Loading...
HomeMy WebLinkAboutEnergy Board - Minutes - 06/09/2022 ENERGY BOARD June 9, 2022 – 5:30 pm 222 Laporte Ave – Colorado Room ROLL CALL Board Members Present: Alan Braslau, Steve Tenbrink, Dan Gould (remote), Sidra Aghababian, Marge Moore (remote), Emilio Ramirez (remote), Jeremy Giovando (remote), John Fassler, Bill Becker Board Members Absent: OTHERS PRESENT Staff Members Present: Christie Fredrickson, Adam Bromley, John Phelan, Michael Authier, Rhonda Gatzke, Kendall Minor, Cyril Vidergar (remote), Leland Keller (remote), Adelle McDaniel (remote) Steve Roalstad (PRPA, remote), Shelley Nywall (PRPA, remote) Members of the Public: Julie (remote) Joe Huyett (remote) MEETING CALLED TO ORDER Chairperson Tenbrink called the meeting to order at 5:32 pm. ANNOUNCEMENTS & AGENDA CHANGES None. PUBLIC COMMENT None. APPROVAL OF MINUTES In preparation for the meeting, board members submitted amendments via email for the May 12, 2022, minutes. The minutes were approved as amended. STAFF REPORTS PLATTE RIVER 2022 RESOURCE PLAN UPDATES John Phelan, Energy Services Manager & Energy Policy Advisor Resource planning is a continuous and dynamic process at Platte River. As part of this ongoing effort, Platte River develops an Integrated Resource Plan (IRP) together with the four owner communities. The Integrated Resource Plan (IRP) is a critical tool for establishing a near-term action plan and long-term trajectory that will ensure an adequate supply of reliable, financially sustainable and environmentally responsible electricity. To meet their Resource Diversification Policy (RDP), Platte River will be accelerating the deployment of additional wind and solar, as well as dispatchable capacity between 2024-2028. Most of the new generation was previously planned to come online closer to 2029 or 2030. This will create rate pressure in 2028 due to increased production expenses, inflationary pressure, and the cost of operating more generation resources. To support rate smoothing strategies and due to ENERGY BOARD REGULAR MEETING substantial uncertainty in pursuit of the resource diversification policy goal, financial projections over the planning horizon include minimum annual 2% rate increases post-2028 Board member Moore wondered how this will affect the consumer’s rates. Mr. Phelan said it is too early to say, and he would not venture a guess at this point. Mr. Bromley added staff would not do that level of planning until there is more information available. Chairperson Tenbrink wondered where does the strategy for excess power comes from. Mr. Phelan said presumably within this timeframe Platte River will be joining a regional market. Board member Braslau asked to clarify that by new dispatchable resources, PRPA means RICE or other natural gas burning generation capacity. Mr. Phelan said yes, perhaps new combustion turbines as the precise technological choices have not been made. SOLAR 120% RULE AND COMPENSATION John Phelan, Energy Services Manager & Energy Policy Advisor The Strategic alignment of solar sizing aligns with Our Climate Future under Big Move 12, which outlines a target of 5% local renewable electricity. It also aligns with the City Strategic Plan, which plans to “intensify efforts to meet 2030 climate, energy and 100% renewable electricity goals that are centered in equity and improve community resilience” (4.1). The goal is to reach scaled-up solar and Distributed Energy Resource (DER) adoption, and sustainable utilities funding for customer service, distribution system operations, and infrastructure needs. Staff will be approaching City Council with the following questions: Does Council support replacing the 120% solar sizing limit in code with administrative policies that support customer solar goals and align with Our Climate Future targets? Does Council support continued gradual transition of solar rates that balance maintaining solar value and limit negative equity impacts? What other feedback does Council have regarding local solar? Fort Collins has four types of solar installations: Residential (17.6 MW, 2,770 systems), Commercial/Institutional (4.3 MW, 89 systems), Riverside Community Solar (.6 MW), and the Solar Power Purchase Program (4.9 MW, 16 systems). The focus tonight will primarily be on the residential portion, and touch on the Commercial portion. At the residence, solar is measured at a single advanced bi-directional meter. Every 15 minutes, there is a measurement of how much is consumed by the house and exported by the solar. A time of day value is then applied to each 15 minute period, and at the end of the month it is resolved into dollars and applied either as an account charge or credit. On average, approximately 50% of solar electricity is self- consumed and 50% is exported to the distribution system. All self-consumed electricity is valued with the full retail rate. Mr. Phelan advised it may be easier to think of this process as net-billing rather than net- metering. Board members expressed confusion about the billing component of 50% consumption and 50% exported. Mr. Phelan explained that of the solar energy that’s produced, approximately 50% of it is self- consumed in the house at the time it’s produced. Board member Braslau asked to clarify why our billing methodology is considered net-billing rather than net metering. Mr. Phelan explained it is because every 15-minute period is resolved into dollars, not energy use. Traditional net metering is a bank of kilowatt hours that rolls over from month to month and ENERGY BOARD REGULAR MEETING resolved on an annual basis. The commercial billing structure is similar to the residential net billing structure with a very low (old) export value. Riverside Community Solar’s system production is valued at project-specific time of day rates and apportioned to customers based on their ownership percentage. In the Solar Power Purchase Program each system has a power purchase agreement, and the electricity is allocated partially to Green Energy program subscribers and partially to all customers. There has been dramatic growth in system installation since 2005, and it is expected to continue to grow at a rapid rate. The 120% rule limits the size of a solar system to produce no more than 120% of a customer’s historical use. The purpose of the 120% rule was to allow customers to offset their electric bill with retail net metering rates. The intent was a financial limit and not related to distribution system requirements. The rule is currently defined in Fort Collins municipal code and was aligned with state statute until last year. The rule is applied only at the time of solar system interconnection application, and it is not tracked or calculated for subsequent homeowners. The Utility’s costs are broken into variable and fixed costs. Variable costs make up 63% of total costs, this cost includes purchased electricity from Platte River. 