ELECTRICITY AND OUR FUTURE INTEGRATED RESOURCE PLAN UPDATE Public - PowerPoint PPT Presentation

ELECTRICITY AND OUR FUTURE INTEGRATED RESOURCE PLAN UPDATE Public Utilities Committee Meeting December 11, 2019 1

Agenda • Mission • Why An IRP • TEA IRP Recommendations • Public Comments • Reliability, Financial & Environmental Considerations • Options & Next Steps • ScottMadden, Inc. 2

Core Mission • Affordable & Value Reliable Services • High Quality • Responsive to Service Customer Needs • Local Control Community • Local Operations “Small Enough to Care” 3

Why an IRP? • Load Decreasing – 16% decrease since 2006 • Units are not competitive – 31, 32, & 33 operating 30% less this year • Opportunity For Lower Cost Options – Natural Gas prices have lowered Electric Energy Prices significantly • Significant capital expenditures for environmental compliance & major maintenance 4

Recommendations 5

Unit Recommendations • Retire Dallman Units 31, 32 & 33 • Retain Unit 4 & Combustion Turbines • Next IRP in 3-5 years 6

Other Recommendations • Issue Renewable Request For Proposal (RFP) • Purchase Power Agreement (PPA) for Energy & Capacity • Expand Energy Efficiency Efforts 7

Public Comments IRP Results 8

Public Comments Resource Preferences • Follow TEA plan to close Dallman 31, 32 & 33 • Increase renewables • Reduce reliance on fossil fuels • Keep Dallman 33 as long as possible • Keep Unit 4 • Mix of generation resources is good 9

Public Comments Objective Preferences Clean Energy Risk of Coal Health Impact Job Creation Plants Coal Job Environmental Risk of Retention Impact Renewables Lowest Cost 10

Public Comments Reviewed by TEA • Consider Different Inputs  No viable inputs missed • Consider All Coal or All Renewables  Utilizing a diversified fuel mix is prudent industry practice and lowers risk • Gas Turbine Cost • Consider New Technologies • Consider New Fuel Prices 11

Public Comments Reviewed by TEA Jiangnan Environmental Technology Inc. (JET) Ammonia Desulfurization System  Success Dependent On Revenues From Fertilizer Sales  No Capital Cost Recovery for installation  Doesn’t avoid need for dry ash conversion  No Operating Projects in the United States  No Guarantee Can Meet Emissions Requirements 12

Reliability, Financial & Environmental Considerations 13

Current CWLP Generation DALLMAN 31 COAL 61 MW 1968 DALLMAN 32 COAL 61 MW 1972 DALLMAN 33 COAL 172 MW 1978 UNIT 4 COAL 207 MW 2009 REYNOLDS FUEL OIL 14 MW 1970 FACTORY FUEL OIL 17 MW 1973 INTERSTATE FUEL OIL & 110 MW 1997 NATURAL GAS 14

CWLP Load only over 350MW 0.5% of the year CWLP Combustion Market Load Turbines, OR Purchases 350 MW 141 MW CWLP Avg. Load = 195 MW Unit 4 207 MW Transmission upgrades will improve ability to import power thus increasing reliability 15

Financial Considerations Wholesale Revenues NET INCOME NET INCOME TOTAL SALES FROM ENERGY FROM CAPACITY INCOME SALES SALES FY19 $5,651,107 $2,800,350 $8,451,457 FY18 $7,807,930 $6,835,201 $14,643,131 • FY20 to October – Sales Revenues down $2M • Units are running 30% less than expected • Energy & Capacity Prices keep decreasing 16

Financial Considerations Dallman 31, 32 & 33 • Operating Costs + Low Market Prices = Dallman 31, 32, & 33 Not In the $$$  31/32 – Approx $10-12M /year loss vs Market*  33 – Approx $13-16M /year loss vs Market* • Lost Savings to CWLP and our customers • Some Costs Shift  As units retire, shared costs are redistributed to remaining units *Excludes additional capital costs for environmental compliance and major repairs. 17

Financial Considerations Dallman 31, 32 & 33 • Revenues highly dependent upon energy and capacity prices • In order to be viable:  Energy prices would have to double*  Capacity prices would have to triple* *Excludes additional capital costs for environmental compliance and major repairs. 18

Demolition Considerations • Lakeside Power Station (retired in 2009) has no current use and would be first priority. • Dallman complex not recommended for near-term demolition if units retire.  Offices and Inventory  Common Equipment for Unit 4  Land can not be used for economic development • Demolition costs  Sunk cost so separate from decommissioning costs  Achieved with savings from retiring plants  $7.5M-$10M to demo complex for Dallman 31, 32 and 33 19

