HomeMy WebLinkAbout08/08/2024 - ENERGY BOARD - AGENDA - Regular Meeting
ENERGY BOARD
REGULAR MEETING
August 8, 2024 – 5:30 pm
222 Laporte Ave – Colorado Room
Zoom – See Link Below
1. [5:30] CALL MEETING TO ORDER
2. [5:30] PUBLIC COMMENT
3. [5:35] APPROVAL OF JULY 11, 2024 MINUTES
4. [5:45] PLATTE RIVER’S INTEGRATED RESOURCES PLAN (120 Minutes, Discussion)
Raj Singam Setti, COO of Innovation & Resource Strategy Integration, Platte River Power Authority
Jason Frisbie, GM & CEO, Platte River Power Authority
5. [7:45] BOARD MEMBER REPORTS (5 min.)
6. [7:50] FUTURE AGENDA REVIEW (5 min.)
7. [7:55] ADJOURNMENT
Participation for this Energy Board Meeting will be in person in the Colorado Room at
222 Laporte Ave.
You may also join online via Zoom, using this link: https://fcgov.zoom.us/j/96707441862
Public Attendance & Comment
Members of the public are encouraged to attend either in person or online. Members of the
public attending in person are expected to sign in on the public sign-in sheet. During the “Public
Comment” segment of each meeting, comment will be allowed on matters of interest or
concern to members of the public, including items the Board will consider at that night’s
meeting. Each speaker will only be allowed to speak one time during Public Comment.
Online Public Participation:
The online meeting will be available to join at approximately 5:15 pm, August 8, 2024.
Participants should try to sign in prior to the 5:30 pm meeting start time, if possible. For public
comments, the Chair will ask participants to click the “Raise Hand” button to indicate you would
like to speak at that time. Staff will moderate the Zoom session to ensure all participants have
an opportunity to address the Board or Commission.
To participate:
• Use a laptop, computer, or internet-enabled smartphone. (Using earphones with a
microphone will greatly improve your audio).
• You need to have access to the internet.
• Keep yourself on muted status.
ENERGY BOARD
July 11, 2024 – 5:30 pm
222 Laporte Ave – Colorado Room
ROLL CALL
Board Members Present: Marge Moore, Alan Braslau (remote), Thomas Loran, Frederick Wegert,
Wendell Stainsby, Scott Canonico, Brian Smith
Board Members Absent: Jeremy Giovando, Eric Shenk OTHERS PRESENT
Staff Members Present: Christie Fredrickson, Michael Authier, Yvette Lewis-Molok, Cyril Vidergar
(remote), Katherine Bailey, Travis Walker
Members of the Public: Sue McFaddin
MEETING CALLED TO ORDER
Interim Chairperson Loran called the meeting to order at 5:30 pm.
ANNOUNCEMENTS & AGENDA CHANGES
None.
PUBLIC COMMENT
Sue McFaddin, former Energy Board Member, asked the Board to encourage City Council to stop the
building of Platte River’s planned natural gas turbine. The cost to build the turbine will increase wholesale
costs significantly, and retail rate increase will be unaffordable for many people. She questioned the
baseline capacity actually needed in order to join the regional market and wondered why Platte River is
unable to use its existing combustion turbines and hydropower from WAPA. This project does not align
with any of the goals of the four communities and from a business perspective it does not make sense.
APPROVAL OF MINUTES
In preparation for the meeting, board members submitted amendments via email for the June 13, 2024,
minutes. The minutes were approved as amended.
BUILDING PERFORMANCE STANDARDS UPDATE
Katherine Bailey, Project Manager
Ms. Bailey briefly reviewed what Building Performance Standards (BPS) are for the Board’s new
members and noted that they look very different from one jurisdiction to the next. It needs to be
implementable and achievable for our local community and existing building stock.
At a very high level, staff is looking to recommend covering buildings (both multifamily and commercial)
5,000 square feet and above because buildings in the 5,000-10,000 square foot range have more
attainable targets and timelines. They will be targeting an Energy Use Intensity (EUI) target, so essentially
how much energy is used per square foot; the target is weather-normalized and compared to other like-
buildings (ex. A house of worship will not have the same target as a restaurant).
Ms. Bailey said staff also recognizes the critical need for maximum flexibility, resources, and support.
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There will always be a situation where an exception or flexibility is needed, so there has to be alternate
pathways or offramps built into this program. These can include caps (a limit that a building can achieve
in reductions), renewables, and waivers. Adjustments are a part of most BPS policies and can include
timeline (ex. A supply chain delay), or targets (ex. Historic buildings).
Ms. Bailey said much of the feedback from this Board after her last presentation mirrored the feedback
received from technical committee, which was essentially a building performance standard is a policy
about performance of an existing building and renewables don’t have anything to do with performance.
That said, the goal is to lead with efficiency, but provide a role for renewables. The recommendation from
staff to council is to allow onsite renewables to count toward compliance by providing an EUI credit that
will apply toward the final goal.
Vice Chairperson Moore asked how the targets are determined. Ms. Bailey said staff was able to use a lot
of local data (because we have a municipal utility) as compared to some other jurisdictions, which was
extremely helpful. Additionally, since we don’t have a statutory requirement to meet, staff was able to
build it from the ground up, framed around what is achievable and attainable within the local building. Ms.