37% were fixed costs (independent of how much electricity is used within the community) for customer service, operations, maintenance, and asset management. All customers use the system and these services (both solar and non-solar customers). The residential electric rate is composed of a base charge and consumption rates, which include recovery of both fixed and variable costs. The fixed portion of the consumption rate is called the Distribution Facilities Charge (DFC). There is an equity issue for non-solar customers in that exported solar electricity is purchased at near retail and then sold to other customers at retail. The difference between these values does not cover the DFC and represents unrecovered fixed costs paid for by non-solar customers. Mr. Phelan explained a few reasons why the Utility may consider removing the 120% rule. Removing it might encourage solar systems that serve increased use from electrification (e.g., electric vehicles, heat pumps). Larger systems also contribute to reaching community renewable electricity goals (anticipating 60-75 megawatts of solar (2.5x) and 5000-7000 solar systems by 2030). Removing the rule also assists in streamlining administrative work for customers, solar trade allies, and staff. It is also structured around a rate structure that the utility no longer uses. Mr. Phelan explained how the Utility might resolve the DFC deficit (0.2%). The DFC component adds about 40 cents per month to non-solar residential customers. Without changes, the non-solar customer impact will scale up to about $1.00 per month by 2030. Staff recommends removing the 120% rule from code, which would align with the City’s electrification goals and streamline the administrative process. There is clear community support behind this specific recommendation. Additionally, staff recommends gradually increasing the differential between retail consumption rate and solar credit rate, which would reduce the cost impact to non-solar customers. Removing the time of day tier charge would also encourage electrification while balancing solar, electrification, and rate equity objectives. Finally, staff recommends aligning the commercial solar credit rate with similar logic. Longer term, the Utility can consider new solar business models with Platte River. Mr. Phelan noted that the time of day recommendation is ultimately going to be a larger conversation, but it does directly affect the conversation around solar and electrification and is often seen as a conflicting policy goal (solar sizing and rates versus electrification). In isolation, none of these things solve the problem and the solar industry recognizes the challenges. That ENERGY BOARD REGULAR MEETING said, Fort Collins has one of the highest solar adoption rates in the state, so the current set up is not driving contractors or customers away. Mr. Keller added that staff has spoken with their solar contractor network, and they were largely supportive of that. Mr. Phelan said that from a practical standpoint, they met set a system KW threshold and say anything below that size will not be questioned; however, if a customer would like something larger it would prompt staff to ask more questions. Staff also wondered if the Utility has an obligation in consumer protection (ex: protecting customers from contractors who want to oversize a system on a residential home), and they hope that a new administrative structure would help mitigate the worst. Board member Fassler wondered if staff might be trying to prevent a problem that isn’t likely to happen because most roofs don’t have the space to oversize a system. Mr. Minor said it isn’t impossible but probably not extremely common. Vice Chairperson Becker said this proposal is about solar rate reform, and not specific only to the 120% rule, he noted that they are all connected and changing one rule will affect another. Board member Braslau said he would suggest making it clear that the solar residential rate is not intended for the customer to be in the business of making money from their production. Mr. Phelan responded that increasing solar production is in alignment with our goals. Vice Chairperson Becker added that many customers will want to make sure adding solar is a reasonable investment, it’s often not altruistic. Board member Ramirez suggested creating a backup slide describing the 50% export model in case the same confusion also comes up at City Council. Board member Braslau said the simplification of net metering (or net billing) was designed to keep financials safe, but now we can do something that is more adapted to a greater penetration; it is time to be a little more sophisticated. 