IRP 2 workshops - WordPress.com

IRP 2 workshops - WordPress.com

Building on the Findings of the Electricity Governance Initiative South Africa The Integrated Resource Plan 2 Durban 10 May 2010 Energy Research Centre IRP 2 is Critical Determines whether South Africa: has adequate electricity to meet demand extends access to electricity for the poor reduces its GHG emissions continues on an energy intensive economic path, or charts a new path to green growth Coordination Renewable Energy White Paper Integrated Energy Plan Climate Change Policy Industrial Policy Action Plan National Planning Commission IRP 2 process IRP 1 released by cabinet in December 2009 interim 5 year plan MYPD 2 decision made, but without clarity on long term plans Now proposing a 2 part consultation First on the assumptions that go into energy models (May) And second on the scenarios developed (late June) Working group on IRP 2 reports to the IMC on energy Maximize opportunities to have input ic c o n s ul t a ti MARCH o MAY 2010 n o n a Intergo s vernmes

ntal u consult ation m p on assumpti o tions n s t h r o u g h Proposed IRP 2 process M o MAY d- JUNE 2010 el in g o Stakeh f older s worksh c op to agree e n on assumpa ri tions o s b e gi n s JUNE JULY 2010 I ConsultR ation P 2 on t scenari o os b e

Integrated Resource Planning and Scheduling Andrew Marquard, Brett Cohen, Mavo Solomon, Bruno Merven Energy Systems Analysis and Planning Energy Research Centre Contents Global history of IRP South African history of IRP NIRP I NIRP II NIRP III *IRP 1 Dispatching/scheduling of units Integrated Energy Planning History of Electricity Planning US Electricity planning in the 1960s Strong and consistent electricity growth Easily matched by bulk supply Simple trending techniques addressed concerns on future requirements Changes in the 1970s Arab oil embargo with price volatilities Nuclear Plant 3 Mile Island Less growth, rampant inflation, implied less predictability in planning US Electricity Planning in the 1970s History cont. Energy

conservation prominence in the 1980s Balancing the need build plants with using less energy Evolved into demand side management Complexity of planning analysis LEAST COST PLANNING Integrated Resource Planning IRP versus Traditional Planning Integrated Traditional Resource Planning Planning Focus on utility-owned Diversity of resources -central utility plants, power power plants purchases, DSM, T&D improvements Planning among several departments, involving Planning spread within utility system planning department customers (and government?) IPPs and small producers could also be included All resources owned by the utility Diverse resource selection criteria - prices, revenue requirements, utility financial health, risk, fuel diversity, Resources selected to minimise electricity prices and environmental quality maintain system reliability

Source: Spalding-Fetcher IRP, a balancing act Reliable service, Economic efficiency, Balancing customer and investor interests Environmental protection, and Equity/energy access - balancing interests of the various consumers against interests of present and future generations. Local, regional, national Energy Supply in South Africa Aggressive industrial growth (1970s 1980s) Overshooting in the1990s Investment in bulk supply Post 1994 economic aspirations Asian economic crisis impact (1998) Surplus capacity (mothballing and slowing of Majuba Power Plant). Stalled proposed market reform (2000s) Early signs of declining surplus capacity (reserve margin) Documented work predicting power shortages by 20068 Eskom still monopoly South Africas history of IRP

NIRP 1 (2002) NIRP II (2003/4) NIRP III Not published IRP 1 Post 1994 economic aspirations Published and gazetted 31 Dec 2009 Controversial IRP 2 Currently underway NIRP I Uses the basic planning assumptions of Eskoms ISEP8 with a few changes: National electricity forecast (not just Eskoms share thereof) Costs and performance parameters of nonEskom generation Fuel cost changes to some of Eskoms existing generation Cost and performance parameters of new simple cycle gas turbines Uses revised cost and performance parameters for: PBMR Pumped Storage Plants Simunye (mothballed) plant