Bailey said where buildings are in their current efficiencies on the public facing benchmarking
transparency map.
Board member Wegert asked if there are specific things a building must do to meet the target. Ms. Bailey
said building owners are flexible to meet the efficiency target however they want to, for example a
restaurant owner who was already planning to upgrade their cooking surfaces could switch them out for
high efficiency electric cooktops and that can count toward their EUI target.
Ms. Bailey displayed a chart of buildings by size and their energy reduction targets along with an
estimated upgrade cost (by square foot). In Fort Collins there are 310 buildings in the 5,000-10,000
square foot range, and 200 (65%) of those building owners need to act by 2035. On average, the
reduction to reach their individual targets is 9% and that could cost roughly $4-5.00 per square foot
(before any rebates or tax incentives, etc.).
When considering only energy savings, BPS implementation has a projected benefit of $0.85 for every $1
in cost spent between 2024-2035. When factoring in the avoided social cost of greenhouse gas
emissions, such as health effects, property damage from climate-related natural disasters, and the
disruption of energy systems, the benefit increases to $3.18 for every $1 in cost.
City Council will be reviewing staff’s final recommendations through a memo, and staff is hoping for
program adoption later this summer. The earlier it is adopted will create a longer runway for building
owners. Resources that are developed ahead of implementation will be shared widely with impacted
groups, both to inform and educate, and to seek feedback on the resources offered. Ongoing feedback
will be sought to understand impacts on the community throughout implementation.
Board member Stainsby asked why buildings under 5,000 square feet aren’t included, and asked how
much commercial energy use falls below the 5,000 square foot threshold. Ms. Bailey explained that some
of it has to do with the value for time and energy spent; there are roughly 900 buildings under 5,000
square feet, but their energy use is a fraction of what it is for the larger buildings. The buildings that are
included under BPS (roughly 1,400 total) account for 40% of community wide electricity use and 80% of
commercial and multi-family use.
Vice Chairperson Moore asked how a multi-owner building is treated, such as a condominium building
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that has individual owners by unit rather than a sole building owner. Ms. Bailey said it is measured on the
building footprint, rather than parcel, so in that case it would be the condo association who would be
responsible for ensuring the targets are met.
Board member Wegert inquired about incentives. Ms. Bailey said incentives will be provided, but there
are also a number of funding sources, such as state or Inflation Reduction Act funding, to support
increased building efficiency. Ideally, a staff member will be provided to help building owners find
available money funding (provided through a budget offer).
Ms. Bailey asked the Board if they have suggestions about messaging. Board members suggested
leading with ROI and not social engineering costs. Board members wondered if there are any case
studies, and if so, providing those along with ROI.
In the Spring, the Board drafted a memo in support of BPS, they will refine that draft and bring it current
after tonight’s presentation. Ms. Fredrickson will help them get it signed and sent to City Council before
Monday, July 15.
HOW DOES PLATTE RIVER’S INTEGRATED RESOURCES PLAN
AFFECT THE CITY’S CLIMATE GOALS
Michael Authier, Mechanical Engineer III
Mr. Authier briefly covered some historical highlights around climate, including initial carbon emissions
plans dating back as far as 1999. The current guiding policy, Our Climate Future (OCF), was adopted in
2021 and encompasses previous plans, including the Climate Action Plan, the Energy Policy, and the
Road to Zero Waste Plan. OCF focuses on mitigation, equity, and resilience and aligns with the City’s
Strategic Plan under objective 4.1 (Intensify efforts to meet 2030 climate, energy and 100% renewable
electricity goals that are centered in equity and improve community resilience).
OCF includes 13 community-created outcomes, known as Big Moves. The work of Energy Services
connects to several Big Moves within the OCF plan but is primarily focused on Big Move 6 (Efficient,
Emissions Free Buildings: Everyone lives and works in healthy energy and water efficient buildings which
transition to become emissions free) and Big Move 12 (100% Renewable Electricity: Everyone in the
community receives affordable and reliable 100% renewable electricity, including from local sources).
Within each Big Move there are Next Moves (strategies and tactics), which all ties together to the
overarching goal of creating the carbon neutral, zero waste and 100% renewable electricity future we
desire while improving our community equity and resilience.
With OCF, there are six core energy-related goals: Reduce the Community’s greenhouse gas emissions
inventory to 50% below 2005 by 2026, 80% below 2005 by 2030, and carbon neutral by 2050; between
2021 and 2030, reduce the Community's forecasted electricity use by 20% and natural gas use by 10%;
advance energy code through regular three-year updates, and adoption within one year of new IECC
issuance; maintain existing Utilities distribution reliability metrics; provide the Community 100% renewable
electricity by 2030, with 5% from local sources; support deployment of distributed energy resources to
achieve a bidirectional demand flexibility capacity of 5% of peak loads by 2030.