2021 ANNUAL ENERGY RESULTS Michael Authier, Senior Energy Services Engineer John Phelan, Energy Services Manager & Energy Policy Advisor Historically, Energy Services staff have reported on Energy Policy progress, and Energy Services’ program portfolio results. With the Energy Policy now being integrated into the Our Climate Future (OCF) plan, and ongoing OCF annual reporting still being developed, Energy Services presented on overall community energy (electricity, natural gas, & petroleum) consumption, related emissions, and Energy Services’ program portfolio results. In 2021, the City adopted the Our Climate Future (OCF) plan, which Energy Services’ staff use as a guiding document, and is focused on mitigation, equity, and resilience. As a refresher, some of the main energy-related goals in OCF are reduce 20% of forecasted electricity consumption, reduce 10% of forecasted natural gas consumption, 100% renewable electricity (with 5% local), zero carbon new construction, maintain current Utilities distribution reliability metrics, and achieve a demand flexibility capacity of 5% of peak loads. There are 13 identified Big Moves in OCF, and although Energy Services touches multiple Big Moves, they are specifically focused on Big Moves 6 and 12 (Efficient, emissions free buildings, and 100% renewable electricity, respectively). 2020 saw reduced energy consumption and overall carbon emissions, driven primarily by COVID-19 ENERGY BOARD REGULAR MEETING (electric and transportation), and a few months of new renewable electricity generation from Roundhouse wind. 2021 saw consumption generally back to pre-pandemic levels, though vehicle miles traveled (VMT) were still down in the first part of the year. For overall emissions in 2021, this increased consumption was countered by receiving the full 12 months of renewable generation from the Roundhouse wind project, resulting in overall emission remaining mostly in line with 2020. This 2021 emission data does, however, still include some preliminary data and will likely change somewhat in the coming months. Energy related emissions in 2021 accounted for 90% of the overall inventory emissions. Of this, electricity was the largest contributor (40% of overall emissions), but has also seen the most (22%) reduction from 2005. Based on current data, staff estimate that by 2030, natural gas and petroleum will comprise 85% of the carbon inventory, and electricity will drop down to 10%, further pushing the discussion around electrification. These forecasts are based on historic data and trends, representing a baseline “do nothing more” scenario, so intentionally do not include estimates around potential electrification other than what’s already included in historic & current data. This allows Big/Next Moves to be calculated and eventually included with this forecast, to call out and show progress/potential by Move(s). Energy consumption has increased since 2005, and is forecasted to continue to grow through 2030, though electricity consumption growth specifically has slowed significantly in recent years. This increased consumption across the board has been primarily driven by community population growth, and although overall consumption is still increasing, it has been consistently decreasing per capita for all three energy resources (electricity, natural gas, & petroleum). Energy Services’ program portfolio added 44,170 MWh of first year customer electricity savings in 2021, which was 3% of retail electricity consumption. Additionally, local distributed renewable generation accounted for 2.3% of all retail electricity consumption. 2021 program portfolio highlights included the adoption and start of implementation for Our Climate Future, 2020 Building Codes adoption, and completion of a framework for electrification benefit cost analysis. Platte River also created a DER strategy in partnership with the four owner communities. Energy Services’ programs continue to evolve and 2021 had several successful programs and pilots, including a new Grid interactive water heater pilot with 88 units installed inside affordable housing, a former pilot for residential batteries being launched as a program to include 70 installed units (across 53 projects), the Building Energy and Water Scoring program being expanded to include commercial and multifamily buildings over 10,000 square feet (480 buildings), and the Efficiency Works Business program, one of the longest running programs, being expanded to go beyond LED lighting with a revamp of building tune-ups and addition of remote retro commissioning. Mr. Minor asked the Board to hypothetically consider what would be a good replacement for hydropower in drought conditions. Board members discussed the pros and cons of nuclear power, batteries, hydrogen storage, and natural gas. They also discussed further efficiency efforts as well as rate structure changes to balance low usage, low carbon emissions, high reliability, while maintaining a level of affordability. BUDGETING FOR OUTCOMES UPDATE Adam Bromley, Interim Deputy Director, Utilities Light & Power Staff are currently working in the BFO Teams Round 2, which is where the teams rank and prioritize ENERGY BOARD REGULAR MEETING offers, and set a recommended funding line (above and below). Once the funding line is set, Mr. Bromley hopes the Board will be able to advocate for any offers that are important to them (whether they are currently funded or not). Mr. Bromley said staff expects core operations offers to be funded, but there are several enhancement offers. He pointed out several offers: 1.7 (grid flexibility communications), 2.20 (two full time electrical engineers), 2.21 (full time lead systems analyst), 1.9 (direct install demand response thermostat replacement), and 2.16 (ADMS Enhancements & Utility Network Integration), which are all very closely linked to each other for grid-flexible communication. BOARD MEMBER REPORTS Board member Gould said the Board may need more specific information about the reduction in hydropower. It would be nice to know what WAPA is doing; what specific restrictions or guidance are they giving. He also thinks it would be good to discuss what the possibility for nuclear capacity is and how it could affect the market. FUTURE AGENDA REVIEW The July Energy Board meeting will have a mid-year financial update from Lance Smith, as well as an update on the Drake Transmission line from Platte River. The June work session will cover the Utilities Affordability Program and the Board will have a chance to meet the new program director, Shannon Ash. ADJOURNMENT The Energy Board adjourned at 8:31 pm.