the commission seeking to establish, modify, or reconcile a RESRAM, it shall submit its supporting documentation regarding the calculation of the proposed RESRAM and shall serve the OPC with a copy of its proposed rate schedules and its supporting documentation. The utility’s supporting documentation shall include workpapers showing the calculation of the proposed RESRAM and shall include, at a minimum, the following information: A. A complete explanation of all of the costs, both capital and expense, incurred for RES compliance that the electric utility is proposing be included in rates and the specific account used for each item; B. The state, federal, and local income or excise tax rates used in calculating the proposed RESRAM, and an explanation of the source of and the basis for using those tax rates; C. The regulatory capital structure used in calculating the proposed RESRAM, and an explanation of the source of and the basis for using the capital structure; D. The cost rates for debt and preferred stock used in calculating the proposed RESRAM, and an explanation of the source of and the basis for using those rates; E. The cost of common equity used in calculating the proposed RESRAM, and an explanation of the source of and the basis for that equity cost; F. The depreciation rates used in calculating the proposed RESRAM, and an explanation of the source of and the basis for using those depreciation rates; G. The rate base used in calculating the proposed RESRAM, including an updated depreciation reserve total incorporating the impact of all RES plant investments previously reflected in general rate proceedings or RESRAM application proceedings initiated following enactment of the RES rules; H. The applicable customer class billing methodology used in calculating the proposed RESRAM, and an explanation of the source of and basis for using that methodology; I. An explanation of how the proposed RESRAM is allocated among affected customer classes, if applicable; and J. For purchase of electrical energy from eligible renewable energy resources bundled with the associated RECs or for AND INSURANCE the purchase of unbundled RECs, the cost of the purchases, and an explanation of the source of the energy or RECs and the basis for making that specific purchase, including an explanation of the request for proposal (RFP) process, or the reason(s) for not using a RFP process, used to establish which entity provided the energy or RECs associated with the RESRAM. (C) RESRAM for equal to or greater than two percent (2%) actual increase in utility revenue requirements. 1. If an electric utility files an application and rate schedules to establish, continue, modify, or discontinue a RESRAM outside of a general rate proceeding, the staff shall examine and analyze the information filed in accordance with this section and additional information obtained through discovery, if any, to determine if the proposed RESRAM is in accordance with provisions of this rule and the statutes governing the RES. The commission shall establish a procedural schedule providing for an evidentiary hearing and commission report and order regarding the electric utility’s filing. The staff shall submit a report regarding its examination and analysis to the commission not later than seventy-five (75) days after the electric utility files its application and rate schedules to establish a RESRAM. An individual or entity granted intervention by the commission may file comments not later than seventy-five (75) days after the electric utility files its application and rate schedules to establish a RESRAM. The electric utility shall have no less than fifteen (15) days from the filing of the staff’s report and any intervener’s comments to file a reply. The commission shall have no less than thirty (30) days from the filing of the electric utility’s reply to hold a hearing and issue a report and order approving the electric utility’s rate schedules subject to, or not subject to, conditions rejecting the electric utility’s rate schedules, or rejecting the electric utility’s rate schedules and authorizing the electric utility to file substitute rate schedules subject to, or not subject to, conditions. 2. When an electric utility files an application and rate schedules as described in this subsection, the electric utility shall file at the same time supporting direct testimony and the following supporting information as part of, or in addition to, its supporting direct testimony: A. Proposed RESRAM rate schedules; B. A general description of the design and intended operation of the proposed RESRAM; C. A complete description of how the proposed RESRAM is compatible with the requirement for prudence reviews; D. A complete explanation of all the costs that shall be considered for recovery under the proposed RESRAM and the specific account used for each cost item on the electric utility’s books and records; E. A complete explanation of all