IRP Advisory Group Draft Meeting Notes March 19, 2015 from 9:00 – 2:00 Summit Conference Room, PSE Building, Bellevue Attendees: James Adcock (customer); Joni Bosh (NWEC), Nicholas Matz (City of Bellevue); Brian Grunkemeyer and Doug Howell (Sierra Club); Yochi Zakai, Steve Johnson, and Juliana Williams (WUTC); Stephanie Johnson (Public Council), Bill Pascoe by phone (Absaroka Energy); Lloyd Reed (Reed Consulting); Michael O’Brien and Kelly Hall (RNW); Constantine Papafakis (Tollhouse Energy); Daren Anderson (NESCO); Phillip Popoff, Villamor Gamponia, Gurvinder Singh, Tom DeBoer, Qihui Qi, Elizabeth Hossner, Bob Williams, Janet Phelps, Nate Hill, Jennifer Creekpaum, Randi Aiken, and Allison Jacobs (PSE); and Lyn Wiltse, facilitator (PDSA Consulting) 2015 IRP Advisory Group Meeting Dates: April 9, May 19, July (TBD), and Aug (TBD) Times: 9:00 ‐ 3:00 except on Fridays when it is 9:00 – 2:00; Location: PSE Headquarters, Bellevue Meeting Topics for Next IRP AG Meeting on Apr. 9, 2015 9:00 – 3:00  Load Forecast  California Energy Balance  Market Reliance Market  Resource Needs  Agenda topics for May 19 meeting (Flexibility, “Final” Portfolio)  Set dates for July and August IRP Advisory Group Meetings Future TAG (Technical Advisory Group) Meetings  Portfolio Model Analysis (Mid‐April)  Stochastic Analysis (May?)  Flexibility Model (May?) New Action Items  Phillip Send out link to the 2015 PNUC Report on load when it becomes available.  Gurvinder Send Joni the source of 2.9% decline in installed cost of PV post 2025.  Bill Send Elizabeth pumped hydro info from MT that is closer to $2K /KW – not $5,556.  Jenifer Check to see what the Montana upgrade is built for. Would that upgrade affect the constraints of going west of Garrison?  Elizabeth See if the solar panel price numbers she uses match the ones Gurvinder is using.  Constantine Provide information re. MT sales tax on wind transmission. (Done)  Jennifer Check to see which Wind projects are in the queue and let Doug know. Ongoing Action Items  All Save the above meeting dates and plan to attend.  Lyn Send notes to Phillip to distribute. TAG MEETING REPORT Phillip reported that the only TAG to meet since our last meeting was the Load Forecast TAG. At that meeting they discussed how a 200 MGW reduction is anticipated on PSE’s system as a whole and how that filters down to the load level. 3‐20‐15IRPAdvisoryGroupMeetingNotes‐Draft
Page1 of 6 Two coal plants (Boardman and Centralia 1) in the area are scheduled to close in 2020 so the Power Council will be releasing two assessments in May of 2015 – one for 2020 and one for 2021. MARKET RELIANCE UPDATE Lloyd provided updated information on the PNW load and resources forecasts. Market reliance is defined as a utility’s ability to purchase wholesale power on the California market to meet load forecast and load obligations. In the 2013 IRP cycle, several investor‐owned utilities including PSE identified large purchase needs to meet those obligations. Several load forecasts here in the Pacific Northwest show a steadily declining surplus especially in winter capacity. A key question for PSE and others is to what level these utilities should rely on wholesale power to meet those needs. We are seeing lower growth rates in the Pacific Northwest for both energy and capacity. The Power Council is trying to improve modeling tools for regional hydro. The Pacific Northwest will be relying more and more on imports from California to help with winter peaking conditions. The challenge is that we cannot guarantee that those resources will be there for our use when we need them. This has not always been the case in the past. Can we lock up these resources on a long‐term physical firm basis? The limiting factor is how much is available in terms of transmission capacity from CA during our winter peak. Phillip doesn’t expect PSE’s IRP to address that issue. They have to make reasonable decisions. The Resource Advocacy Advisory Committee will come to a conclusion on what those assumptions will be. Steve pointed out that the model this committee has used over the years has changed. All seem to think the model is now more realistic about import