Draft 2011 Long-term Transmission Plan. Stakeholder Session June 20, 2011

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1 Draft 2011 Long-term Transmission Plan Stakeholder Session June 20, 2011

2 Agenda Highlights of draft 2011 Long-term Transmission Plan Discussion of project costs and rate impact Impact of transmission constraints on the wholesale energy market Next steps in consultation Questions and answers 2

3 Transmission Drivers Reliable electric system supports continued provincial economic growth, ensures our quality of life, attracts investment Transmission in Alberta supports $5 billion wholesale electricity market which enables our $300 billion economy, which is expected to grow to $500 billion by 2020 Upgrades to the system needed to preserve system reliability, connect both load and generation customers, facilitate the fair, efficient and openly competitive operation of the market Development has not kept pace with growth in the last decade - as a result, system is running close to capacity with congestion on lines across the province Need to reduce transmission congestion and related congestion costs Demand has increased 32 per cent over the last 10 years and annual peak demand forecast to grow an average of 3.2 per cent per year over next 20 years - driven by oilsands development and related economic and population growth 13,000 MW of new generation needed over next 20 years to meet power needs of Albertans double current capacity Third party estimates show $188 billion in capital spending in Alberta in the next 24 months $109 billion in oilsands $18 billion in infrastructure $8 billion in commercial/retail $7.5 billion in pipelines $5 billion in mining 3

4 Highlights of draft 2011 Long-term Transmission Plan (LTP) Draft version filed with AUC June 2, 2011 Our updated blueprint for ensuring we continue to have a reliable and robust electricity system to meet the growing needs of the province 2011 LTP provides for an uncongested transmission system that will be available in advance of forecast need 2011 LTP is aligned with legislation, regulation and government policy; satisfies Alberta Reliability Standards Confirms need for transmission projects identified in the 2009 LTP Growth = Need LTP includes 53 projects, including four previously legislated CTI projects Identified several smaller regional projects All non CTI will continue to proceed through two stage (need and facility) AUC regulatory review No new CTI proposed No new interties identified or contemplated pre LTP includes plan to restore existing interties to their rated capacity Some of the projects previously identified have been cancelled and/or deferred beyond

5 Long-term Transmission Planning Process 5

6 Transmission Project Costs and Rate Impacts Shan Bhattacharya, Vice-President Transmission

7 Reconciliation of Costs from 2009 LTP $16,000 $14,000 $12,000 $1,927 $1,520 $10,000 $1,281 $1,216 $8,000 $6,000 $14,463 $10,951 $4,000 $2,000 $0 $1,473 $1,122 $13,545 7 $ millions 2009 LTP (2008$) Projects cancelled (2008$) Projects delayed beyond 2020 (2008$) Projects completed or near completion (2008$) Escalation 2008 to 2011 (2011$) Adjusted 2009LTP (2011$) New projects and scope changes (2011$) 2011 LTP (2011$) Scope Change New

8 Projects in Various Development Stages 10,000 9,000 8, % 7,000 $2011 million 6,000 5,000 4, % - 10% + 30% 3,000 2,000-30% + 50% 1,000 0 Facility Application Need Identification Document Planning Bars represent the range in the accuracy of the cost estimate 8

9 Basis of cost estimates 18 projects ($5,217M) Facility Application (+20/-10%) level cost estimates Adjusted to 2011$ - applied 4% annual escalation 4 projects ($3,017M) - NID (+/-30%) level cost estimates Adjusted to 2011$ - applied 4% annual escalation 31 projects ($5,311M) - in early planning stage with conceptual level (+/-50%) cost estimates 21 projects ($3,410M) - cost estimates provided by Teshmont Consulting in 2011$ and validated by AESO 5 projects ($1,401M) - cost estimates generated internally Used AESO available data to generate estimates 5 projects ($500M) represent a placeholder for customer distribution interconnections - cost estimates generated internally Used AESO available data to generate estimates 9

10 CTI and Regional Cost Estimates Region Estimated Cost ($2011 million) CTI Total $5,174 HVDC $2,951 Heartland $537 Fort McMurray $1,649 Calgary $37 South $3,473 Central $1,754 Edmonton $711 Northeast $1,588 Northwest $845 AIES Total $13,545 10

11 Northwest Region Developments Load 2010 Winter Peak 1,039 MW 2020 Forecast Winter Peak 1,450 MW Generation Current Installed 798 MW 2020 Forecast Installed 1,330-1,800 MW Inherent load growth Generation developments HR Milner expansion, Swan Hills synfuel, Hydro, gas-fired Planning Regions Central Edmonton Northeast Northwest South Estimated Capital Cost: $845 million ($2011) CTI not included in regional developments 11

12 Northeast Region Developments Load 2010 Winter Peak 2,349 MW 2020 Forecast Winter Peak 4,078 MW Generation Current Installed 3,001 MW 2020 Forecast Installed 4,865 MW Strong load growth Oilsands development, support industries for oilsands, population growth Generation developments Gas-fired cogeneration Planning Regions Central Edmonton Northeast Northwest South Estimated Capital Cost: $1,588 million ($2011) CTI not included in regional developments 12

