Muskrat Falls Development Presentation to the PUB July, 2011 - - PowerPoint PPT Presentation
Muskrat Falls Development Presentation to the PUB July, 2011 Presentation Outline Purpose of Presentation 1. Provincial Energy Plan 2. Meeting Domestic Power Needs 3. Analyzing the Alternatives 4. Electricity Rates 5. Selecting the
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– Meeting provincial electricity needs – Re‐investing wealth from non‐renewable oil resources
– Replacing Holyrood Thermal generating Station (HTGS)
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requirements so there is electricity available when people need it
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Driven by economic growth and electric heated homes.
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86% of new homes have electric space heating: conversions from oil as oil prices rise
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On average, 50% of home electricity costs and usage are from electric heat
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Domestic demand has grown steadily over time and will continue
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Vale Inco smelter, average 92MW (0.73 TWh annually) at full production
delay in needing new generation
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Hydro Rural)
for 20 year period
Gov’t, PIRA and Hydro)
saturation
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Load forecast is realistic and reflective of the expected provincial demand
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2500 5000 7500 10000 12500 15000 Gigawatt hours Historical Forecast
Population declined by 12% but electricity use continued to rise Vale Inco coming online Mill shutdowns Peak energy in 2004
1970‐2010 CAGR*: 2.3% 2010‐2067 CAGR*: 0.8%
* CAGR: Compound Annual Growth Rate
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6000 7000 8000 9000 10000 11000 1990 1995 2000 2005 2010 2015 2020 2025 Energy (GWh) Island Interconnected System Capability vs. Load Forecast
ACTUAL FORECAST TOTAL SYSTEM LOAD
FIRM CAPABILITY PRV & HRD#2 Uprating Southside Steam NUGS & RB (Small Hydro)
2010 PLANNING LOAD FORECAST
Fermeuse Wind Granite Canal, Exploits River Partnership and CBP&P Cogen. Firm Adjustment
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Year Island Load Forecast Existing System LOLH (hr/year) (limit: 2.8) Energy Balance (GWh)
Maximum Demand (MW) Firm Energy (GWh) Installed Net Capacity (MW) Firm Capability (GWh) HVdc Link/Isolated Island HVdc Link/Isolated Island
2010
1,519 7,585 1,958 8,953 0.15 1,368
2011
1,538 7,709 1,958 8,953 0.22 1,244
2012
1,571 7,849 1,958 8,953 0.41 1,104
2013
1,601 8,211 1,958 8,953 0.84 742
2014
1,666 8,485 1,958 8,953 2.52 468
2015
1,683 8,606 1,958 8,953 3.41 347
2016
1,695 8,623 1,958 8,953 3.91 330
2017
1,704 8,663 1,958 8,953 4.55 290
2018
1,714 8,732 1,958 8,953 5.38 221
2019
1,729 8,803 1,958 8,953 6.70 150 Capacity deficit forecasted and new generation required Energy deficit forecasted and new generation required
LOLH is a statistical assessment of the risk that the System will be incapable of serving the System’s firm load for all hours of the year. For Hydro, an LOLH target of not more than 2.8 hr/year represents the inability to serve all firm load for no more than 2.8 hours in a given year.