capabilities and other resource capabilities in the region. Steve thinks PSE should include in their IRP a discussion of the dynamics between the Council and BPA. At their March 9 meeting slide 7 was very instructive – it showed 95% of the time in February over the last 5 years 3,400 MGW were available from California. If PSE doesn’t use that number, there should be supporting rationale. Lloyd walked us through a chart showing the trend is going from marginal surplus in the winter – and then crossing the zero point around 2019‐2020 and then declining in winter peaking capability. We would look to CA imports to meet the need. As CA adds more solar PV could some be available for export? There would likely need to be resources to help stabilize and shape the solar power in a way that it is more reliable. In the Genesis model, that functionality is built in to shape the hydro. The shaping capability of the NW power availability is already limited due to wind. PSE uses 5‐10% capacity credit given for wind. We don’t have an appropriate number yet for solar. Many have their eye on the Idaho solar plants to provide more reliability. From a risk management standpoint PSE wants to be in the “sweet spot”. Instead they are moving toward being a buyer in a seller’s market. At out last meeting in January, we had a lot of discussion around the characteristics of the WECC power markets. Lloyd summarized these. He noted the flexible bilateral markets outside of the CAISO’s system – where buyers and sellers contact each other directly for short‐ and long‐term agreements. Most WSPP transactions are not done on a unit specific basis. Description of Schedules:  Schedule A (non‐firm energy) is rarely if ever used anymore because the risk is concentrated on one or two specific units.  Schedule B (unit contingent) contracts are not used as often as Schedule C (non‐unit specific).  Schedule C transactions are treated as financially firm but not physically firm.  Schedule R is for renewable energy credits. 3‐20‐15IRPAdvisoryGroupMeetingNotes‐Draft
Page2 of 6 Deliveries of power can be curtailed if in a shortage position in order to meet their own obligations. Financial damages would be paid. PSE has a long‐term exchange contract with PG&E. It was filed with and approved by FERC. In 2001 when PG&E failed to deliver energy to PSE and PSE sued them, PSE lost that suit due to the vague language in the contract. WSPP has just filed for a new set of amendments from FERC. The amendment is evolving constantly. If we choose to rely on imports, we must consider how available that resource will be when we need it. Lloyd explained the $1,000/Mwh “soft” price cap (day‐ahead prescheduled and real‐time transactions). It is like a short‐term call option on energy. FERC can change this at any time and issue a price cap. He also explained the Loss of Load Probability (LOLP) peak capability model and how both the NWPCC and PSE have adopted a 5% LOLP planning standard (quantifies the ability of a utility to meet its peak load obligations). In 2015 PSE’s ability to buy the power it needs will be linked to regional availability. They are intending to synch up the Council’s modeling work with PSE’s modeling work. They are also taking into consideration what happened in 2000‐2001 and are looking at other markets outside the Pacific NW to see how they have reacted in shortage situations. PSE plans to utilize some metrics that were published by Lawrence Berkeley National Lab to help derive VoLL figures specifically for the PSE electric system. Note: This study is available at: http://eetd.lbl.gov/ea/EMS/EMS_pubs.html, Pub LBNL‐2132E DISTRIBUTED GENERATION SOLAR Gurvinder explained that PSE is looking at the potential they have for solar in all of their service territory. In past IRPs, DG Solar didn’t capture the incentives. PSE is looking now to see what could possibly happen on their system. They will be looking at the solar resource as a reduction on their load. The substance of this presentation came from the study done by Cadmus. The whole report will be part of the appendix which will be included in the IRP. It will also be made available to IRP AG members when the