2008 Long-Term Acquisition Plan Intervenor Workshop #3 2008 LTAP Draft Application
June 3, 2008
AGENDA
Time
8:30 9:00 Registration Introduction Order Sought Break Analysis & Requests • • • • • • • • 12:15 12:45 Risk Framework & Modelling Intro Burrard DSM Acquisitions Site C Base Resource Plan Contingency Resource Plan Transmission Contingency Plan
Agenda Item
Lunch Analysis & Requests - continued Break Implementation • • • • • DSM Burrard Mica Unit 5/Mica Unit 6 Site C Acquisitions
Fort Nelson Resource Plan Next Steps/Regulatory Process
2
Introduction
Cam Matheson
Introduction / Overview
2008 LTAP Process
Update
Load Forecast
Update
Key Risks and Uncertainties
No Update
Step 1 Establish Objectives Step 2 - Load Resource Balance Step 4 – Develop & Evaluate Portfolios
Update (REVIEW TODAY)
Step 5 – Portfolio Trade-Off Analysis
Update (REVIEW TODAY)
Step 6 – LongTerm Acquisition Plan
Update
Update
Step 3 – Resource Options Inventory
Attributes
No Update
Limited Update
4
Application Overview
Chapter 1 – Introduction and Context 2 – Load and Resource Balance 3 – Resource Options 4 – Market Assessment Reviewed To Date Legislative and regulatory framework Load Forecast (energy & peak) Load Resource Balance Resource Options Intervenor Workshop Wkshp #1: Mar 5th Wkshp #2: Apr 25th Wkshp #2: Apr 25th
ROU Results Session: Dec 4th Wkshp #1: Mar 5th Wkshp #2: Apr 25th Wkshp #1: Mar 5th Wkshp #2: Apr 25th
GHG Offset Price Forecast Gas & Electricity Price Forecast Natural Gas Price Forecast Risk Framework Initial Portfolio Analysis
5 – Risk Framework and Portfolio Analysis 6 – Long-Term Acquisition Plan
Wkshp #2: Apr 25th Today Today
5
Orders Sought
BCUC determines that the 2008 LTAP is in the public interest Endorsement of:
the Clean Power Call pre-attrition target of 5,000 GWh/yr and that energy to be purchased pursuant to the Clean Power Call must qualify as “clean or renewable” BC Hydro relying on Burrard for planning purposes for 900 MW of dependable capacity and 3,000 GWh/yr of firm energy
Approves the submission of the 2008 LTAP CRPs for inclusion in BC Hydro’s NITS update BCUC determines that expenditures of $552.2 million are in the public interest
6
Order Sought (cont’d)
Activity DSM Plan for F09 to F11 Definition phase for capacity related DSM Sustaining Capital for Burrard Definition phase for Mica Units 5 & 6 Site C Stage 2 Definition and Consultation work Clean Power Call Definition and Implementation Fort Nelson Upgrade Requested Expenditures ($M) $418.0 $0.6 $1.6 $30.0 $41.0 $2.0 $59.0
7
Analysis & Requests: Risk Framework & Modelling Intro
Randy Reimann Basil Stumborg
Introduction
Goal of the 2008 LTAP
Identify best combination of supply-side and demand-side resources
• Subject to 2007 Energy Plan, related legislation, and special directions
Key Issues:
The future role of the Burrard Generating Station (BGS); Amount of Demand Side Management (DSM); Timing and nature of Calls for Energy; The value of maintaining Site C as an option. Contingency Plans (Resources and Transmission)
This portion of today:
Risk Framework Portfolio Modeling Overview Analysis, Conclusions and Requests for key issues
9
Risk Framework and Portfolio Analysis
LTAP Actions
•DSM Plan •Calls – Size and Type •Burrard – Future Role •Mica/Revelstoke • Site C • Contingency Resource Plans • Transmission Contingency Plans
Supported by Analysis
Risk Framework
• Process for comparing risks • Identify Key Risks • Scenarios
Portfolio Modeling
• Scenario Runs/Portfolios • PV Costs • Likelihood of resources being needed, their cost effectiveness • Ability to meet reliability requirements
Policy Requirements Resource Options
Uncertainties/Risks
10
Risk Framework
Four Key Elements:
Characterizing of uncertainty
• either stochastic modelling or subjective assessments;
Combining uncertainty measures with portfolio analysis; Qualitative Assessment; and Providing mitigation for risks that need to be managed.
11
Risk Framework - Definitions
Uncertainty
Unknown outcomes
Risk
Uncertain outcomes that can be adverse to BCH and its customers
Stochastic Modeling
Based on data from historic record Includes load growth, market prices,
Subjective assessment
When historic record can’t be relied upon
• Quantitative or qualitative
12
Risk Framework – Probability Assessments
Probability Tree
Combines probability assessments from stochastic modelling and from more subjective assessments Provides a range of scenarios of what the future might look like Used to frame comparisons for key issues
13
Gap Uncertainty
Uncertainty around The Gap
Uncertain load growth Uncertain DSM performance Uncertain performance of IPP EPA’s
Putting this together gives a range of Net Demand
For a fixed supply, gives a range of outcomes for The Gap
Table 5-1 Representing Uncertainty Regarding Net Demand Net Demand Scenarios Low Net Demand Relative Likelihood GWh (F2020) 20% 55,000 Mid Net Demand 60% 59,800 High Net Demand 20% 65,500
14
Uncertainty Regarding Thermal Costs
Thermal Cost Uncertainty
Uncertain Natural Gas Cost Forecasts Uncertainty Around GHG Offset Costs Putting these together gives a range of costs for thermal operations
Table 5-2 Cost of Thermal Operations (Three-point Distribution) Cost of Thermal Operations Scenarios Low (Low Gas, Low GHG) Relative Likelihood 1% Mid (Mid Gas, Mid GHG) 66% High (High Gas, High GHG) 33%
15
Uncertainty Regarding Thermal Costs – cont’d
Thermal Cost Uncertainty
Pulling apart GHG and Natural Gas prices gives a five point distribution Use where separating out these effects was important
Table 5-3 Cost of Thermal Operations (Five-point Distribution) Cost of Thermal Operations Scenarios Low Mid (Low Gas, (Mid Gas, Low Mid GHG) GHG) Relative Likelihood 1% 32% Mid Gas, High GHG 13% High High Gas, (High Mid GHG Gas, High GHG) 38% 16%
16
Base 11 Scenarios
Combining Net Demand (The Gap) with Cost of Thermal Generation Yields discrete scenarios Each scenario has a relative likelihood
Figure 5-1 Eleven Branch Probability Tree
17
Base 11 Scenarios – cont’d
How were these used?