NIRP I conclusions and comments Strategies to diversify away from coal as primary fuel source produce best relative environmental performance but more expensive than the base plan. Not very diversified. Access to water will become more difficult in future. Legislative changes on emission limits, water allocation and an effluent levy will impact on costs of future options, cause delays and influence site preferences Lead times for EIAs impact on the IRP planning process Environmental costs, as input into the preferred strategy, need to be justified for localised conditions NIRP I recommendations Whereas the base plan is the least cost option, it is important to incorporate strategies for fuel and geographic diversity and multiple investment opportunities in the energy market. These strategies will produce better relative environmental performance and have greater potential for regional development. NIRP I base plan NIRP II Two-stage process Stage 1: like NIRP 1, developed base/reference plan Stage 2: explicit risk modelling to develop reserve margin capacity Reserve margin:

demand DSM RM = 1 NIRP II preferred plan + renewables Mothballed YR Cam (PF) Gr'tvlei (PF) Coal-Fired Kom (PF) PF (1) PF (2) PF (3) FBC Gas Green-field FBC OCGT Committed 2003 Pumped Storage PS (A) PS (C) Conc. Solar Panels (CSP) Committed 2004

380 2006 380 2007 570 188 2008 190 377 101 152 24% 152 21% 152 18% 152 17% 152 16% 152 565 202 16% 720 152 17% 720

152 17% 152 14% Decide Decide Decide Decide 720 20 2010 303 2011 303 Decide 240 Decide 300 240 2012 932 Decide 333 2013 13% 999 2014 932 2015

466 Reserve on moderate forecast Committed Decide Decide 2005 DSM Wind CEE IMEE Turbines IMLM REE RLM Committed Committed 2009 PS (B) Renewables 13% 999 15% 14% 2016 1284 14% 2017 1284 15% 2018 1284 15% 2019

13% 2020 1284 2021 1284 2022 1284 1284 3852 1284 TOTAL 1520 1130 909 3852 13% 466 999 14% 13% 2796 2640 1332 999 999 300 20 1370

NIRP II - capacity Installed Capacity (MW) 60,000 55,000 OCGT Pump Storage CCGT 50,000 45,000 Fifty year plant life assumed (except 25 yrs for demothballed plant) 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 00 03 06 09 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 Year Conventional approach to IRP Process Choosing supply options Resource availability Costs (capex, operational and fuel) Environmental concerns Demand analysis Stakeholder involvement

Scenario development Appliance costs and cost of efficiency improvements Cost of no-supply (cost of unserved energy) Integrated Resource Plan Scheduling of units Dispatching/scheduling of units To meet load requirements with the cheapest energy sources Chronological hourly consumption Random events impacting available units Scheduling Baseload plants inflexible thermal plants: Coal plants (as function of coal contract) Nuclear plant Mid-merit plants minimal flexibility Pumped storage Combined cycle gas turbine plants Scheduling of units ... cont. Scheduling ... cont. Peaking units maximum flexibility open cycle gas turbines (fully variable costs)

Spinning reserve (thermal units) standby reserve in the event of load increases or unit failures Integrated Resource vs Energy Planning IRP is relatively mature, with standardized analytical tools Integrated Energy Planning (IEP) in infancy Interlinking of all energy carries Analytical tools becoming more widely available n er g y P e u st bl a ic bl c is o h n August e s plannind ul g ( t regulatiD a ons P ti task E o c n h o ai n r) a Intergo Ds vernme o s ntal E u consult A ationb m on br p

ti assump e o tions vi n at s o m m c m o The it IRP 2 process m s This is what we know so far m to is fu si ll o c NERSA n o holds s n Eskom s public JP submitsul hearingM revised s in Jan or ta MYPD M 2010; g ti request o 25% a o (35% n d increas n e per to o el n in for developing IRP 2year a Proposed process d IRg dr o StakehP f eI

older 2 s R ss Consult in worksh P it c ation op to e 2 s e on agree ar t fu n scenari on ly o n a os 2 assump b di ri tions 0 o ne 1 g 0s What was in the original IRP 1? Originally A Multi Criteria Decision Framework Ran several scenarios: 1. Reference Case 2a. Domestic emissions 2b. Regional emissions 2c. Delayed Regional Emissions 2d. Carbon Tax 3a. IPP alternates 1 3b. IPP alternates 2 2. Lowest CO2 3. Policy Portfolio 4. Risk-adjusted emission portfolio 5. Policy-adjusted IRP Criteria for Assessment:

Risk factors Diversity Costs Technology What was in IRP 1? CSP Kudu MSBLP CCGT Mpanda Nkua Nuclear DoE OCGT FBC Small hydro Wind OCGT Moamba Mmamabula MTPPP2 PF Coal PS Risks 0 = No risk (white blocks) 1 = Low risk (green blocks) 2 = Moderate risk (orange blocks) 3 = High risk (red blocks) Confidence in cost assumptions 1 0 0 0 1

1 1 1 2 1 1 3 2 3 3 3 Confidence in technology 0 0 0 0 0 0 0 0 1 0 1 0 0 0 0

2 Confidence in timing 1 0 1 1 2 0 0 1 1 1 1 3 1 3 3 2 Confidence in reliability 0 1 2 0 0 0 3 2 0

0 0 0 0 1 1 Safety concerns 0 0 0 0 0 0 0 0 0 0 2 0 1 0 0 0 Resource concerns 0 2 0

2 0 3 0 0 1 3 0 0 3 2 2 2 2 3 3 3 3 4 4 4 5 5 5 6 7 8 9

10 TOTAL What made it into IRP 1 Gazetted IRP 2 assumptions Parameter Discount rate Demand Forecast Energy Intensity (Long) Energy Intensity (Short) Economic multipliers Rate of Exchange Inflation GDP Cost of energy not served Price Elasticity DSM EE DMP Conservation Gx Mix Parameter Cogeneration Nuclear Funding / Financing Owner NT DOE DTI DOE NPlanning NT NT NT DOE NT DOE DOE SO DOE/NERSA DOE DOE DOE NT Key Outcome Price cone Security of supply

Security of supply Security of supply Key Outcome Price cone Price cone Price cone Security of supply Price cone Security of supply Security of supply Security of supply Security of supply Price cone Price cone Carbon Price cone IRP 2 assumptions Parameter Gx Lifecycle Costs Reserve Margin Own Generation Imports Price cone Renewables Water IRP 2010 Approach & Methodology Overview IRP Consultation Plan Carbon & Climate Change Carbon taxes Distribution Base Scenarios Gx Location Owner DOE DOE DOE SAPP DOE DOE DWAF DOE DOE DEAT DEAT DOE DOE/NERSA DOE Key Outcome

Price cone Security of supply Price cone Security of supply Key Outcome Carbon Externality Governance Governance Carbon Carbon Externality Key Outcome Externality Electricity planning, policy, politics and democracy Traditional - technical and cost barriers also a necessity! Stakeholders Problems Preferences Goals Scenarios - Detailed technical elaborations of possible aspirations Policymaking The main goal of SNAPP and similar tools is to empower a wider group of stakeholders to elaborate policy goals for the electricity sector through scenario development Detailed technical studies / tenders / market mechanisms etc. Implementation: - Infrastructure development (plants, transmission, etc) Why SNAPP is different from traditional planning tools For scenario development and exploration although rigorous, it does not have many of the sophisticated features of professional planning frameworks (e.g. optimisation, accurate dispatch simulation) Simple and easy to use, even for people with few technical skills