report is finalized. Tech Potential = Maximum production they would get on their system without regard to economics – looking at building stock, roofs (including pitch), panel capacity, sun, shade, vegetation, etc. CBSA = Commercial Building Stock Assessment; RASS = Residential Appliance Saturation Survey They have found commercial roofs are the best options (65%) Second best options are multi‐family homes (33%). They also use these data for their Energy Efficiency initiatives. Total technical potential is a whopping 14,000 MW (84% of which is commercial). Market potential = 4 different cases: 1. Base Case with policies to date and credits remain in effect (2016‐2035 Mkt Potential = 3 MGW)  ITC: 30% tax credit sunsets end of 2016 for residential, and reduced to 10% for commercial  State Sales Tax Exemption and CRP expires end of June, 2020 2. ITC gets extended (2016‐2035 Mkt Potential = 26MGW)  Base except extend ITS at 30% to end of the study 3. CRP (2016‐2035 Mkt Potential = 165 MGW)  Base except CRP and State Sales tax exemption (54 cents extended to the end of the study) 3‐20‐15IRPAdvisoryGroupMeetingNotes‐Draft
Page3 of 6 4. Best Case where all credits are extended, benefitting customers (2016‐2035 Mkt Potential = 309 MGW)  Continuation of CRP, State Sales Tax Exemption and ITC (at 30%) PSE plans to run the Base Case and the Best Case scenarios in their IRP (between 3 and 309 MGW). PSE is considering how to plan to meet those needs. The Annualized Simple Payback (ASP) was used to predict the market potential. ASP = Next Costs (after incentives) divided by Annual Energy Savings plus CRP payments. Note: CRP is the WA Renewable Energy Cost Recovery Program Incentive. Gurvinder walked us through various charts showing the market potential of distributed solar. The charts were in nominal dollars. There were questions about why PSE was using worst case numbers, e.g., using the SunShot worst case number ($3.78) when their best case was $1.50. Gurvinder will follow up with Joni to explain the source of the projected 2.9% decline in installed cost of PV post 2025 (slide 27). Brian noted he has recent information from an installer of a commercial system at $2.33 installed cost of PV and wondered if PSE could possibly run an additional scenario. Gurvinder explained they used average incentive of what people are building (locally constructed and imported). Third party financing could make a big difference as customers might be more likely to do solar through third party leasing. Joni asked whether PSE is planning to look at best case and worst case costs for the cost curve. Most think the numbers forecast are lower than what they are planning for. The number PSE may ultimately be looking at may be larger than 309? Joni also expressed appreciation for the presentation. Jim noted that smart convertors may allow solar to contribute to the stability of the grid. Also using electric cars and water heaters will help. 2015 IRP ELECTRIC RESOURCE ALTERNATIVES Thermal Resource Assumptions Elizabeth explained that PSE is using thermal resource assumptions from the Black & Veatch report commissioned by PSE. They are assuming a 40% owner’s cost for outside –the fence, project development, project financing, and escalation. They are also aware that heat rate degrades at an average of 2% over the life of the plant. CCCT is in compliance with Washington Emission Performance Standards at 970 lbs/Mwh. Capital costs include selective catalytic reducer (SCR). She reviewed all the assumptions for CCCT (modeling after a GE unit (one gas turbine and one steam turbine), Frame CTR, Aero Ct, and Reciprocating Engine. For combined cycle plants, PSE is assuming wet cooled. Dry cooled includes a 5% capital cost increase. They will be adding $15mm (one‐time costs) for oil back‐up for peakers (in addition to the capital costs). The oil in the tanks can last several years. Gas transportation costs when there is no oil back‐up. ‐ 100% NW pipeline to Sumas ‐ NW expansion to station 2. They have to buy 54K Dth/Day in fixed cost to make sure there is enough pipeline to bring in the gas when we need it. The annual fixed cost is $21MM. This is $1.07/Dth/Day x 54K Dth/day 365 days/yr. All 3‐20‐15IRPAdvisoryGroupMeetingNotes‐Draft