of the costs, both capital and expense, incurred for RES compliance that the electric utility is proposing be included in rates and the specific account used for each cost item on the electric utility’s books and records; F. A complete explanation of all of the costs, both capital and expense, incurred for RES compliance that the electric utility is proposing be included in base rates and the specific account used for each cost item on the electric utility’s books and records; G. A complete explanation of all the revenues that shall be considered in the determination of the amount eligible for recovery under the proposed RESRAM and the specific account where each such revenue item is recorded on the electric utility’s books and records; H. A complete explanation of any feature designed into the proposed RESRAM or any existing electric utility policy, procedure, or practice that can be relied upon to ensure that only prudent costs shall be eligible for recovery under the proposed RESRAM; I. For each of the major categories of costs, that the electric utility seeks to recover through its proposed RESRAM, a complete explanation of the specific rate class cost allocations and rate design used to calculate the proposed RES compliance revenue requirement and any subsequent RESRAM rate adjustments during the term of the proposed RESRAM; and J. Any additional information that may have been ordered by the commission in a prior rate proceeding to be provided. 3. When an electric utility files rate schedules as described in this subsection, and serves upon parties as provided in paragraph (A)20. of this section, the rate schedules must be accompanied by supporting direct testimony, and at least the following supporting information: A. The following information shall be included with the filing: (I) For the period from which historical costs are used to adjust the RESRAM rate: (a) REC costs differentiated by purchases, swaps, and loans; (b) Net revenues from REC sales, swaps, and loans; (c) Extraordinary costs not to be passed through, if any, due to such costs being an insured loss, or subject to reduction due to litigation, or for any other reason; (d) Base rate component of RES compliance costs and revenues; (e) Identification of capital projects placed in service that were not anticipated in the previous general rate proceeding; and (f) Any additional requirements ordered by the commission in the prior rate proceeding; (II) The levels of RES compliance capital costs and expenses in the base rate revenue requirement from the prior general rate proceeding; (III) The levels of RES compliance capital cost in the base rate revenue requirement from the prior general rate proceeding as adjusted for the proposed date of the periodic adjustment; (IV) The capital structure as determined in the prior rate proceeding; (V) The cost rates for the electric utility’s debt and preferred stock as determined in the prior rate proceeding; (VI) The electric utility’s cost of common equity as determined in the prior rate proceeding; (VII) The rate base used in calculating the proposed RESRAM, including an updated depreciation reserve total incorporating the impact of all RES plant investments previously reflected in general rate proceedings or RESRAM application proceedings initiated following enactment of the RES rules; and (VIII) Calculation of the proposed RESRAM collection rates; and B. Workpapers supporting all items in subparagraph (C)3.A. of this section shall be submitted to the manager of the auditing department and served upon parties as provided in paragraph (A)20. in this section. The workpapers may be submitted to the manager of the auditing department through EFIS. (D) Alternatively, an electric utility may recover RES compliance costs without use of the RESRAM procedure through rates established in a general rate proceeding. In the interim between general rate proceedings the electric utility may defer the costs in a regulatory asset account, and monthly calculate a carrying charge on the balance in that regulatory asset account equal to its short-term cost of borrowing. All questions pertaining to rate recovery of the RES compliance costs in a subsequent general rate proceeding will be reserved to that proceeding, including the prudence of the costs for which rate recovery is sought and the period of time over which any costs allowed rate recovery will be amortized. Any rate recovery granted to RES compliance costs under this alternative approach will be fully subject to the rate limit set forth in section (5) of this rule. (7) Nothing in sections (5) and (6) of this rule shall relieve the electric utility from reviewing its initial or ongoing decisions related to adding renewable resource additions or affect the commission’s ability to review the prudence of the electric utility’s renewable resource additions. (8) Annual RES Compliance Report and RES Compliance Plan. Each electric utility shall file a RES compliance report no later than April 15 to report on the status of both its compliance with the RES and its compliance plan as described in this section for the most recently completed calendar year. Each electric utility shall file an annual RES compliance plan with the commission. The plan shall be filed no later than April 15 of each year. (A) Annual RES Compliance Report. 