Because SNAPP is a spreadsheet, it provides instantaneous feedback on changes to parameters in the system, is transparent, easily and infinitely adaptable results are replicable, and assumptions are visible Free you can start today Electricity Supply (generation) Planning Process 1. 2. 3. Analyze current/past demand (energy and power/load shape) Project demand (energy and power) over the study horizon Analyze existing supply system, costs, and technical parameters (e.g. availability, efficiency, FOR) and retirement schedule 4. Analyze future technology options, costs (incl. learning curves) and technical parameters 5. Analyze fuel costs, current and projected over study horizon 6. Design supply system over study horizon looking at costs, within constraints (reliability standards, resource potential) 7. Study and cost demand-side options, for comparison to new generation 8. Study alternative scenarios: e.g. policy targets and compare to ref 9. Do sensitivity studies on uncertain parameters 10. Compile findings 11. Present to Stakeholders and iterate steps 4,5, 7-9 2. Project demand (energy and power) over the study horizon: Elec Demand sheet Main menu Levelised Costs Investment Plan System Costs Emissions etc Instructions: choose an electricity demand growth forecast in cell C8. You can specify your own forecast in rows 43 to 45. You will still have to choose which forecast you want to use in cell C8. Specify whether to include Solar Water Heaters (which will The LTMS growth forecast is a baseline forecast (business as usual), whereas the Ind eff forecast is a scenario based on the implementation of an industrial energy efficiency programme Electricity demand, peak demand, import and export energy and capacity include SWH? include PV? N N 2005 2006 2007 2008

2009 2010 2011 2012 2013 2014 2015 Baseline demand projections downstream of distribution choose: 3.0% 1.0% 0.0% 3.0% 3.5% 2.7% 3.4% 4.5% 4.0% 193,180 0.750 29.42 198,889 200,878 200,878 206,905 214,146 219,928 227,406 237,639

247,065 0.750 0.750 0.750 0.750 0.750 0.750 0.750 0.750 0.750 30.29 30.59 30.59 31.51 32.61 33.49 34.63 36.19 37.62 200,878 30.59 0.750 200,878 30.59 0.750 206,905 31.51 0.750 214,146 32.61 0.750

219,928 33.49 0.750 227,406 34.63 0.750 237,639 36.19 0.750 247,065 37.62 0.750 National Electricity Demand Growth REF (LTMS) National Electricity Demand (Distribution) GWh National average load factor (before demand reduction) National Electricity peak Demand (Distribution) GW Demand reduction National electricity demand (distribution with reduction) GWh National peak demand (distribution with reduction) GW 193,180 29.42 0.750 198,889 30.29 0.750 Electricity demand Upstream of distribution GWh Electricity peak demand upstream of distribution GW 12.48% 220,720 33.6

227,244 34.6 229,516 35.0 229,516 35.0 236,402 36.0 244,676 37.3 251,282 38.3 259,826 39.6 271,518 41.3 282,287 43.0 3.80% 229,450 34.9 3.80% 236,232 36.0 3.80% 238,594 36.3 3.80% 238,594 36.3 3.80% 245,752 3.80% 254,353 3.80% 261,221 3.80% 270,102

3.80% 282,257 3.80% 293,452 10,624 1.5 10,624 10,624 10,624 10,624 10,624 10,624 10,624 10,624 10,624 14,126 14,126 14,126 14,126 14,126 14,126 14,126 14,126 14,126 14,126 243,576 250,358 37.47 252,720 37.81

252,720 37.81 259,878 38.88 268,479 40.17 275,347 41.20 284,228 42.52 296,383 44.34 307,578 46.02 76.3% 76.3% 76.3% 76.3% 76.3% 76.3% 76.3% 76.3% 76.3% 36.513 4.9% 2.8% 36.139 -1.0% 0.9% 35.91 -0.6% 0.0% 37.698 5.0% 2.8%

39.015 3.5% 3.3% 40.062 2.7% 2.6% 41.441 3.4% 3.2% 43.294 4.5% 4.3% National average load factor (with demand reduction) Upstream of distribution National Average Distribution Losses 12.48% 12.48% 12.48% 12.48% 12.48% 12.48% 12.48% 12.48% 12.48% Upstream of transmission National Average Transmission Losses Electricity demand Upstream of Transmission excl. exports, PS input GWh 229,450 Electricity peak demand upstream of transmission excl. exports, PS inputGW Imports Imported electricity GWh Import capacity