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Island Electricity Requirements By Source
Island Hydro & NUGs Thermal/Other Other Supply
2010 PLF Island Hydro and Non Utility Purchases Labrador or Other Supply 2041
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– Security of supply and reliability – Least cost option for ratepayers (measured as the
– Environment – Risk and uncertainty – Financial viability of non‐regulated elements
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Isolated Island LCP Options Other
Muskrat Falls first Gull Island first
Conservation & Demand Management Projections
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Parameter Assumption
Regional North American Electricity prices
World Oil prices
Environmental costs
Atmospheric Emission regulations or GHG; such costs would be unfavourable to the Isolated Island case
Cost escalation and inflation
Long run regulated financial assumptions
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2010 2015 2020 2025 2030
Wind 25 MW (power purchase) Island Pond 36 MW ($199M) Portland Creek 23 MW ($111M) Round Pond 18 MW ($185M) CCGT 170 MW ($282M) CT 50 MW ($91M) CT 50 MW ($97M) Holyrood upgrades, ESP/scrubbers, low NOx burners ($582M) Wind renewal 50 MW ($189M) Post 2030 – Holyrood replacement; additional thermal ($1,504M)
Total capex $3.2 billion before adding fuel expense & sustaining capital
$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 2010 2020 2030 2040 2050 2060
Isolated Island Revenue Requirements
$millions nominal
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Economic Indicators ($ millions)
Key Risks:
Reliability Considerations:
grid Rate of return on non‐regulated elements:
Holyrood replacement
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2010 2015 2020 2025 2030
HVDC Island Link 900 MW LCP Muskrat Falls 824 MW CT 50 MW Holyrood standby Holyrood shut down Post 2030 – thermal units for reliability support only
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1,000 2,000 3,000 4,000 5,000 6,000 7,000 2010 2014 2018 2022 2026 2030 2034 2038 2042 2046 2050 2054 2058 2062 2066 GWh
Island ‐ Labrador Electricity Supply Balance
Muskrat Supply to Island Market Activity and/or Spillage
2010 PLF Surplus for Market Activities and/or Spillage Muskrat Falls Supply for the Island CF Supply 2041
The price paid by the Island ratepayers is based on LCP cost assuming a return similar to a regulated utility
$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 2010 2020 2030 2040 2050 2060
Revenue Requirements: Isolated Island versus LCP Muskrat
$millions nominal
Island Isolated LCP Muskrat
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Economic Indicators ($ millions)
Key Risks:
Reliability Considerations:
grid via Churchill Falls Rate of return on non‐regulated elements:
spill Long term superior value $2.2B
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Criteria Muskrat Falls Isolated Island Security of supply and reliability ‐ Interconnection with NA grid ‐ Limited reliance on fossil fuel ‐ No interconnection with NA grid ‐ Heavy reliance on fossil fuel Cost to ratepayers (CPW) ‐ CPW of $10,114 M ‐ Lower over long term ‐ $2.2 B in net savings vs. Isolated island case ‐ CPW of $12,272 M ‐ Higher than Muskrat Falls over long term Environment ‐ EA almost completed ‐ Environmental impacts well studied ‐ Much lower GHG emissions ‐ Numerous environmental assessments will be required ‐ Unknown environmental impacts Increased GHG emissions Risk and uncertainty ‐ Significant planning and engineering work completed ‐ Minimal engineering work and planning completed Financial viability of non‐ regulated elements ‐ 8.4% IRR on non‐regulated elements ‐ NA
– Planning decisions cannot be deferred
– Even assuming no value obtained for surplus MF power
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– Commercial
– Project Execution
– EA & Regulatory
– Stakeholder Engagement
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Current Target: Oct 2016
– Staged‐gate project delivery models
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capital predictability
Decision Gate is focused towards ensuring a full understanding of all Project risks
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Driver behind Decision Gate Key Deliverables
we understand the risks and
right choice at the Decision Gate
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Decision Gate 3
Project Influence Curve
Risk Framing and Analysis
Technical Regulatory / Stakeholder Financial Execution
Risk‐Informed Decisions & De‐Risking Strategies
Financial Risks Regulatory & Stakeholder Risks Technical Risks Execution Risks
Risk Exposure ‐ People ‐ Environment ‐ Capital ‐ Schedule ‐ Revenue ‐ Quality ‐ Reputation
Commercial Risks
Commercial
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Confidential
Project Team led by Project Director complete deliverables during phase leading up to Gate. Recommendation for the Gate made via a Decision Support Package. Independent Project Review (IPR) Team complete interviews and assessment to verify readiness & prepare Gate Readiness report. LCP Executive Committee review DSP and IPR report and make recommendation to Gatekeeper. Gatekeeper makes recommendation to NE Board and Shareholder.