1. The annual RES compliance report shall provide the following information for the most recently completed calendar year for the electric utility: A. Total retail electric sales for the utility, as defined by this rule; B. Total jurisdictional revenue from the total retail electric sales to Missouri customers as measured at the customers’ meters; C. Total retail electric sales supplied by renewable energy resources, as defined by section 393.1025(5), RSMo, including the source of the energy; D. The number of RECs and S-RECs created by electrical energy produced by renewable energy resources owned by the electric utility. For the electrical energy produced by these utility-owned renewable energy resources, the value of the energy created. For the RECs and S-RECs, a calculated REC or S-REC value for each source and each category of REC; E. The number of RECs acquired, sold, transferred, or retired by the utility during the calendar year; F. The source of all RECs acquired during the calendar year; G. The identification, by source and serial number, or some other identifier sufficient to establish the vintage and source of the REC, of any RECs that have been carried forward to a future calendar year; H. An explanation of how any gains or losses from sale or purchase of RECs for the calendar year have been accounted for in any rate adjustment mechanism that was in effect for the electric utility; I. For acquisition of electrical energy and/or RECs from a renewable energy resource that is not owned by the electric utility, except for systems owned by customer-generators, the following information for each resource that has a rated capacity of ten (10) kW or greater: (I) Facility name, location (city, state), and owner; (II) That the energy was derived from an eligible renewable energy technology and that the renewable attributes of the energy have not been used to meet the requirements of any other local or state mandate; (III) The renewable energy technology utilized at the facility; (IV) The dates and amounts of all payments from the electric utility to the owner of the facility; and (V) All meter readings used for calculation of the payments referenced in part (IV) of this paragraph; J. For acquisition of electrical energy and/or RECs from a customer generator— (I) Location (zip code); (II) Name of aggregated subaccount in which RECs are being tracked in; (III) Interconnection date; (IV) Annual estimated or measured generation; and (V) The start and end date of any estimated or measured RECs being acquired; K. The total number of customers that applied and received a solar rebate in accordance with section (4) of this rule; L. The total number of customers that were denied a solar rebate and the reason(s) for each denial; M. The amount expended by the electric utility for solar rebates, including the price and terms of future S-REC contracts associated with the facilities that qualified for the solar rebates; N. An affidavit documenting the electric utility’s compliance with the RES compliance plan as described in this section during the calendar year; O. If compliance was not achieved, an explanation why the electric utility failed to meet the RES; and P. A calculation of its actual calendar year retail rate impact. 2. On the same date that the electric utility files its annual RES compliance report, the utility shall post an electronic copy of its annual RES compliance report, excluding highly confidential or proprietary material, on its website to facilitate public access and review. 3. On the same date that the electric utility files its annual RES compliance report, the utility shall provide the commission with separate electronic copies of its annual RES compliance report including and excluding highly confidential and proprietary material. The commission shall place the redacted electronic copies of each electric utility’s annual RES compliance reports on the commission’s website in order to facilitate public viewing, as appropriate. (B) RES Compliance Plan. 1. The plan shall cover the current year and the immediately following two (2) calendar years. The RES compliance plan shall include, at a minimum— A. A specific description of the electric utility’s planned actions to comply with the RES; B. A list of executed contracts to purchase RECs (whether or not bundled with energy), including type of renewable energy resource, expected amount of energy to be delivered, and contract duration and terms; C. The projected total retail electric sales for each year; D. Any differences, as a result of RES