For each scenario, resources used to fill the gap Resources used, costs and other impacts can be analyzed Policy options, resources constraints can then be tested Table 5-5 Portfolio Results associated with the Base 11 Scenarios
18
Base 9 Scenarios
A simplified tree was used when:
“cost of thermal” distinctions were not important Site C analyses, capacity projects on the Columbia
(Portion of) Table 5-31 Portfolios with Mica/Revelstoke Unit Selections identified
19
Base 5 Scenarios
Used when:
Focus was on just most likely (mid-gap) scenarios Used to manage modeling resources Used mostly for sensitivity analyses
• Incremental revenues from “green credits” (RPS sales), • exchange rates; and • discount rates.
20
Base Plan and Contingency Plans
Base Plan
Informed by probability tree, probability weighted costs Driven by more likely scenarios
Contingency Plans
Informed by judgment and probability tree’s less likely branches E.g. - Large gap scenario
21
Portfolio Analysis
Randy Reimann
Portfolio Analysis - Topics
Renewable Energy Credits Gas Modeling Burrard DSM Acquisitions Mica / Revelstoke Next Units Site C Base Resource Plan Contingency Resource Plans Transmission Contingency Plans
23
Renewable Energy Credits Modeled in LTAP
70
60
50
CDN $/MWh
40
30
20 BC Hydro Low Scenario BC Hydro Mid Scenario BC Hydro High Scenario Global Energy High Range Global Energy Low Range 2010 2012 2014 2016 2018 2020 2022 2024 2026
10
0
24
Natural Gas Generation
Burrard Allowed a range of dispatch, but plant generally does not run Reflects current role as a backup source to non-firm Heritage Hydro or market purchases New gas generation committed and operated to: Resource • SCGTs: • CCGTs: Firm Energy 18% 70% Minimum Operating 18% 70%
Reflects new unit construction commitments would be based on an expectation of operation Considers impact of divergent GHG offset policies and carbon taxes across neighbouring jurisdictions may not persist
25
Burrard
Burrard’s historical role
Including current operation and contribution to dependable capacity and firm energy;
AMEC technical studies
Undertaken on Burrard’s health Implications on BC Hydro’s ability to rely upon and operate the plant
RWDI environmental and social license study
Undertaken on BC Hydro’s ability to operate Burrard
Analysis of the impacts of maintaining Burrard
In current configuration with varying levels of energy contribution; and
Rebuilding Burrard
Technical, environmental and social considerations
26
Burrard
Figure 5-7 Burrard Actual Annual Generation
6000
5000
4000 GWh/yr
3000
2000
1000
0 1961 1966 1971 1976 1981 1986 1991 1996 2001 2006
27
Burrard
Figure 5-8 Burrard Capability Study Annual Generation over 60-year period of record
7000
6000
Annual Energy (GWh/yr)
5000
4000
3000
2000
1000
0 1940 1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 Water Year
28
Burrard – Current Configuration
Table 5-6 Annual OMA and Capital Funding for Alternative Burrard Operating Scenarios ($M/yr)
Period Average 2009-2015 Average 2016-2028 Average 20 yrs Levelized 20 yrs
Scenario 1 (900 MW/600 GWh)
Scenario 2 (900 MW/3000 GWh)
Scenario 3 (900 MW/6000 GWh)
Capital 26 6 13 16
OMA 15 13 14 14
Capital 31 7 16 19
OMA 18 15 16 17
Capital 35 7 17 22
OMA 20 16 18 18
29
Burrard
Figure 5-9 Effect of Incremental RPS sales on the PV of the Burrard Firm Energy Capability Analysis
13,000
12,500
Present Value ($M)
12,000
11,500
11,000
10,500
B2000 B3000 B4000 No RPS Low Mid High
10,000 RPS Price Scenario
30
Burrard
Figure 5-11
$1,400
Comparison of the Annual Cost of the Burrard Options by Capacity Factor (high gas forecast)
$1,200
$1,000
$/kW-yr
$800
$600
$400 CCGT Existing SCGT 0 10 20 30 40 50 60 70 80 90 100
$200
$0 Annual capacity factor (%)
31
Burrard Options
Demolish: Maintain 900 MW / 600 GWh: Maintain 900 MW / 3000 GWh Maintain 900 MW / 6000 GWh Rebuild SCGT Rebuild ½ CCGT or full CCGT Infeasible Feasible – Risk: Low Feasible – Risk: Low – Mod Feasible – Risk: High Feasible – Risk: Mod – High Infeasible
32
Burrard Conclusion
1. Reduce planned firm energy commitment to 3,000
GWh to reflect the actual firm energy contribution to the BC Hydro system, reduce social license risk and to meet the intent of SD 10; 2. Funding and implementing the refurbishment plan as proposed by AMEC for the 900 MW / 3000 GWh reliance on Burrard; and 3. Delaying any potential plans to rebuild the plant that may raise either social license or permitting issues until ILM Upgrade Project is in place;
33
DSM
DSM Option A:
By 2020, expected energy savings of 10,900 GWh per year with associated capacity savings of 1,900 MW, both including transmission and distribution loss savings;
DSM Option B:
By 2020, expected energy savings of 12,900 GWh per year with associated capacity savings of 2,200 MW both including transmission and distribution loss savings.
34
DSM
1. Impact of alternative DSM volumes on the
load/resource balance; 2. Economic analysis of the two DSM options; and 3. Deliverability risk of the DSM savings.