Environmental Compliance At A Glance For Units Remaining in Operation February Dry Fly Ash Engineering 2022-2024 ACE Rule for Heat (ordinance) Future CO 2 Limits Rate Improvements April new FGD Waste Stream Complete construction of new CEJA (if adopted) would Treatment Engineering (ordinance) Lime Ponds . require all coal units 2021 2023 May 2020 deadline to certify shuttered by 2030. Exhaust bank of seasonal NO x retirement of Unit 31, 32 & 33 to allowances if all Units running, Complete closure of Ash obtain final closure extension for Ash Initiate purchase of additional Ponds to October 2028. Ponds by October 2028 if allowances. retirements option November 2020 must cease sending invoked in 2020 CCR alternatives analysis and water to Ash Ponds if no extension (to permitting expected under October 2023) granted State rules Summer 2023 complete construction September 2021 Dry Fly Ash of FGD treatment system for ELG system constructed and PSES rule as proposed operational for Units 31, 32 and 33 October 2023 (if extension granted) 2022 complete Dry Bottom Ash system, 2024 Begin construction of Filter WWTP sludge handling, FGD WWTP Press for WWTP, FGD WWTP filter press and leachate relocation. & Beyond 2020 sludge handling and landfill leachate collection Begin Closure of Ash Ponds if extension granted 316a, 316b and Biomonitoring studies once new NPDES permit issued

Environmental Compliance for Dallman 31, 32, & 33 • CCR and ELG Rules revised in November  Dry Fly Ash by September 2021  Dry Bottom Ash by October 2023  Ash Ponds will stop receiving water by 2023 If retirement dates are set by May 2020, then ash pond closure date is extended to 2028 • Illinois Senate Bill #9 – Ash Ponds • 316a and 316b (Intake and Discharge) with renewed NPDES permit. Cooling Tower may be required. • Clean Energy Jobs Act CEJA • Future CO 2 limits 21

Effluent Limitation Guideline (ELG) FGD (Scrubber) Blowdown • Rule revised in November • If 31, 32 or 33 are retained, ~ $45M new treatment facility by June 2023 • If only Unit 4 remains:  Closer to meeting water concentration limits  Possible can meet limits with new chemical and avoid building a smaller facility Upcoming slides do not include this project cost since rule just revised. 22

Options & Next Steps 23

Retain Unit 4 & Combustion Turbines -Cover Base Load • Unit 4  Most efficient and economical  Lowers Risk – Fuel Diversity • Combustion Turbines  Factory, Reynolds & Interstate  Cover Peak if needed  Adds Capacity at low cost 24

Retire Dallman 31 & 32 • Avoid $40M in Costs in next 5 years  Dry Ash Conversion  Boiler Repairs  Turbine Overhauls  Major Maintenance  Excludes $ for ELG FGD Blowdown • Avoid $10-12M/year loss vs Market • Decommissioning cost $700k – Lube Oil, Cleaning, and Building Heat • 25 positions eliminated, but 15 employees need transitioned 25

Retain Dallman 33 • Provides backup to Unit 4 but at higher cost • Incur $29M in Costs over next 5 years  Coal Ash Regulations  Boiler Repairs  Major Maintenance  Excludes $ for ELG FGD Blowdown • $13-16M/year loss vs Market • Retain Jobs • Start Dry Fly Ash Engineering • Start New ELG /FGD Blowdown Treatment Facility Engineering 26

Retire Dallman 33 • Avoid $ 29M in Costs in next 5 years  Dry Ash Conversion  Boiler Repairs  Major Maintenance  Excludes $ for ELG FGD Blowdown • Avoid $13-16M/year loss vs Market • Decommissioning cost $2M  Transmission Upgrades, Lube Oil, Cleaning • 50 employees currently in positions that would be transitioned 27

Employee Transition Options Minimize Impacts to Employees • Working with HR, Legal, and Unions • Job Restructuring • Training and/or transition to other open jobs • Options for severance • Options for retirements 28

Expand Energy & Capacity Purchases • Lowest Cost is the Market • Types of Purchases  Purchase Power Agreements  Bi-lateral Transactions  Real Time/Day Ahead • Develop Hedging Strategy  Covers difference vs our generation  Quantity of Power needed varies throughout the year 29

Natural Gas Forward Curve As of 11/13/19 Cal 20: $2.50 Cal 21: $2.47 Cal 22: $2.48 Cal 23: $2.53 Cal 24: $2.58 Cal 25: $2.62 Cal 26: $2.66 Cal 27: $2.75 Cal 28: $2.84 Cal 29: $2.94 Cal 30: $3.05 Cal 31: $3.16 The 2023-2031 strips hit new all- time lows earlier this week 30

Energy Services Office (ESO) Expand Customer Energy Efficiency Programs 1. Update 2008 Market Assessment Study of residential and commercial properties 2. Re-issue Customer Preference Survey (priorities, program needs, customer satisfaction) 3. Develop Program Options and Funding 31