Keegan Moyer Interim Manager, Transmission Expansion Planning ColumbiaGrid 2012 TEPPC Study Requests August 1st, 2013 ColumbiaGrid – Portland, OR

Outline 2011 and 2012 Study Programs ColumbiaGrid studies PC23 Northwest Resource Option PC27(a-b) Northwest Firmed Resource Option WECC 2013 Interconnection-wide Transmission Plan

WECC performed over 80 studies in 2011 and 2012 Build dataset, run a few studies Run a bunch of studies using same dataset 10-yr No model Build dataset, run a few studies 20-yr

TEPPC’s delicate balance Many individual “one-off” study requests. Limited time and resources Do “new” things This is why TEPPC does not always perform studies that exactly meet the stakeholders request. But hopefully they meet the intent

Study Results NW Resource Option Selkirk-Bell-Ashe Nicola-Chief Joseph Selkirk-Ashe DC Selkirk-Buckley DC Focus of plan will be on common case. Spend time on it here.

Renewable Options Under High Load Cases The Basics Study Concept Starting case: 2022 High Load (PC1-5) Increase WECC annual energy demand 8% Results in additional 12,000 GWh of RPS resource requirements (per statutes) Model added 12,000 GWh in regions throughout WECC (w/ transmission) Goal Compare different resource and transmission options Total (capital and production) cost comparisons

Renewable Options Under High Load Cases Increase WECC-wide load 8% 1 Add: 12,000 GWh to meet WECC RPS 2 3 Add transmission For these regions

8% increase to peak and energy 1 Increase WECC-wide load 8% 8% 8% increase to peak and energy 10% 10% decrease to energy LRS to common case 3.2% Higher Load = Additional RPS Energy

2 Add 12,000 GWh to meet WECC RPS Calculate ratios of planned renewables in TEPPC 2022 Common Case Do not include existing resources Do not include DG IRP and LRS data Apply ratio to study build-out of 12,000 GWh Concept: development trends are best representation of what could be added to each state More resources available than what is identified in WREZ More granular information from CPUC/CAISO Locate resources using WREZ peer-analysis tool Extrapolation Method

Wind Solar PV Solar Thermal Small Hydro Geothermal Biomass RPS Northwest Resource Assumptions Capacity Added (MW) + 3375 + 76 + 71 + 2284 + 56 + 48 + 49 Wind Solar PV Solar Thermal Small Hydro Geothermal Biomass RPS

Transmission Expansion Projects 3 Add transmission Transmission Expansion Projects Path 8 Upgrade MSTI + SWIP N Selkirk – Bell – Ashe Nicola – Chief Joe Selkirk – Ashe DC Selkirk – Buckley DC WY-CO Intertie TransWest Express Zephyr A /B/C/D High Plains Express SSPG East SSPG North SSPG South High Plains Express None Centennial West

Now to the results… Portfolio Case generation results (versus PC1-5 High Load) Transmission projects overview Expansion case generation results (versus PC1-5 High Load and Portfolio Case)

Northwest Expansion Projects Expansion Cases Key Assumptions EC23-1 Selkirk – Bell – Ashe British Columbia to central Washington; 1,500-MW AC EC23-2 Nicola – Chief Joe EC23-3 Selkirk – Ashe DC British Columbia to central Washington; 3,000-MW DC EC23-4 Selkirk – Buckley DC AC Projects DC Projects

Expansion Project Flows AC Projects DC Projects Most + energy Most net energy Focus on this result Input/Result EC23-1 EC23-2 EC23-3 EC23-4 75% Limit 0.23% 0.00% 0.42% 0.41% 90% Limit 0.16% 0.14% 99% Limit 0.10% 0.09% PosFlowLimit(MW) 1,500 3,000 NegFlowLimit(MW) -1,500 -3,073 Total Flow (net) 889,968 1,428,025 1,987,700 1,638,558 Total Flow (+) 2,303,169 2,263,289 2,252,492 2,063,278 Total Flow (−) -1,413,201 -835,264 -264,792 -424,720 Path Interstate Selkirk-Bell Interstate Nicola-Chief Joe Interstate Selkirk-Ashe DC Interstate Selkirk-Buckley DC

What is different? Loads Transmission Resources

What is different? Loads Transmission Resources

AC projects Selkirk – Bell – Ashe Nicola – Chief Joe Selkirk – Ashe DC Selkirk – Buckley DC AC projects

Decreased flow on Path 3

Decreased flow on COI/PDCI

Annualized Cost (M$/yr) Cost Results PC23 Northwest – Incremental Resources Levelized Fixed Costs ($/kW-yr) Levelized Fixed Costs ($M/yr) Type MW CF Total Renewable Resources Added OR Biomass RPS 48 41.98% $626 $30 OR Geothermal 56 89.08% $667 $37 OR Solar PV – Tracking 49 19.61% $260 $13 OR Wind 1,902 25.68% $218 $415 425 21.53% $227 $96 WA Biomass RPS 41 39.23% $632 $26 WA Small Hydro RPS 76 99.57% $512 $39 WA Wind 1,500 23.61% $224 Capacity Resources Removed CA CT-Aero -500 85.00% $238 -$119 Net Change in Resource Capital Cost* $1,096 *Relative to 2022 PC1-5 High Load Expansion Case Voltage/ AC or DC Line Length (mi.) Line Cost (M$) Substation Cost (M$) Annualized Cost (M$/yr) Selkirk – Bell – Ashe 500-kV AC 326 $1,209 $20 $177.00 Nicola – Chief Joe 186 $988 $10 $143.73 Selkirk – Ashe DC 500-kV DC 239 $678 $1,092 $254.92 Selkirk – Buckley DC 387 $1,220 $332.98

Cost Results

Flow Comparison

Study Results Northwest Firmed Resource Options Focus of plan will be on common case. Spend time on it here.