35
DSM Volume
Table 5-10 Remaining Gap with Mid Load/Resource Gap and DSM Options F2013 Mid Gap with DSM Option A Peak (MW) Energy (GWh/y) Mid Gap with DSM Option B Peak (MW) Energy (GWh/y) 527 927 546 502 588 187 209 56 388 -1,837 382 339 356 -352 358 -905 37 -1,315 115 -3,258 F2014 F2015 F2016 F2017
36
DSM Volume
Figure 5-12 Electricity Trade Volumes with DSM Option B and Low Load Growth
37
DSM Economic Analysis
Table 5-15 Relative Value of DSM Option A as compared to No DSM
C [A-B] PV Supply Side Savings ($M) 8,794 9,748 11,186 10,530 11,094 11,312 12,615 12,600 8,706 9,361 11,710 11,597 D A - No PV DSM Acquired (GWh) 108,339 108,339 108,339 93,342 93,342 93,342 93,342 93,342 74,848 74,848 74,848 92,992 E F [ A * 1000 / D ] [ C * 1000 / D ] PV Supply PV DSM Cost Side Savings ($/MWh) ($/MWh) 38 38 38 41 41 41 41 41 45 45 45 41 81 90 103 113 119 121 135 135 116 125 156 125
Gap
Cost of Thermal
Gas Low Mid High Low Mid Mid High High Low Mid High
GHG Low Mid High Low Mid High Mid High Low Mid High
A B A - No A - No DSM Total Net PV Cost of Resource Cost Scenario ($M) Likelihood ($M) 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3% 4,078 4,078 4,078 3,781 3,781 3,781 3,781 3,781 3,394 3,394 3,394 3,772 (4,716) (5,670) (7,108) (6,749) (7,313) (7,531) (8,834) (8,819) (5,312) (5,967) (8,316) (7,825)
Small
Mid
Large
Weighted Present Value
38
DSM Economic Analysis
Figure 5-12
High/High Large Mid/Mid Low/Low
Cost of DSM Option A versus Supply Side
High/High High/Mid Mid Small Mid/High Mid/Mid Low/Low
High/High Mid/Mid Low/Low $0 $50 $100 Levelized $/MWh
39
Supply Saving DSM Cost $150 $200
DSM Economic Analysis
Figure 5-13
High/High Large Mid/Mid Low/Low
Cost of Incremental Savings from DSM Option B and displaced Electricity Supply
High/High High/Mid Mid Small Mid/High Mid/Mid Low/Low
High/High Mid/Mid Low/Low $0 $50 $100 Levelized $/MWh Supply Saving DSM Cost $150 $200
40
DSM – Deliverability Risk
Includes consideration of: The expected variability of the resource; The degree of reliance upon the resource (e.g. how much of the gap is met by the resource); and The proven success of similar programs either here or in other jurisdictions.
41
DSM – Deliverability Risk
Table 5-17 Low, Mid, and High Ranges for DSM Energy Savings
Low Reduction From Mid Probability 20% Mid High Increase From Mid 20%
60% DSM Option A
GWh/y savings, 2020
(1,700)
10,200 DSM Option B
1,800
GWh/y savings, 2020
(2,100)
12,000
2,300
Application of the Risk Framework to DSM was a first-time effort that involved eliciting probability assessments regarding DSM tools that were new to BC Hydro DSM planning, such as codes and standards and conservation rate structures, and programs that involved higher levels of effort than previous years. As such, the Risk Framework has not have yet identified and captured all drivers of DSM performance risk and correlations between drivers
42
DSM - Conclusions
Based upon:
DSM’s low cost, The uncertainties and costs of supply side options, and
In consideration of:
The degree of reliance upon DSM programs;
BC Hydro concludes that DSM Option A should be the extent of the reliance on DSM savings at this point in time.
43
Acquisitions (Calls for Power)
Key considerations: 1. Size of the gap, including DSM and past acquisition process delivery risk; 2. Natural gas prices; 3. Possible future impacts of GHG legislation or carbon taxes; and 4. Costs of the available clean supply sources.
44
Acquisitions
Table 5-18 Mid Gap Load/Resource Gap with Existing and Committed Resources plus Scenario A DSM
Mid Gap Peak (MW) Energy (GWh/y)
F2013 382 339
F2014 356 -352
F2015 358 -905
F2016 37 -1,315
F2017 115 -3,258
45
Acquisitions
Table 5-21 Results of the 11 Base Scenarios showing amount of Thermal and Clean Resources
2012-2016 2012-2027
Base 11 Scenarios
Gap
Cost of Thermal Gas GHG Low Mid High Low Mid High Mid High Low Mid High Likelihood 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3%
Dependable Capacity Thermal Clean MW MW 479 479 479 577 577 137 137 188 188 319 277 418 418 575
Firm Energy Thermal Clean GWh GWh 2,939 2,939 2,939 3,094 3,094 1,226 1,226 1,637 1,637 3,940 3,664 5,386 5,386 8,456
Dependable Capacity Thermal Clean MW MW 236 1,430 951 951 1,675 1,528 715 100 202 237 189 369 366 742 742 690 725 953
Firm Energy Thermal Clean GWh GWh 1,448 8,775 5,836 5,836 9,384 8,929 4,387 801 2,106 2,387 1,749 4,935 5,237 11,303 11,303 9,446 10,079 14,937
Small
Low Mid High Low Mid Mid High High Low Mid High
Mid
Large
46
Acquisitions
Table 5-22