compliance, from the utility’s preferred resource plan as described in the most recent electric utility resource plan filed with the commission in accordance with 4 CSR 240-22, Electric Utility Resource Planning; E. A detailed analysis providing information necessary to verify that the RES compliance plan is the least cost, prudent methodology to achieve compliance with the RES; F. A calculation of the RES retail impact limit calculated in accordance with section (5) of this rule. The calculation should be accompanied by workpapers including all the relevant inputs used to calculate the retail impact limits for the AND INSURANCE planning interval which is included in the RES compliance plan. The electric utility may designate all or part of those calculations as highly confidential, proprietary, or public as appropriate under the commission’s rules; and G. Verification that the utility has met the requirements for not causing undue adverse air, water, or land use impacts pursuant to subsection 393.1030.4., RSMo, and the regulations of the division. (C) Upon receipt of the electric utility’s annual RES compliance report and RES compliance plan, the commission shall establish a docket for the purpose of receiving the report and plan. The commission shall issue a general notice of the filing. (D) The staff of the commission shall examine each electric utility’s annual RES compliance report and RES compliance plan and file a report of its review with the commission within forty-five (45) days of the filing of the annual RES compliance report and RES compliance plan with the commission. The staff’s report shall identify any deficiencies in the electric utility’s compliance with the RES. (E) OPC and any interested persons or entities may file comments based on their review of the electric utility’s annual RES compliance report and RES compliance plan within forty-five (45) days of the electric utility’s filing of its compliance report with the commission. (F) The commission may direct the electric utility to provide additional information or to address any concerns or deficiencies identified in the comments of staff or other interested persons or entities. (9) Penalties. An electric utility shall be subject to penalties of at least twice the average market value of RECs or S-RECs for the calendar year for failure to meet the targets of section 393.1030.1, RSMo, and section (2) of this rule. (A) Any allegation of a failure to comply with the RES shall be filed as a complaint under the statutes and regulations governing complaints. (B) An electric utility shall be excused if it proves to the commission that failure was due to events beyond its reasonable control that could not have been reasonably mitigated or to the extent that the maximum average retail rate impact increase, as determined in accordance with section (5) of this rule, would be exceeded. (C) Any penalty payments assessed by the courts shall be remitted to the division. These payments shall be utilized by the division for the following purposes: 1. Purchase RECs or S-RECs in sufficient quantity to offset the shortfall of the utility to meet the RES portfolio requirements; and 2. Payments in excess of those required in paragraph (C)1. of this section shall be utilized to provide funding for renewable energy and energy efficiency projects. These projects shall be selected by the division in consultation with the staff. (D) Upon determination by the commission that an electric utility has not complied with the RES, penalty amounts shall be calculated by determining the electric utility’s shortfall relative to the RES portfolio requirements (total and solar) for the calendar year. The penalty amount recommended by the commission to the court of jurisdiction shall be twice the average market value during the calendar year for RECs or S-RECs in sufficient quantity to make up the utility’s shortfall for RES total requirements or RES solar energy requirements. The average market value for RECs or S-RECs for the calendar year shall be based on RECs and S-RECs utilized for compliance with this rule. A recommended average market value for the compliance period shall be calculated by the staff. OPC and any interested persons or entities may file comments based on their review of the staff’s recommendation. The commission may issue an order which establishes a further procedural schedule, or the commission may determine the average market value as part of the complaint proceeding. (E) Any electric utility that is subject to penalties as prescribed by this section shall not seek recovery of the penalties through section (6) of this rule or any other rate-making activity. (10) Nothing in this rule shall preclude a complaint case from being filed, as provided by law, on the grounds that an electric utility is earning more than a fair return on equity, nor shall an electric utility be permitted to use the existence of its RESRAM as a defense to