Page4 of 6 plants without oil back up. Other costs for each plan will be different depending on capacity and heat rates. 20% of all required gas needs to be in storage. RESOURCE ASSUMPTIONS FOR RENEWABLES Wind Resources Washington wind is in SE portion of the state (in the Lower Snake River area). PSE got estimated costs and capacity factors for both Washington and Montana Wind from RES. They are using the same facility costs from the Washington wind sites. They will look at specific transmission cost from Judith Gap to Broadview substation (71 miles on Northwestern line in Montana) and then over to PSE. There is KW loss along the line to get all the way to BPA system. Wind integration costs will come through BPA. There may be updated numbers from BPA that would get around Garrison – other ways to build upgrades that are reasonable form a cost perspective. 4 Scenarios for MT Wind Transmission Costs – Building 265 MW wind facility near Judith Gap: a. Colstrip retires, upgrade Judith Gap‐Broadview Line ($52.5MM) b. Colstrip retires, New Judith Gap‐Broadview substation upgrade ($114 MM) c. Colstrip operating, Upgrade JG‐Broadview line and expand Broadview substation and new Broadview – Garrison Line and expand Garrison substation ($682.5 MM) d. Colstrip operating, New JG‐Broadview line and expand Broadview substation and new Broadview – Garrison Line and expand Garrison substation ($744MM) BPA has said that if we add more capacity to Garrison, they will have to make more upgrades due to flow problems that will cost an additional ~ $1 billion. WA Wind Cost vs. MT Wind Cost WA Wind = $1,968 MT Wind, Scenario A = $2,061; B = $2315, C = $4659, D = $4913 MT peaks in winter so is a better shape to fit with PSE loads. WA Wind peaks in the spring. Incremental Capacity factors will translate into a higher capacity credit. Solar/ Biomass For Solar, Elizabeth explained PSE will use the numbers from NPCC estimates for the 7th Power Plan ‐ Central to Southern WA, fixed tilted PV. Elizabeth to see if the panel price numbers used here match the ones Gurvinder is using. For biomass, they are using the EIA Capital Cost Report, Western Washington, wood waste. PSE will assume a 20% capacity (MW) number for solar and 15% for Biomass. PSE has added in the cost of transmission to these resources. Note: The 2014 dollars were the 2012 dollars with a 2% escalation. Battery Located within PSE service territory; lithium –ion technology with 2 hours of storage. Pumped Hydro Located in Western Montana, 400‐3,000 MG, assuming PSE would slit the output with another party. Correction to Renewable Assumptions – Energy Storage slide 57: All in Cost ($/KW) for pumped hydro should be 5,556. 3‐20‐15IRPAdvisoryGroupMeetingNotes‐Draft
Page5 of 6 Elizabeth walked us through projected capital costs the various types of resources of Generic Resources by vintage year through 2035. Pumped hydro was the most expensive and Peaker‐Frame was the least. LEVELIZED COSTS: PART 2 Bob Williams, Senior Energy Resource Acquisition Analyst, explained that while in past IRPs PSE has not presented any kind of levelized costs, they can be helpful in that they give an idea of the capacity factor of the wind – is it close enough that we should be concerned. Puget Sound area is on the lower end of the scale for solar potential in the United States:  Utility scale solar has very little presence in Washington with less than 1MW.  PSE’s 0.5 MW solar project at Wild Horse has 18% capacity factor.  In the last RFP PSE was quoted 20% capacity factor for a solar project. Capacity factor has a significant impact on the cost effectiveness of solar projects. Currently solar is not competitive with wind with higher capital costs and lower capacity factor. Note: Bill thinks we may be underestimating the capacity factory for MT and there may be better transmission numbers. WRAP UP / REVIEW ACTION ITEMS We agreed on the meeting topic: Load Forecast for the April 9 IRP AG meeting. The main topic of the May meeting will be the. 3‐20‐15IRPAdvisoryGroupMeetingNotes‐Draft
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