Base 11 Scenarios Gap Cost of Thermal Gas Small Low Mid High Low Mid Mid High High Low Mid High GHG Low Mid High Low Mid High Mid High Low Mid High Likelihood 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3% Present Value of Portfolios including Scenarios of RPS Sales Revenue None 7,809 7,124 6,583 11,577 11,529 11,758 11,777 11,859 17,692 17,669 18,490 11,857 Low 7,225 6,543 5,836 11,326 11,210 11,427 11,360 11,436 17,279 17,203 17,954 11,445 Mid 6,861 6,182 5,370 11,183 11,026 11,237 11,121 11,193 17,031 16,923 17,634 11,203 High 6,497 5,821 4,904 11,039 10,842 11,046 10,882 10,949 16,783 16,643 17,314 10,962
47
Present Value of Costs of the Base 11 Scenarios including RPS Sales
Mid
Large
Weighted Present Value
Acquisitions – Commitment Analysis
Table 5-23 Assumed Resources in Clean Call Block and Open Call Block
Dependable Capacity (MW) Scenario Thermal Clean Thermal Clean Capacity (MW) 319 667 Energy (GWh) 3940 4756 Firm Energy (GWh) Total
Clean Call Block Open Call Block
0 479
319 188
0 2939
3940 1637
48
Acquisitions
Table 5-24 Results of the Commitment Analysis for the Clean Call Block showing the amount of Thermal and Clean Resources
2012-2016 Dependable Capacity Firm Energy Thermal Clean Thermal Clean MW MW GWh GWh 958 715 319 319 319 319 319 319 319 319 319 319 595 5,878 4,387 3,940 3,940 3,940 3,940 3,940 3,940 3,940 3,940 3,940 3,940 8,473 2012-2027 Dependable Capacity Firm Energy Thermal Clean Thermal Clean MW MW GWh GWh 1,342 951 715 1,673 1,430 958 319 319 319 324 364 491 742 742 622 711 870 6,453 5,836 4,387 10,266 8,775 5,878 3,940 3,940 3,940 4,246 4,869 6,581 11,303 11,303 8,889 10,837 13,645
Clean Call Block Gap Cost of Thermal Gas Small Low Mid High Low Mid Mid High High Low Mid High GHG Low Mid High Low Mid High Mid High Low Mid High Likelihood 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3%
Mid
Large
49
Acquisitions
Table 5-25 Results of the Commitment Analysis for the Open Call Block showing the amount of Thermal and Clean Resources
2012-2016 Dependable Capacity Firm Energy Thermal Clean Thermal Clean MW MW GWh GWh 479 479 479 479 479 479 479 479 958 958 479 188 188 188 188 188 188 188 188 237 241 391 2,939 2,939 2,939 2,939 2,939 2,939 2,939 2,939 5,878 5,878 2,939 1,637 1,637 1,637 1,637 1,637 1,637 1,637 1,637 2,387 2,468 5,781 2012-2027 Dependable Capacity Firm Energy Thermal Clean Thermal Clean MW MW GWh GWh 479 479 479 1,243 951 1,194 479 479 1,909 1,673 753 188 188 188 266 369 268 562 562 480 622 953 2,939 2,939 2,939 7,627 5,836 7,327 2,939 2,939 11,714 10,266 4,448 1,637 1,637 1,637 3,072 4,935 3,440 8,209 8,209 7,667 8,889 14,937
Open Call Block Gap Cost of Thermal Gas Small Low Mid High Low Mid Mid High High Low Mid High GHG Low Mid High Low Mid High Mid High Low Mid High Likelihood 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3%
Mid
Large
50
Acquisitions
Table 5-29 Difference in PV of Costs including RPS Sales of Clean Call Block minus the Open Call Block
Present Value of Portfolios including Scenarios of RPS Sales Revenue Likelihood 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3% None 182 (14) (873) 354 210 114 (549) (659) 275 225 13 (204) Low 158 (39) (898) 336 179 49 (616) (705) 208 199 (62) (252) Mid 142 (55) (914) 327 162 12 (655) (731) 164 183 (106) (280) High 127 (71) (931) 318 145 (25) (693) (757) 120 168 (150) (307)
Clean Call Block - Open Call Block Gap Cost of Thermal Gas Low Mid High Low Mid Mid High High Low Mid High GHG Low Mid High Low Mid High Mid High Low Mid High
Small
Mid
Large
Weighted Present Value
51
Acquisitions
Table 5-30
Base 11 Scenarios Gap Cost of Thermal Gas Low Mid High Low Mid Mid High High Low Mid High GHG Low Mid High Low Mid High Mid High Low Mid High Likelihood 0.1% 6.6% 3.3% 0.5% 24.8% 10.7% 31.0% 13.0% 0.1% 6.6% 3.3% Minimum Clean or Renewable Percentage based on Generation in Portfolio (2012-2027) Base 93% in 2027 95% in 2024 95% in 2024 83% in 2026 87% in 2025 88% in 2026 95% in 2015 95% in 2015 84% in 2025 84% in 2025 91% in 2026 Clean Call Block 95% in 2015 95% in 2015 95% in 2015 87% in 2027 87% in 2026 90% in 2025 95% in 2015 95% in 2015 83% in 2024 84% in 2023 89% in 2026 Open Call Block 91% in 2024 91% in 2024 91% in 2024 85% in 2027 87% in 2025 86% in 2026 91% in 2017 91% in 2017 82% in 2026 83% in 2024 91% in 2026
Minimum Clean or Renewable Generation in Portfolios
Small
Mid
Large
52
Acquisitions - Conclusion
It is BC Hydro’s conclusion that given the gap uncertainties, that an acquisition of additional resources is warranted. Given the uncertainties surrounding GHG regulation and natural gas costs, that BC Hydro should avoid these risks, and target cost-effective clean or renewable resources.