a complaint case based upon an allegation that it is earning more than a fair return on equity. (11) Variances. Upon written application, and after notice and an opportunity for hearing, the commission may grant a variance from any provision of this rule for good cause shown. (A) The granting of a variance to one (1) electric utility which affects the required compliance with a provision of this rule does not constitute a variance respecting, or otherwise affect, the compliance required of any other electric utility. (B) The commission may not grant a variance from this rule in total. Electric Company 12 Months Ended ________________ Per Books (IN THOUSANDS OF DOLLARS) FINANCIAL SURVEILLANCE MONITORING REPORT RATE BASE AND RATE OF RETURN 12 Months Electric Ended Total Electric Rate Base Measurement Basis Plant in Service Intangible End of Period $ xxx,xxx Production - Steam End of Period xxx,xxx Production - Nuclear End of Period xxx,xxx Production - Hydraulic End of Period xxx,xxx Production - Other End of Period xxx,xxx Transmission End of Period xxx,xxx Distribution End of Period xxx,xxx General End of Period xxx,xxx Total Plant in Service $ x,xxx,xxx Reserve for Depreciation Intangible End of Period xxx,xxx Production - Steam End of Period xxx,xxx Production - Nuclear End of Period xxx,xxx Production - Hydraulic End of Period xxx,xxx Production - Other End of Period xxx,xxx Transmission End of Period xxx,xxx Distribution End of Period xxx,xxx General End of Period xxx,xxx Total Reserve for Depreciation x,xxx,xxx Net Plant $ x,xxx,xxx Add: Materials & Supplies 13 Mo. Avg. x,xxx,xxx Cash {from prior rate case including offsets} x,xxx,xxx Fuel Inventory 13 Mo. Avg. x,xxx,xxx Prepayments 13 Mo. Avg. x,xxx,xxx Other Regulatory Assets End of Period x,xxx,xxx Less: Customer Advances 13 Mo. Avg. x,xxx,xxx Customer Deposits 13 Mo. Avg. x,xxx,xxx Accumulated Deferred Income Taxes End of Period x,xxx,xxx Other Regulatory Liabilities End of Period x,xxx,xxx Other Items from Prior Rate Case Per rate case method x,xxx,xxx (A) Total Rate Base $ x,xxx,xxx (B) Net Operating Income $ x,xxx,xxx (C) Return on Rate Base [ (B) / (A) ] AND INSURANCE Overall Cost of Capital Weighted Amount Percent Cost Cost Long-Term Debt $ xxx,xxx x.xx % x.xx % f x.xx % Short-Term Debt xxx,xxx x.xx % x.xx % f x.xx % Preferred Stock xxx,xxx x.xx % x.xx % f x.xx % Other d xxx,xxx x.xx % x.xx % f x.xx % Common Equity xxx,xxx x.xx % x.xx % a x.xx % Total Overall Cost of Capital based on Rate Case Rate of Return on Equity $ x,xxx,xxx 100.00% x.xx % Actual Earned Return on Equity Weighted Amount Percent Cost Cost Long-Term Debt $ xxx,xxx x.xx % x.xx % f x.xx % Short-Term Debt (1) xxx,xxx x.xx % x.xx % f x.xx % Preferred Stock xxx,xxx x.xx % x.xx % f x.xx % Other d xxx,xxx x.xx % x.xx % f x.xx % Common Equity xxx,xxx x.xx % x.xx % a x.xx % Total Overall Cost of Capital with Actual Return on Equity $ x,xxx,xxx 100.00% x.xx % b a From last general rate case, Report & Order. b From actual Return on Rate Base, Page 1 "Rate Base" c Calculated after actual Return on Rate Base, per footnote B, is determined. d Other capital structure components from last general rate case, Report & Order e Actual balance at end of period f Actual average cost at end of period Note Additional breakdown may be added per Report & Order authorizing a recovery clause under 4 CSR 240-20 12 Months Ended ________________ Per Books (IN THOUSANDS OF DOLLARS) FINANCIAL SURVEILLANCE MONITORING REPORT CAPITAL STRUCTURE AND RATE OF RETURN Electric Company Electric Company Quarter Ended and 12 Months Ended ________________ Per Books (IN THOUSANDS OF DOLLARS) FINANCIAL SURVEILLANCE MONITORING REPORT OPERATING INCOME STATEMENT QUARTER ENDED 12 MONTHS ENDED Total Electric Income Statement ACTUAL ACTUAL Operating Revenues Sales to Residential, Commercial, & Industrial Customers Residential $ x,xxx,xxx $ x,xxx,xxx Commercial x,xxx,xxx x,xxx,xxx Industrial x,xxx,xxx x,xxx,xxx Total of Sales to Residential, Commercial, & Industrial Customers $ x,xxx,xxx $ x,xxx,xxx Other Sales to Ultimate Consumers x,xxx,xxx x,xxx,xxx Sales for Resale x,xxx,xxx x,xxx,xxx Off-System Sales x,xxx,xxx x,xxx,xxx Other Operating Revenues x,xxx,xxx x,xxx,xxx Provision for Refunds x,xxx,xxx x,xxx,xxx Operating Revenues $ x,xxx,xxx $ x,xxx,xxx Operating & Maintenance Expenses Production Expenses Fuel Expense Native Load x,xxx,xxx x,xxx,xxx Off-System Sales x,xxx,xxx x,xxx,xxx Other Production-Operations x,xxx,xxx x,xxx,xxx Other Production-Maintenance x,xxx,xxx x,xxx,xxx Purchased Power-Energy Native Load x,xxx,xxx x,xxx,xxx Off-System Sales x,xxx,xxx x,xxx,xxx Purchased Power-Capacity x,xxx,xxx x,xxx,xxx Total Production Expenses x,xxx,xxx x,xxx,xxx Transmission Expenses x,xxx,xxx x,xxx,xxx Distribution Expenses x,xxx,xxx x,xxx,xxx Customer Accounts Expense x,xxx,xxx x,xxx,xxx Customer Serve. & Info. Expenses x,xxx,xxx x,xxx,xxx Sales Expenses x,xxx,xxx x,xxx,xxx Administrative & General Expenses