Decision Gate
Step 1a Step 1b Step 2 Step 3
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DG 2 Nov‐10
2008 2009 2010 2007 2006
LIL EA Registration Jan‐09 New Dawn Oct‐08 Generation EIS Submittal & Issued EOI for Detailed Design Feb‐09 DG 1 Feb‐07 Gull & TL Field Programs Commence Jun‐07 SOBI Geotech. & Seismic Program Sep – Nov 09 SOBI Seabed Option Confirmed Sep‐10 MF Geotechnical Program Jul – Oct 10 ASEP Training Program Announced Jul‐09 SOBI Crossing Task Force Established Generation EA Registration Dec‐06 IPA Pacesetter Review Aug‐08 Start Mobilization
Project Team Award Feasibility Studies Contracts to Hatch, SNC‐Lavalin & Fugro‐Jacques Apr‐07
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Maritime Transmission Link
to Cape Breton NS
Muskrat Falls Generation
Labrador‐Island Transmission Link
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EPCM‐led Scope
Sub‐Project
Environmental Assessment & Aboriginal Affairs Nalcor Other Activities Muskrat Falls Generation (Component 1) Island Link ‐Land Portion (Components 3&4) Island Link ‐ Strait of Belle Isle Marine Crossing Maritime Link ‐ Land Portion EA – MF & GI Generation with MF/GI Interconnect EA – Island Link EA ‐ Maritime Link Aboriginal Affairs Power sales & market access Finance Existing Contracts Industrial Relations Execution Readiness Insurance 824 MW powerhouse and supporting structures including: ‐ Infrastructure/Temps ‐ Powerhouse/Intake ‐ Dams/Spillway ‐ Overhead Lines ‐ Reservoir 345 kV HVac transmission interconnect between Muskrat Falls and Churchill Falls 1050 km Overhead Transmission Line ‐ incl. Transition Structures HVac to HVdc converter stations at Muskrat Falls and Soldier’s Pond Shore Electrodes at SOBI and Dowden’s Point ‐ incl. transmission line Switchyard on Avalon Island System Upgrades Route and Installation Strategy Shoreline / Landfall Protection Subsea Cable Procurement and installation Subsea Protection 127 km Overhead Transmission Line HVac to HVdc converter stations at Bottom Brook and Lingan Shore Electrodes in NL and NS Island System Upgrades
Sub‐Project Sections
Maritime Link ‐ Cabot Strait Marine Crossing Route and Installation Strategy Shoreline / Landfall Protection Subsea Cable Procurement and installation Subsea Protection
Emera‐led Scope Nalcor‐led Scope Nalcor Energy – Lower Churchill Project Overall Project Management
Project Delivery accountability and interfaces with NE Corporate.
Functional Managers and expertise.
Project Teams for MF + LIL, SOBI, and Maritime Link.
expertise required for delivery.
manage the EPC and contractors (the builders).
their vendors, contractors and sub‐ contractors.
Nalcor Corporate
NE‐LCP MF + LIL Team MF + LIL EPCM Consultant NS‐NL EPC(s) / EPCI (s) NE‐LCP NS‐NL Team SOBI EPC(s)/EPCI s)
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Established Performance Baseline Focused Project Control Resources Control During Execution
made to define and document the projects scope, schedule and cost estimates
benchmarked against other projects
pricing data for labour, equipment and materials
prepared to facilitate effective cost control during construction
contingencies to address uncertainties have been established
world class EPCM contractor SNC‐ Lavalin who are focused on controlling projects cost and schedule against baseline plans
schedule and scope management approach
management of change processes implemented
experienced professionals provide both continual managerial and technical oversight of the projects
identify emerging issues and initiate management action
showing physical progress
management of performance trends
and schedule form the basis for management of change
process to challenge all project changes that can affect the projects cost and schedule
Four key attributes of successful project execution are addressed in these projects:
review at decision gates and expert panels).
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– Most economic and least‐cost option – Holyrood thermal plant coming off‐line and thermal replacement
avoided
– Enhances system reliability and security of supply with interconnection – Rate stability for customers over long term – Generates a positive rate of return for province
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