Market Power Mitigation Regulation

(no amdt) ALBERTA REGULATION 43/2024 Alberta Utilities Commission Act Electric Utilities Act MARKET POWER MITIGATION REGULATION Table of Contents 1 Definitions 2 Monthly net revenue secondary offer price cap 3 Modelling the reference generating unit 4 Exemptions 5 Enforcement 6 Filing of ISO rules 7 Expiry Schedule Definitions 1 (1) In this Regulation, (a) “annualized unavoidable costs” means the annualized unavoidable costs associated with operating the reference generating unit, as determined under section 3(1); (b) “ICE NGX AB NIT DAY AHEAD” means the ICE NGX Canada Inc.’s ICE NGX AB-NIT Day Ahead Index; (c) “ISO” means the Independent System Operator created under the Electric Utilities Act ; (d) “monthly cumulative settlement interval net revenue” means the monthly cumulative settlement interval net revenue of the reference generating unit; (e) “MSA” means the Market Surveillance Administrator continued under Part 5 of the Alberta Utilities Commission Act ; (f) “offer price” means a price, expressed in dollars per megawatt hour, at which an electricity market participant offers electric energy from a generating unit into the power pool; (g) “reference generating unit” means a generating unit possessing the operating variables and values listed in the Schedule with a monthly cumulative settlement interval net revenue and annualized unavoidable costs. (2) In this Regulation, the following words and phrases have the meanings given to them by the Electric Utilities Act : (a) electric energy; (b) electricity; (c) electricity market participant; (d) energy storage resource; (e) generating unit; (f) ISO rules; (g) power pool; (h) settlement interval. Monthly net revenue secondary offer price cap 2 Upon notification from the ISO, an electricity market participant must (a) not submit offer prices that are greater than the offer price limit communicated by the ISO under section 3(6)(c), (b) restate all previously submitted offer prices, excluding those for the next 2 settlement intervals, to conform with the offer price limit, and (c) maintain all offer prices equal to or less than the offer price limit until the first settlement interval in the first day of the following month. Modelling the reference generating unit 3 (1) For each year, the ISO shall determine the value of the annualized unavoidable costs as the summation of the annualized capital investment costs and the annual fixed operating costs associated with operating the reference generating unit. (2) The annualized capital investment costs, expressed in dollars, is determined in accordance with the following formula: where ACIC is the annualized capital investment costs; NC G is the net capacity of the generating unit listed as item 3 in the Schedule; CC G is the capital cost of the generating unit listed as item 4 in the Schedule; R is the pretax weighted average cost of capital listed as item 5 in the Schedule; N is the generating unit useful life listed as item 11 in the Schedule. (3) The annual fixed operating costs, expressed in dollars, is determined in accordance with the following formula: AFOC = (NC G x FOM x 1000) where AFOC is the annual fixed operating costs; FOM is the fixed operating and maintenance costs of the generating unit listed as item 8 in the Schedule; NC G is the net capacity of the generating unit listed as item 3 in the Schedule. (4) After each settlement interval in a month, the ISO shall determine the monthly cumulative settlement interval net revenue of the reference generating unit, expressed in dollars, in accordance with the following formula: where MCSINR is the monthly cumulative settlement interval net revenue of the reference generating unit; i is each settlement interval within the current month; n is the number of settlement intervals that have occurred within the current month; PP i is the electricity market pool price posted publicly by the ISO for each settlement interval; L is the loss factor listed as item 13 in the Schedule; P C is the price per tonne of CO 2 e for the applicable month determined in accordance with the Technology Innovation and Emissions Reduction Regulation (AR 133/2019); EI NG is the emissions intensity of natural gas listed as item 16 in the Schedule; HR G is the combined cycle heat rate of the generating unit listed as item 10 in the Schedule; HPB E is the high‑performance benchmark for electricity for the applicable month determined in accordance with section 6(1) of the Technology Innovation and Emissions Reduction Regulation (AR 133/2019); P NG is the price of natural gas listed as item 15 in the Schedule; VOM is the variable operating and maintenance costs of the generating unit listed as item 9 in the Schedule; TC is the ISO trading charge for the applicable month as published by the ISO; T subject to subsection (5), is the tax rate listed as item 14 in the Schedule; NC G is the net capacity of the generating unit listed as item 3 in the Schedule; CF G is the capacity factor of the generating unit listed as item 12 in the Schedule; min i is the number of minutes in the settlement interval. (5) If the monthly cumulative settlement interval net revenue of the reference generating unit calculated in subsection (4) is negative, then the tax rate must be set to zero for the applicable settlement interval in determining the monthly cumulative settlement interval net revenue. (6) In any month when the value of the monthly cumulative settlement interval net revenue of the reference generating unit exceeds 1/6 of the annualized unavoidable costs of the reference generating unit, the ISO must (a) notify electricity market participants to align their offer prices in accordance with section 2, (b) determine, on a daily basis, an offer price limit equal to the greater of (i) $125 per megawatt hour, or (ii) an amount equal to 25 times the ICE NGX AB NIT DAY AHEAD natural gas price, and (c) communicate, on a daily basis, the offer price limit determined in clause (b) to electricity market participants. (7) Any dollar amounts listed in the Schedule are expressed in 2022 dollars and must be subsequently adjusted for inflation each year using the annual Canada Consumer Price Index for the previous year. (8) The ISO must publicly communicate the updated value of the monthly cumulative settlement interval net revenue at least once a day. Exemptions 4 Section 2 does not apply to (a) any price offers submitted by an electricity market participant that has offer control of less than 5% of the total maximum capability of generating units in Alberta, as determined by the MSA under section 5(3) and (4) of the Fair, Efficient and Open Competition Regulation (AR 159/2009), (b) any generating unit that produces electric energy from a renewable energy resource as defined in the Renewable Electricity Act , or (c) an energy storage resource that (i) is controlled by an electricity market participant that has offer control of less than 5% of the total maximum capability of generating units in Alberta, as determined by the MSA under section 5(3) and (4) of the Fair, Efficient and Open Competition Regulation (AR 159/2009), (ii) derives its electric energy input from a renewable energy resource, as defined in the Renewable Electricity Act , or (iii) derives its electric energy input from the power pool. Enforcement 5 The MSA is authorized and mandated to enforce any contraventions of this Regulation or any related ISO rules. Filing of ISO rules 6 (1) The ISO shall make or amend any ISO rules to facilitate the requirements and the objectives of this Regulation. (2) The ISO shall file the required ISO rules under subsection (1) so that they are in effect by July 1, 2024. Expiry 7 This Regulation expires on November 30, 2027. Schedule Reference Generating Unit Operating Variables and Values Item Variables Values 1 Generating unit technology H class combustion turbine; single shaft configuration 2 Generating unit type Combined cycle natural gas 3 Generating unit net capacity 418 megawatts 4 Capital cost of generating unit $1,552.63 per kilowatt 5 Pretax weighted average cost of capital 10.5% 6 Debt financing cost 7% 7 Debt to capitalization ratio 50% 8 Generating unit fixed operating and maintenance costs $20.20 per kilowatt year 9 Generating unit variable operating and maintenance costs $3.65 per megawatt hour 10 Generating unit combined cycle heat rate 6.79 gigajoules per megawatt hour 11 Generating unit useful life 30 years 12 Generating unit capacity factor (availability) 86% 13 Loss factor 3% 14 Tax rate 23% 15 Natural gas price ICE NGX AB NIT DAY AHEAD 16 Emissions intensity of natural gas 0.0561 tonnes CO 2 e per gigajoule