x,xxx,xxx x,xxx,xxx Total Operating & Maintenance Expenses $ x,xxx,xxx $ x,xxx,xxx Depreciation & Amortization Expense Depreciation Expense x,xxx,xxx x,xxx,xxx Amortization Expense x,xxx,xxx x,xxx,xxx Decommissioning expense x,xxx,xxx x,xxx,xxx Other x,xxx,xxx x,xxx,xxx Total Depreciation & Amortization Expense x,xxx,xxx x,xxx,xxx Taxes Other than Income Taxes xxx,xxx xxx,xxx Operating Income Before Income Taxes $ x,xxx,xxx $ x,xxx,xxx Income Taxes xxx,xxx xxx,xxx Net Operating Income $ x,xxx,xxx $ x,xxx,xxx Actual Cooling Degree Days x,xxx x,xxx Normal Cooling Degree Days x,xxx x,xxx Actual Heating Degree Days x,xxx x,xxx Normal Heating Degree Days x,xxx x,xxx AND INSURANCE Electric Company 12 Months Ended ________________ FINANCIAL SURVEILLANCE MONITORING REPORT Missouri Jurisdictional Allocation Factors Description Allocation Factor Plant in Service Intangible Production - Steam Production - Nuclear Production - Hydraulic Production - Other Transmission Distribution General Reserve for Depreciation Intangible Production - Steam Production - Nuclear Production - Hydraulic Production - Other Transmission Distribution General Net Plant Materials & Supplies Cash Working Capital per rate case Fuel Inventory Prepayments Other Regulatory Assets Jurisdictional Specific Customer Advances Customer Deposits Accumulated Deferred Income Taxes Other Regulatory Liabilities Jurisdictional Specific Other Items from Prior Rate Case Operating Revenues Interchange Revenues Production Expenses Fuel Expense Native Load Off-System Sales Other Production-Operations Other Production-Maintenance Purchased Power-Energy Native Load Off-System Sales Purchased Power-Capacity Total Production Expenses Transmission Expenses Distribution Expenses Customer Accounts Expense Customer Serve. & Info. Expenses Sales Expenses Administrative & General Expenses Depreciation & Amortization Expense Depreciation Expense Amortization Expense Decommissioning expense Taxes Other than Income Taxes Income Taxes Other Items xxxx xxxx xxxx Note Additional breakdown may be added per Report & Order authorizing a recovery clause under 4 CSR 240-20 Electric Company Quarter Ended and 12 Months Ended ________________ Per Books FINANCIAL SURVEILLANCE MONITORING REPORT NOTES TO FINANCIAL SURVEILLANCE REPORT AND INSURANCE Illustration ‐ Attachment A Illustration ‐ Attachment A AND INSURANCE Illustration ‐ Attachment A Illustration ‐ Attachment A AND INSURANCE AUTHORITY: section 393.1030, RSMo Supp. 2018, and sections 386.040 and 386.250, RSMo 2016.* This rule originally filed as 4 CSR 240-20.100. Original rule filed Jan. 8, 2010, effective Sept. 30, 2010. Amended: Filed March 25, 2015, effective Nov. 30, 2015. Amended: Filed Feb. 27, 2019, effective Oct. 30, 2019. Moved to 20 CSR 4240-20.100, effective Aug. 28, 2019. *Original authority: 386.040, RSMo 1939; 386.250, RSMo 1939, amended 1963, 1967, 1977, 1980, 1987, 1988, 1991, 1993, 1995, 1996; and 393.1030, RSMo 2007, amended 2008, 2010, 2013, 2018. *Ruling by the Joint Committee on Administrative Rules. On July 1, 2010, the Joint Committee on Administrative Rules voted to disapprove subsection (2)(A) and paragraph (2)(B)2. of 4 CSR 240-20.100. Those portions contained provisions on geographic sourcing. The committee considered those portions which were disapproved to be held in abeyance and asked that they not be published. Public Service Commission action. On January 26, 2011, the Public Service Commission filed an order with the Administrative Rules Division of the Office of the Secretary of State withdrawing the geographic sourcing provisions found in subsection (2)(A) and paragraph (2)(B)2. of 4 CSR 240-20.100. This commission order renewed the request of the Public Service Commission submitted by letter with its final order of rulemaking on July 6, 2010, that subsection (2)(A) and paragraph (2)(B)2. not be published in the Code of State Regulations and that these portions of the rule not become effective. A copy of this order appeared in the April 1, 2011, issue of the Missouri Register (36 MoReg 1002–1007). Legislative action. On January 24, 2011, Senate Concurrent Resolution No. 1 regarding 4 CSR 240-20.100 was adopted by the Senate and was concurred in by the House of Representatives on February 1, 2011. On February 16, 2011, the governor sent a letter to the speaker of the Missouri House of Representatives and the president pro tem of the Missouri Senate serving as notice of his action on the resolution. This concurrent resolution upheld a ruling issued by the Joint Committee on Administrative Rules disapproving subsection (2)(A) and paragraph (2)(B)2. of 4 CSR 240-20.100. The concurrent resolution permanently disapproves and suspends the final order of rulemaking for the proposed amendment to the above stated subsection and paragraph. The concurrent resolution and the letter from the governor were published in the April 1, 2011, issue of the Missouri Register (36 MoReg 1008–1011).