13 Edmonton Region Developments Load 2010 Winter Peak 2,093 MW 2020 Forecast Winter Peak 2,780 MW Generation Current Installed 4,457 MW 2020 Forecast Installed 4,385 5,420 MW Load growth Economic growth, support industries for oilsands, population growth Generation developments Gas-fired Planning Regions Central Edmonton Northeast Northwest South Estimated Capital Cost: $711 million ($2011) CTI not included in regional developments 13

14 Central Region Developments Load 2010 Winter Peak 1,505 MW 2020 Forecast Winter Peak 2,251 MW Generation Current Installed 1,837 MW 2020 Forecast Installed 2,130-2,630 MW Load growth Pipeline development Generation developments Wind, Gas-fired Planning Regions Central Edmonton Northeast Northwest South Estimated Capital Cost: $1,754 million ($2011) CTI not included in regional developments 14

15 South Region Developments Load 2010 Winter Peak 2,971 MW 2020 Forecast Winter Peak 4,093 MW Generation Current Installed 2,919 MW 2020 Forecast Installed 4,955-6,000 MW Load growth Economic growth, population growth Generation developments Wind, gas-fired Planning Regions Central Edmonton Northeast Northwest South Estimated Capital Cost: $3,473 million ($2011) CTI not included in regional developments 15

16 Residential Rate Impact $120 $100 Average residential bill ($/month) $80 $60 $40 $9/month Transmission Distribution & Retail Energy $21/month $20 $ Year 16

17 Industrial Rate Impact $120 $100 Average industrial charge ($/MWh) $80 $60 $40 $16/MWh Transmission Energy $35/MWh $20 $ Year Rate impact estimate assumes all other costs remain unchanged 17

18 Summary of Project Costs Estimated 2011 project costs are in line with costs identified in 2009 LTP 53 projects listed in 2011 LTP Approximately 60% of the projects ($ weighted) at development stage $5.2 billion in Facility Application stage $3 billion in Needs Identification Document stage Approximately 40% of the projects ($ weighted) in planning stage (estimated cost $5.3 billion) Rate impact 1 due to Transmission Residential customer: Average bill increase $1 per month per year from $92 /month in 2011 to $103/month in 2020 Industrial customer: Average bill increase 2.2% per year from $79/MWh to $98/MWh 1 Rate impact estimate assumes all other costs remain unchanged 18

19 Impact of Transmission Constraints on the Wholesale Energy Market Matthew Davis Supervisor, Market Analytics

20 Transmission and Alberta s Market Design Hourly real-time energy only market Single clearing price regardless of location of delivery Significant locations of constraint requiring transmissionmust-run (TMR) for reliability Other constraints result in dispatching higher priced generation Result: Transmission constraints impact the wholesale market price 20

21 Impact on Price $1,000 $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 If the original dispatch was at 9,150 MW, then the impact would be $12.60/MWh Original price at 9,500 MW dispatch level: $73.35/MWh Increased price at 9,500 MW dispatch level (with 100 MW constraint applied): $494.70/MWh Difference = $421.35/MWh 8,000 8,100 8,200 8,300 8,400 8,500 8,600 8,700 8,800 8,900 9,000 9,100 9,200 9,300 9,400 9,500 9,600 9,700 9,800 9,900 10,000 10,100 10,200 MW Actual Merit Order Merit Order with a 100 MW Constraint 21

22 Current Levels of Constraints Currently the system is constrained on a regular basis and major projects also result in significant levels of constraints 30,000 25,000 20,000 15,000 10,000 5,000 0 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Regular Constraints (Ft. Mac & Wind) Regular Constraints (Ft. Mac) Regular Constraints (Other) Regular Constraints (Wind) 22 Total CDG (MWh)

23 Monte Carlo Simulation Approach Impact of constrained generation on price is dependant on the dispatch level at the time Monte Carlo simulation designed to evaluate across a variety of dispatch levels To determine increase in price: Randomly select a historical merit order Randomly select a dispatch level Determine original price Determine price if a constraint was there (higher price) Determine the difference Market value impacts were determined by the price distribution, historic constraints and 6,300 MW of AIES load 23

24 Results: Price Impact 24

25 Results: Price Impact 25

26 Results: Estimated Market Value of Constraints Similar to Historic Levels Impact on the wholesale price is significant Major constraint events impact the market the most, but regular constraint events such as for wind power can result in an impact of over $75 million per year Estimated Cost of Constrained Generation TMR Year Total Due to Major Constraint Events Due to Regular Constraints Volume (GWh) Volume Analyzed (GWh) Estimated Cost ($ million) Volume (GWh) Volume Analyzed (GWh) Estimated Cost ($ million) Volume (GWh) Volume Analyzed (GWh) Estimated Cost ($ million) Volume (GWh) Cost ($ million)

27 Next Steps in Industry Stakeholder Consultation on Draft 2011 Long-term Transmission Plan

28 Implementation Timeline June 2010 February 2011 March 2011 June 2, 2011 June 20, 2011 Generation baseline and scenarios published for stakeholder for comment Information paper updating generation baselines published for stakeholder comment Finalized baselines and draft regional Tx plans published for stakeholder comment Draft 2011 LTP filed for information with AUC Industry stakeholder session August 2, 2011 Deadline for stakeholder comments on draft 2011 LTP September 2011 Fall 2011 Respond to comments, revise 2011 LTP as necessary File final 2011 LTP with AUC 28

29 Questions?

30 For further information, comments, questions...