53
Mica / Revelstoke
Table 5-31
Base 9 Portfolios Net Demand Small Cost of Thermal Generation Low Mid High Low Mid High Low Mid High Relative Likelihood 0.10% 6.60% 3.30% 0.80% 52.80% 26.40% 0.10% 6.60% 3.30% Thermal Renewables MW MW 243 100 0 477 0 484 1474 305 980 1181 0 2932 1730 2479 1577 2652 737 4205 Site C MW 0 0 0 0 0 0 0 0 0 MCA/REV MW 0 0 0 0 0 0 0 0 1000
Portfolios with Mica/Revelstoke Unit Selections identified
Start
Mid
Large
$ $ $ $ $ $ $ $ $
NPV 7,809 7,124 6,583 11,577 11,529 11,859 17,692 17,669 18,490
Site C as an option Small Low Mid High Low Mid High Low Mid High 0.10% 6.60% 3.30% 0.80% 52.80% 26.40% 0.10% 6.60% 3.30% $ $ $ $ $ $ $ $ $ 7,809 7,124 6,579 11,570 11,449 11,579 17,636 17,456 17,864 243 0 0 840 737 0 1577 1577 103 100 477 219 552 681 1842 1606 1709 4411 0 0 912 912 912 912 912 912 912 0 0 0 0 0 0 0 0 500
Start
Mid
Large
54
Site C
Table 5-32 Portfolio Comparison between Site C not an option and Site C as an Option ($150M Risk Reserve cases)
Net Demand Small Cost of Thermal Generation Low Mid High Low Mid High Low Mid High Low Mid High Low Mid High Low Mid High Relative Likelihood 0.10% 6.60% 3.30% 0.80% 52.80% 26.40% 0.10% 6.60% 3.30% 0.10% 6.60% 3.30% 0.80% 52.80% 26.40% 0.10% 6.60% 3.30% Thermal MW 243 0 0 1474 980 0 1730 1577 737 243 0 0 980 737 0 1680 1334 243 Clean MW 100 477 484 305 1181 2932 2479 2652 4205 100 477 219 219 661 1938 1541 2091 4232 Site C MW 0 0 0 0 0 0 0 0 0 N/A N/A 912 912 912 912 912 912 912 Site C year 2019 2024 2022 2019 2021 2021 2020 MCA/REV MW 0 0 0 0 0 0 0 0 1000 0 0 0 0 0 0 0 0 500
Site C Project
Not an option
Mid
Large
Small
An Option
Mid
Large
NPV $ 7,809 $ 7,124 $ 6,583 $11,577 $11,529 $11,859 $17,692 $17,669 $18,490 $ 7,809 $ 7,124 $ 6,555 $11,533 $11,387 $11,500 $17,562 $17,363 $17,841
55
Site C
Table 5-33 Portfolio Results with Site C as an Option for varying Risk Reserves
No Risk Reserve Gap Thermal Low Low Mid High Low Mid Mid High Low Large Mid High 2019 2023 2021 2019 2021 2021 2019 Year 6,544 11,484 11,318 11,399 17,480 17,285 17,743 PV 2026 2024 2023 2021 2023 2021 2020 $450M Risk Reserve Year 6,574 11,552 11,414 11,554 17,597 17,437 17,897 PV 2027 2023 2022 2025 2021 2021 $1,050M Risk Reserve Year 6,583 11,483 11,642 17,662 17,502 18,026
56
PV
Base Resource Plan
Figure 6-1
17,000 Effective Load Carrying Capability (MW)
Capacity Load / Resource Balance - Base
15,000
Operating Planning
13,000
11,000
9,000
F2 00 9 F2 01 0 F2 01 1 F2 01 2 F2 01 3 F2 01 4 F2 01 5 F2 01 6 F2 01 7 F2 01 8 F2 01 9 F2 02 0 F2 02 1 F2 02 2 F2 02 3 F2 02 4 F2 02 5 F2 02 6 F2 02 7 F2 02 8
Fiscal Year (year ending March 31) 2007 Load Forecast Range Clean Power Call Canadian Entitlement Mica Unit 6 2007 Mid Load Forecast after DSM with Reserves Existing and Committed Resources BioEnergy Call Future Resources 2007 Mid Load forecast Before DSM with Reserves
57
Base Resource Plan
Figure 6-2
Energy Load / Resource Balance - Base
85,000 Operating Planning Firm Energy Capability (GWh) 75,000
65,000
55,000
45,000
35,000
2007 Load Forecast Range BioEnergy Call Mica Unit 6
F2 00 9 F2 01 0 F2 01 1 F2 01 2 F2 01 3 F2 01 4 F2 01 5 F2 01 6 F2 01 7 F2 01 8 F2 01 9 F2 02 0 F2 02 1 F2 02 2 F2 02 3 F2 02 4 F2 02 5 F2 02 6 F2 02 7 F2 02 8
Fiscal Year (year ending March 31) Existing and Committed Resources Future Resources 2007 Load forecast Before DSM Clean Power Call Mica Unit 5 2007 High Load Forecast after DSM
58
Contingency Resource Plan
Table 6-13
Risk Potential High Gas Prices
BRP Actions to Manage Risks
Action Significant DSM program Target clean resources in next calls Significant DSM program Target clean resources in next calls Limit Burrard energy reliance to 3000 GWh Rationale Avoids further exposure to gas prices by reducing need for calls and ensures calls avoid gas projects Avoids further exposure to GHG offset policies and prices by reducing need for calls and ensuring calls avoid gas projects Burrard capacity is required and by lowering energy reliance 1) reduces risk of technical or social license issues reducing plant availability, 2) is in line with Government Energy Plan and 3) reduces the impact if something goes wrong Provides maximum available capacity in the LM/VI region without targeting further and potentially expensive capacity additions
GHG Offset Requirements and Costs
Burrard incapable or not permitted to operate
ILM Timing Construction results in LM/VI shortages
Maintain Burrard for 900 MW of capacity and retain CE as a contingency resource Investigate the potential for cost effective DSM capacity programs or curtailable load
59
Contingency Resource Plan
Table 6-14
Rationale Risk F2017
CRP Shortfall Risks
Capacity Reduction
[1]
(MW) F2028
Energy Shortfall Risk (GWh) F2017 F2028
Load Forecast Uncertainty DSM Deliverability Risk[2]
Peak load and energy requirements can increase as a result of either sustained growth or low temperatures on winter peak. DSM programs as modelled have a significant range of deliverability where the variability is driven by implementation of codes and standards, customer response to rate design and rate increases. Capacity related to DSM energy savings was separately addressed as shown in section 5.7 or Appendix F-17
500
660
2,800
4,900
230
380
1,600
2,500
Burrard Unit Catastrophic Failure
Given the condition of the units, some units could suffer catastrophic failure, notwithstanding the planned refurbishment work and procurement of critical spares to reduce down time. Based upon less Bioenergy projects being successful.
150
150
n/a
n/a
Calls Capacity Reduction Total Reduction:
50 930
n/a 1,190
n/a 4,300
n/a 7,400
60
Contingency Resource Plan
Table 6-15 CRP#1
BRP Unit Mica 5 Mica 6 Not Required Not Required
CRP #1 F2014 F2016
61
Contingency Resource Plan
Table 6-16
Action Short lead time acquisition processes BC Hydro would seek to undertake shorter lead time acquisition processes that could include prequalification of bidders and pre-established acquisition rules. The DSM programs identified have an ability to adjust the timing and rate of delivery of energy savings. In the case of a short term shortfall of energy, BC Hydro would ultimately resort to market energy acquisitions.