Hydro Firming Modeling Goal Compare different hydro dispatches in different wind conditions given various modeling techniques Compare path flows and production costs Implementation Steps Start with 2022 PC23 NW Resource Option (+12,000 GWh) Increase WECC annual energy demand 8% Add 12,000 GWh of renewables to NW Under the purview of high wind in a particular region, investigate how a nearby region’s hydro responds based on different types of modeling (commercial behavior) Investigate how the changes listed above impact path flows 5 – system cost curve OR L – localized view from LMP Signal, or M LMP with depth, iterative LMP dispatch signal (time-intensive) – we use this option Pumping dispatch cost option – permits pumped storage generation to displace generation in several hours with energy resulting from pumping in one hour. The average cost of the whole pumping capacity step is used in the economic evaluation LP – allocating limited resources among competing activities in the best possible way (optimal)

Renewable Options Under High Load Firmed Cases Increase WECC-wide load 8% 1 Hydro Add: 12,000 GWh to meet WECC RPS Gas 2 3 Add: firming resource 4 Add transmission Pumped storage For these regions

NW Firmed Resource Cases Comparing Four Cases PC1-5 High Load PC23 NW Resource Option PC27a NW Firmed Resource PC27b NW Firmed Resource Shrum Shrum Shrum Shrum Mica Mica Mica Mica Revelstoke Revelstoke Revelstoke Revelstoke +12,000 GWh (mostly wind) +12,000 GWh (mostly wind) +12,000 GWh (mostly wind) No added resources +12,000 GWh resources +12,000 GWh resources +12,000 GWh resources Standard HTC modeling Standard HTC modeling Fixed shape hydro from PC1-5 (no resources) HTC modeling with price signals from a windy Northwest Compare Results Generation Hydro impact Path Flows Compare Compare

Production cost decreased $27 M (.15%) PC23 vs. PC27a Normal hydro Fixed hydro AZ, OR, CA, WA Production cost decreased $27 M (.15%) Dump energy increased 397 GWh (93%) Emergency Energy decreased 6% CO2 Emissions did not change Note the difference in energy is mainly due to the change in dump energy By eliminating dump energy, we require less energy to serve load Does it appear that simply fixing the hydro might be a better solution?? (its less expensive)

Production cost decreased $6 M (.032%) AL, BC Production cost decreased $6 M (.032%) Dump energy increased 80 GWh (19%) Emergency Energy decreased 0% CO2 Emissions decreased 0% Price sensitive had more dump

PC23 vs. PC27b Normal hydro NW $ Hydro

Suggests that the “dumb” hydro based on PC1-5 conditions was more economic than smart hydro that looks at area LMP. This makes no sense, of course. Production cost decreased $22 M (.125%) Dump energy increased 478 GWh (1649%) Emergency Energy decreased 6% CO2 Emissions decreased 0% Suggests that the “dumb” hydro based on PC1-5 conditions was more economic than smart hydro that looks at area LMP How do we explain this?

PC27a vs. PC27b Fixed hydro NW $ hydro

Only modeled plants – 7500 MW of generation Red – fixed shape Energy moved Only modeled plants – 7500 MW of generation Red – fixed shape Blue – aggressive htc Yellow – normal htc Note how energy was shifted in price responsive case (low flow to high flow)

S-N Less S-N flow Most congestion was in 27b… This kind of makes sense since now our price responsiveness is ignoring whether P3 is congested when additional resources are being dispatched. This could result in a more gen, more dump, and likely a higher production cost! Congestion

Cost Comparison

Summary Northwest Firmed Resource Option with BC hydro fixed as historical data resulted in savings of $27 million annual over the PC23 Northwest Resource Option Case. HTC modeling of the firming hydro resources resulted in $7 million of savings over the “base case” PC23 Northwest Resource Option case. This means that having some portion of BC hydro providing price responsiveness based on NW market signals (near areas of high wind penetration) could result in West-wide savings of $7 million per year These savings do not include any costs to compensate or incent BCH for changing operation of its hydroelectric projects.

For study presentations and reports… http://www. wecc

2013 Interconnection-Wide Transmission Plan (approval at August TEPPC meeting) http://www.wecc.biz/committees/BOD/TEPPC/Pages/2013_Plans.aspx

Questions Keegan Moyer Interim Manager, Transmission Expansion Planning (801)819-7662 kmoyer@wecc.biz