GW 10,624 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 Exports Exported electricity GWh 14,126 Peak Demand on generation system Energy dispatched upstream of transmission (excl. PS input) Peak Demand on national system incl exports Load Factor (demand) Eskom forecast of peak on their system Eskom forecast of peak demand growth Peak demand growth Check GWh 35.10 36.44 76.3% 33.461 34.807 4.0% 3.8% 4. Analyze future technology options, costs (incl. learning curves) and technical parameters: Tech Parameters sheet Main menu

Levelised Costs Investment Plan System Costs Emissions etc Instructions: change setting in column B to Y or N to show the levellised cost of specific technologies To look at a breakdown of levellised costs for a specific technology, choose the technology in cell M2 Show ? (Y/N) 200 150 100 50 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 N N Existing coal Small N OCGT liquid fuels Y PWR nuclear N Hydro N Landfill gas N

Biomass Y Supercritical coal Y Wind 30% Y Wind 25% solar thermal central reciever Y Y solar thermal trough N solar PV Y combined cycle gas N PBMR Y IGCC N N N N Pumped storage Existing coal Large cents/kWh Technology Existing coal Large OCGT liquid fuels Hydro Biomass Wind 30% tax carbon financesolar thermal central reciever solar PV Existing coal Small PWR nuclear Landfill gas Supercritic al coal Wind 25% solar thermal trough combined cycle gas Levelised cost for in 7. Study alternative scenarios: e.g. policy targets and compare to ref: Cost graphs and Environmental Impacts sheets Ref Scen Comp

Reference electricity system costs and average electricity cost 200000 Scenario electricity system costs and average electricity cost 0.4 300000 0.6 250000 0.5 200000 0.4 0.35 0.2 0.15 50000 0.1 0.05 0 0 2005 2008 2011 2014 2017 2020 2023 2026 2029 Existing coal Large OCGT liquid fuels Hydro Biomass Wind 30% solar thermal central reciever solar PV PBMR carbon tax Average an elec cost with carbon tax Existing coal Small PWR nuclear Landfill gas Supercritical coal Wind 25% solar thermal trough combined cycle gas IGCC

Pumped storage Average electricity cost 150000 0.3 100000 0.2 50000 0.1 0 0 2005 2008 2011 2014 2017 2020 2023 2026 2029 Existing coal Large OCGT liquid fuels Hydro Biomass Wind 30% solar thermal central reciever solar PV PBMR carbon tax Average an elec cost with carbon tax Existing coal Small PWR nuclear Landfill gas Supercritical coal Wind 25% 500thermal trough solar combined cycle gas IGCC - 400 Pumped storage Average annual electricity cost (R/kWh) Reference electricity system greenhouse gases scenario electricity system greenhouse gases 400 350 300 Mt CO2-eq 100000 Mt CO2-eq

R million 0.25 R million 0.3 Rands / kWh 150000 300 200 250 200 150 100 100 50 0 Existing coal Large OCGT liquid fuels Hydro Biomass Wind 30% solar thermal central reciever solar PV PBMR - 0 Existing coal Small PWR nuclear Landfill gas Supercritic al coal Wind 25% solar thermal trough combined cycle gas IGCC Pumped storage Existin g coal Large OCGT liquid fuels Hydro Biomass Wind 30% solar thermal central reciever solar PV PBMR

- Existin g coal Small PWR nuclear Landfill gas Supercritical coal Wind 25% solar thermal trough combined cycle gas IGCC Pumped storage Moving Forward DoE to brief the Energy Caucus on the IRP 2 process Online resources to share information http://irp2.wordpress.com Second round of workshops when DoE releases its scenarios Independent research and information on the proposed assumptions Note: Leaked Sep 09 DRAFT IRP 1 available at http://www.mg.co.za/article/2010-01-08-eskoms-secret-tariff-plan-r evealed

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