Energy Contingencies
Description
DSM Program Adjustment
Market Reliance
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Contingency Resource Plan
Table 6-17 Unit Site C Mica 5 Mica 6 BRP Not required Not Required Not Required CRP#2 CRP #2 F2020 F2014 F2016
63
Transmission Contingency Plan
Table 6-18
Contingency Resource Plan - LM/VI Capacity Balance with 5L83 delayed (MW) Fiscal Year 2007 High Load Forecast LM/VI before DSM DSM Savings Net Peak Load Forecast LM/VI Dependable Capacity (excluding Burrard) Capacity Available via ILM - Under System Normal - Under N-1 Contingency Burrard Capacity Requirements - Under System Normal - Under N-1 Contingency CE Capacity Requirement - Under System Normal - Under N-1 Contingency 11/12 8515 303 8212 1822 12/13 8640 413 8227 1873 13/14 8760 531 8229 2026 14/15 8869 626 8243 2159 15/16 8969 737 8232 2159 16/17 9126 864 8262 2175 17/18 9243 987 8256 2226 18/19 9423 1110 8313 2226 19/20 9597 1215 8382 2226 20/21 9775 1292 8483 2226
5242 5000
5367 5000
5673 5000
5525 5000
5529 5000
5684 5000
5686 5000
5734 5000
5751 5000
5760 5000
750 750
750 750
530 750
559 750
544 750
403 750
344 750
353 750
405 750
497 750
398 640
237 604
0 453
0 334
0 323
0 337
0 280
0 337
0 406
0 507
64
Break
DSM
Steve Hobson
Overview of DSM Options in the Portfolio Analysis
Two DSM Resource Options (A & B) Cost Effective Resource Options Uncertainty DSM Option A selected
67
Overview of Proposed DSM Plan
Codes and Standards
23 changes to Provincial and Federal regulations across building codes and equipment regulations
Rate Structures
Two-step incline block rate structures for all major rate classes
DSM Programs
21 programs across 3 sectors
Supporting Initiatives
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Overview of Proposed DSM Plan
Codes and Standards
Category Electronic equipment Incandescent lighting Other residential equipment Building code Appliances Large motors Commercial equipment High intensity discharge lamps and ballasts, packaged terminal air-conditioners, ice-cube makers, large air-conditioners, commercial clothes washers Clothes washers, refrigerators, freezers, dishwashers Windows, ceiling fans, furnace blower motors, torchieres, hot tubs, small motors, room air-conditioners Components Standby power, set-top boxes, external power supplies, battery chargers
69
Overview of Proposed DSM Plan
Rate Structures
Sector Residential Rate Class Residential (application filed with BCUC February 2008) Small general service (<35 kW) Commercial Large general service (>35 kW) Large general service (>35 kW) Industrial Transmission (existing)
70
Overview of Proposed DSM Plan
Programs
Residential Behaviour Voltage Optimization Lighting Sustainable Community Refrigerator Buy-Back Renovation Rebate New Home Low Income Appliances and Electronics Load Displacement Sector Enabling Activities Commercial Power Smart Partner Product Incentive High Performance Building Voltage Optimization Sustainable Community Load Displacement Sector Enabling Activities Industrial Mechanical Pulping Power Smart Partner – Transmission Power Smart Partner – Distribution New Plant Design Load Displacement Sector Enabling Activities
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Overview of Proposed DSM Plan
Supporting Initiatives
Supporting Initiative Components Funding and technical assistance Codes and Standards Support Research on new opportunities Industry and stakeholder support Training and education support Advertising Public Awareness and Education School education Internet Showcasing public figures as advocates for conservation Partnering with non-government organizations Codes and standards at local government level Community Engagement Support for incorporating energy strategies into community plans Event sponsorships Public outreach Community specialists Technology Innovation Technology identification, introduction and demonstration Support for technology commercialization and adoption Support and administration Regulatory Indirect and Portfolio Enabling Activities Strategy and policy Processes and documentation DSM-related training and education Information Technology For internet and tracking and reporting
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Overview of Proposed DSM Plan
Planned Energy Savings in F2020 (GWh/yr)
Codes and Standards Residential Commercial Industrial Total 2,760 500 110 3,370 Rate Structures 980 390 730 2,090 Programs 1,070 1,480 2,590 5,150 Total 4,810 2,370 3,430 10,610
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Risk Management
Individual components undergo more detailed design Tracked against milestones and energy savings Flexibility to adjust individual components Flexibility to adjust mix of components over time
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Burrard
Randy Reimann
Burrard – Implementation
Determination of $1.6 million are in the public interest BC Hydro requests that the BCUC endorse BC Hydro’s plan
900 MW of dependable capacity and 3,000 GWh/year of firm energy.
The plan reflects a commitment and requirement to:
Undertake the inspection work Fund the additional capital investments and OMA expenditures identified in Scenario 2 of the AMEC Burrard Current Configuration Study Average over 2009 – 2015 (timing to be confirmed)
• • $31M/yr capital $18M/ year OMA
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Burrard – Implementation - Need
System Condition Burrard Reliance (MW) CE Reliance (MW)
Base Plan Normal Base Plan N-1 T Contingency after 1 hr
640 900
0 115
CRP* Normal CRP* N-1 T Contingency after 1 hr
750 750
400 640
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Burrard – Implementation – Time Line
F2009
Develop project plan to undertake detailed inspections including tendering and retaining consultants;
F2010-F2012
Undertake detailed unit inspections at the rate of two per year. Order of inspections to begin with older and worse condition Units 1-3. Units 4-6 would follow. This work would include taking key measurements for any critical spares identified in the inspection.
F2010-F2012
Procure critical spares immediately as identified in the detailed inspections. Non-critical items would be reflected in capital plans.
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Mica Unit 5 and Unit 6
Ken McKenzie
Mica Unit 5 / Mica Unit 6 – Implementation
BC Hydro is requesting a determination that expenditures of $30 million in F2009, F2010, F2011 to complete the Definition phase work for Mica Unit 5 and Mica Unit 6 are in the public interest Completing the Definition phase for both Mica Units at the same time is also in the public interest Stakeholder Engagement process and economic assessment confirmed optimal development sequence of Mica Unit 5, followed by Mica Unit 6, followed by Revelstoke Unit 6
80
Mica Unit 5 / Mica Unit 6 – Implementation
To retain Contingency Resource Plan date of F2014 for Mica Unit 5, BC Hydro will undertake to complete in the Definition Phase: Stakeholder Engagement (Regulatory agencies, First Nations, Local Government and stakeholders) First Nations consultation Environmental Regulatory approval (Environmental Assessment Certificates, Federal) Technical design work Award turbine and generator contract – complete turbine model test Application to BCUC for a Determinations for implementation Implementation phase project plan The Mica units provide: Very long term (50 + years) dependable capacity (465 / 460 MW) Dependable capacity can be sustained over daily 16 HLH UCCs delivered to the Lower Mainland : $34 / kW-yr to $49 / kW – yr Table 6-6 Direct and Loaded Capital Cost Estimates for the Mica Units ($2008) Expected Direct Cost ($M) Mica Unit 5 Mica Unit 6 316 316 Expected Loaded Cost ($M) 420 420 High Case Loaded Cost and deferred ISD ($M) 560 700
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Mica Unit 5 / Mica Unit 6 – Timeline
Table 6-7
Activity
Definition Phase starts Phased Turbine tender award Expected issuance of EAC Expected Determination issuance by BCUC Definition phase ends Mica Unit 5 Implementation Phase begins Turbine model tests complete Mica Unit 5 In-Service
Mica Units Definition Phase Timeline
Target Completion Date
May, 2008 May, 2009 February, 2010 February, 2010 June, 2010 June, 2010 August, 2010 October, 2013
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Implementation: Site C
Mike Savidant
Site C: Background
BC Hydro is requesting a determination that Site C Stage 2 expenditures are in the public interest
Stage 2 is Project Definition and Consultation Stage 2 expenditures forecast to be $41 million
Stage 2 work will preserve Site C as an available supply option for 2019 BC Energy Plan mandated BC Hydro and the Province to enter into consultation with First Nations, the province of Alberta, and communities LTAP Portfolio analysis shows Site C offers economic benefits to ratepayers in a range of scenarios
84
Site C: Staged Process
85
Site C: Project Definition
Engineering Field Investigations and Studies
Updating decades-old studies including:
• • • • Flood and earthquake design criteria Foundation conditions Peace river thermal regime and total gas pressure Others
Will inform consultation process and may be required if project moves into environmental assessment Will be used to confirm design criteria and inform project costs
Commercial Analysis
Update interim project cost estimate Investigate potential procurement options
86
Site C: Environmental & Social Issues
Environmental and Socio-Economic Studies and Field Research
Prepare information baseline of current conditions in preparation for assessing project effects Have planned for more than fifty studies over the next two years
Technical Advisory Committees
Preparation for potential entry into federal / provincial environmental regulatory process Participation from province, federal government, First Nations, local government, and local experts where applicable Topics: Fish, Wildlife, Land Use, GHG, Recreation / Tourism, Heritage, Community Services & Infrastructure
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Site C: Consultation
Stakeholder and public consultation
Opened consultation office in Fort St. John (January ‘08) Pre-consultation process (Dec ‘07 – Feb ‘08) First round of project definition consultation (May ’08 – Jun ’08) Second round of consultation planned for Fall 2008
First Nations consultation
Parallel, separate process from public consultation
Inter-provincial consultation with Alberta and NWT
88
Site C: Stage 2 Deliverables
Project Definition Report (Stage 2 Report)
Updated project definition Report on results of public consultation Updated project cost estimate
Recommendation to BC provincial government Provincial government will decide whether or not to proceed to Stage 3 Stage 3 would include the formal regulatory process and environmental assessment
89
Acquisitions
Jim Scouras
Clean Power Call – Order Sought
Expenditures of $2.0 million in F2009 and F2010 to complete the Definition phase work and implement the Clean Power Call are in the public interest Request that BCUC endorse the following:
proposed target of 5,000 GWh/year of firm energy, that the energy to be purchased must qualify as “clean or renewable” in accordance with the B.C. government’s Clean or Renewable Electricity Guidelines, and the eligibility requirements for the Call.
91
Clean Power Call – Structured RFP
RFP establishes BC Hydro’s preferred terms and conditions
RFP provides flexibility to explore variations or alternatives that add value to ratepayers
Proponents may submit modifications to the specimen EPA BC Hydro can initiate discussions and negotiations with selected proponents after proposal submission RFP approach reduces risk of legal claims
Power Acquisitions
92
92
Clean Power Call – Key Eligibility Criteria
Project Size – minimum of 25 GWh/year of energy Project Location – must be located in B.C. Project Type – new generation Interconnection – must have interconnection point on integrated system and follow BCTC’s OATT Biomass – forest-based biomass not eligible Existing Contracts – must be terminated shortly after call issued System Freshet Limitation – No greater than 25% of firm energy during May 1 to July 31 period
93
Clean Power Call – Evaluation
BC Hydro will determine the most cost-effective portfolio based on a comparison of adjusted bid prices and potential consideration of several nonprice factors. The bid price adjustments currently contemplated are as follows:
Hourly Firm: ~$4/MWh deduction for flat energy profile Wind Integration: $10/MWh adder for wind projects Interconnection/Transmission: adder for project specific costs borne by BC Hydro for interconnection, network upgrades and transmission losses
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Clean Power Call – Key Terms and Conditions
Product – seasonal or hourly firm energy Term – 15 to 40 years COD – November 1, 2010 to November 1, 2016 Environmental Attributes – All transferred to BC Hydro
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Bioenergy Call
Bioenergy Call - Phase I
A flexible RFP for projects viable now and do not require new tenure from Ministry of Forests and Range (MoFR). Issued February 6, 2008; submission deadline is June 10 Targeting 1,000 GWh/year of new firm energy
Bioenergy Call - Phase II
For projects that require more time and/or new forest tenure (presently being completed by MoFR) Launched by July 2008 after inventory and forest tenure analysis is complete Targeting 1,000 GWh/year of new firm energy
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Fort Nelson Resource Plan
John Rich
Fort Nelson Resource Plan
Outline
Fort Nelson Resource Plan
Overview of Fort Nelson Area Existing and Future Supply/Demand Supply Options Initial Assessment
Resource Plan
Proposed Approach and Schedule
Next Steps Questions
98
Fort Nelson Resource Plan
Overview of Fort Nelson Area
Pre-1991 Diesel generating station 1991 Transmission line to Alberta 1999 Fort Nelson 47 MW (nominal) gas-fired
Fort Nelson
Connected to Alberta system
generating station Forecasted minimal load growth
2000 Decommissioned diesel generating
station Firm back-up supply from Alberta
2007/8 Load in the Fort Nelson area increased
by more than 50% (now about 40 MW)
99
Fort Nelson Resource Plan
Supply/Demand Balance
Current Supply Implications
50% load growth in less than 2 years Modest new supply Gap between supply & expected load needed to meet actual and expected Reliability deteriorated growth
Future Supply Implications
Potential significant load growth (as much as 200% above forecasted) Industry-related growth and fuelswitching
Significant future load growth will require major new resources
100
Fort Nelson Resource Plan
Reference Demand Forecast and Possible Load Growth Scenarios
120
100
80
MW
60
40 Reference Forecast High Scenario Medium Scenario Low Scenario
FNG 40MW
(dependable)
20
0 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 Calendar Year
101
Fort Nelson Resource Plan
Resource Options
Local Generation
FNG Upgrade project Further expansion of FNG IPP – Acquisition of clean or renewable or gas-fired generation
Transmission
Connection from Fort Nelson to BC Hydro grid (Peace region) Increased supply from Alberta (A1 and A2 reinforcement options identified for analysis)
Load
Demand-Side Management
102
Fort Nelson Resource Plan
Local Generation - FNG Upgrade Project
Convert the existing simple cycle gas-fired unit into a combined cycle facility without expanding the existing footprint Estimated cost ~ $59 million Planned ISD: March 2012
EFFICIENCY & POWER OUTPUT IMPROVEMENTS ENVIRONMENTAL IMPROVEMENTS
Increase power output by about 8MW to 12MW (nominal) More MWh produced for the same natural gas consumption Add voltage support to the region
Reduce effluent production by 50 – 75% Reduce GHG per MWh by roughly 20% Potentially reduce raw water usage by 60 – 80%
103
Fort Nelson Resource Plan
Local Generation - Fort Nelson Generation Expansion
Double size of existing FNG (after upgrade project) by adding second CCGT. Economies of scale relative to greenfield CCGT.
Local Generation - IPP Acquisition
Clean or Renewable Generation Procurement
Request for Expression of Interest (RFEOI) for Clean or Renewable Projects was undertaken in October 2007 6 Biomass, 2 Run-of-river, 6 Wind power, 2 Additional Clean/renewable supply unlikely to meet load – some potential for biomass although with high cost/fuel supply risk
Gas Generation Procurement
Greenfield CCGT – assumed characteristics same as FNG expansion.
104
Fort Nelson Resource Plan
Approach
Bundle supply options into “portfolios” Assess each portfolio against the forecasted load and each of the three scenarios (low, medium and high) Reliability and cost criteria were primary considerations Key input assumptions same as 2008 LTAP (GHG, gas/electricity prices) Other considerations identified for further assessment (e.g. consistency with BC Energy Plan) Economic and risk analysis on a range of uncertainties
Upgrade project capital cost GHG costs Gas/electricity prices Expected local generation dispatch Marginal versus system losses Load growth above scenarios Double circuited transmission line from Alta (Rainbow) to Fort Nelson
105
Fort Nelson Resource Plan
Portfolio Cost-Effectiveness as a Function of Load (Illustration)
120
New transmission line to BCH grid
100
or
New local generation
80
+
Upgrade of AB transmission supply
MW
60
+
FNG Upgrade
40 Reference Forecast High Scenario Medium Scenario Low Scenario
+
Fort Nelson generating station + Backup supply from Alberta
2026
20
0 2008 2010 2012 2014 2016 2018 2020 2022 2024 Calendar Year
106
Fort Nelson Resource Plan
Preliminary Results – PV Analysis
1,200
PV of Costs - Weighted Average Price Forecast, Mid GHG Offset Cost
1,000
PV (2012-2027) Millions
800
600
400
200 A0 = AESO Committed Trans A1 = AESO Upgrade 1 A2 = AESO Upgrade 2 A0.FNGU.LM.Link A0.FNG.LM.Link A0.FNGUBM.LM.Link A0.FBM.LM.Link FNGUBM = FNGU + 10 MW Biomass FNG = Existing FNG SCGT FBM = FNG + 10 MW Biomass FNGU = FNG Upgrade to CCGT B1 = New BCTC 230 kV to GMS FNGUCC = FNGU + 60 MW CCGT Link = GHG Linked Markets Scen (Mid) A1.FNGU.M.Link A2.FNGU.M.Link A1.FNG.M.Link A0.FNGUCC.LM.Link A1.FNGUCC.M.Link A2.FNG.M.Link A1.FNGUBM.M.Link A2.FNGUBM.M.Link A1.FBM.M.Link A2.FBM.M.Link B1.FNGU.Link B1.FNG.Link
Reference Low Scenario Mid Scenario High Scenario B1.FNGUBM.Link B1.FBM.Link
0
Portfolio
107
Fort Nelson Resource Plan
Initial Indications
New supply required just to meet expected load forecast All supply options will require significant investment and lead time RFEOI indicates clean or renewable supply alone cannot meet future load FNG Upgrade project and Alberta transmission reinforcement (A1) appear to be cost-effective building blocks across all load growth scenarios More detailed study of other options, combined with increased certainty of future load increases needed to determine next best supply option
108
Fort Nelson Resource Plan
Next Steps
Advance FNG Upgrade project
Evidentiary update to be filed in August 2008 Seek regulatory approvals First Nations and Stakeholder Engagement to be completed
Initiate more detailed studies of:
Transmission reinforcements to support increased supply from Alberta Expansion of Fort Nelson generating station (~ double the size) and new gas generation Integration of Fort Nelson to BCH grid
109
Next Steps
Joanna Sofield
Next Steps
Intervenor written comments accepted up to noon on this Friday June 6th Target Filing Date June 12th BCUC IR No. 1 – July 3rd Intervenor IR No. 1 – July 10th BC Hydro Responds – August 14th Evidentiary Update – August 21st BCUC IR No. 2 – August 27th Intervenor IR No.2 – September 3rd BC Hydro Responds – October 1st Procedural Conference – October 3rd
111