Other notable and relevant policies are Platte River Power Authority’s 2018 Resource Diversification
Policy (generate 100% noncarbon electricity by 2030, while maintaining existing reliability, financial
sustainability, and environmental responsibility) and the State of Colorado’s 2021 Clean Energy Plan
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(reduce electricity generation greenhouse gas emissions to 80% below 2005 by 2030).
Mr. Authier explained greenhouse gasses are measured in metric tons of carbon dioxide equivalent
(MTCO₂e). This can be inclusive of carbon dioxide, methane, nitrous oxide, hydrofluorocarbons,
perfluorocarbons, sulfur hexafluoride, and nitrogen trifluoride. There are also several protocols (three
primary: Global Protocol for Community-scale GHG Emissions, U.S. Community Protocol, Local
Government Operations Protocol) which provide best practices and comparisons. The reporting for these
protocols is annualized.
There are generally two types of inventories, Sector-Based Inventories (SBI) (aka territorial-based) and
Consumption-Based (CBI). SBI is the most common and is mostly based on local data and geared toward
decision making insights for leadership. Within SBI, Scope 1 is mostly consumption within the city, for
example agriculture and other land use, stationary fuel combustion, waste generated and disposed of
within the city, industrial process and product use, and in-boundary transportation). Scope 2 is electricity
generated outside the city but consumed within the city. Scope 3 is outside the city boundary, such as
transmission distribution, out of boundary transportation, and waste generated inside the city but
disposed of outside the boundary.
CBI includes some of the same things as SBI, but it is labor intensive and more expensive to perform, so
they are not done as frequently. While CBI is not necessarily new, it is an emerging approach based
mostly on national data, providing consumer-focused insights. Fort Collins has looked into this approach
but has not done a CBI; however, Larimer County has completed both an SBI and a CBI.
Fort Collins completes an SBI annually (every year since 2000), following Global Protocols within the
Growth Management Area. This has provided consistent sources and methodologies from 2005 onwards.
There are six resource areas within the community inventory: Industrial Processes and Product Use
(IPPU), Water, Solid Waste, Ground Travel, Natural Gas, and Electricity. Previously this data was
accessible by springtime every year, but there are increasing delays in obtaining certain data sets, so the
2022 Community Inventory is still considered preliminary.
In electricity accounting, individual electrons are not identifiable or traceable; however, energy can be
measured, both at generation and consumption and in between (ex. At substations) by metering.
Accounting heavily relies on metering, financial transactions, and contracts/agreements (PPAs, etc.).
Conceptually, electric grids are somewhat like a water system, in that generators provide power
“pressure” into the system, consumers access power by turning a switch on (“opening a tap”), and
balancing authorities maintain the system “pressure” of 120 volts. Today in Fort Collins, Platte River
serves as the generator role, and the balancing authority is Public Service Company of Colorado.
Platte River was formed in 1973 by the four owner communities (Fort Collins, Loveland, Estes Park, and
Longmont) to provide wholesale electric generation and transmission to the owner communities. They are
governed by an eight-person Board of Directors, composed of two representatives from each community.
Platte River has three distinct, but interconnected relationships with the City of Fort Collins: the City as a
co-owner of the generation authority, the Utility as a partner in operations and planning, and the
Community as a consumer of purchased electricity.
Platte River will buy and sell excess generation regionally. 20% of Platte River’s annual generation is sold
regionally, and roughly 8% of Fort Collins’ annual consumption is from regional purchases. These
regional purchases can’t be traced as renewable- or fossil-based, so to be conservative, the City
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accounts for them as fossil derived energy.
In 2026, Platte River will be joining the Southwest Power Pool (SPP) West, which is an expansion of an
existing Regional Transmission Organization (RTO). The expansion membership is expected to include
Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative,
Municipal Energy Agency of Nebraska, Platte River Power Authority, Tri-State Generation & Transmission
Association, and Western Area Power Administration.
SPP provides its members with marketplace administration, real-time and day ahead resource
scheduling, electric supply and demand balancing, real-time congestion and outage management, and
transmission expansion planning. SPP requires its members maintain credit rating and minimum
capitalization requirements, resource adequacy requirements (be able to provide as much generation as
its local community would need), NERC reliability standards, annual risk management certification, an
energy management system, energy trading risk management system, market operations system, and
automatic dispatch systems, and inter-control center communications protocol (ICCP) compatibility.
Board member Canonico commented that it seems like Fort Collins would have much less influence over
SPP, so how will be certain that our climate goals have be met? Mr. Authier said the way the accounting
will work is actually not that different from what we are doing today. Chairperson Loran added that the
crux of the Board’s question is are the credits operational or electricity accounting that are being used to
reach the 100% goal. To the Board, they mean different things. Mr. Authier said everything is recorded
operationally on the City’s side; however, the goals in the Resource Diversification Policy, the State’s
goals, and the Community’s goals are all different parts of it. While the steps may be slightly different, the
end result is the same from a community inventory perspective.
In the current structure, Platte River generates electricity selling all to its owner communities and
regionally through contracts, with any excess also sold regionally as surplus. Platte River purchases
electricity from regional utilities when needed or financially prudent, and Renewable Energy Credits or
certificates (RECs) are created for all renewable generation; these can be bought or sold, with or
separate from the generation. Fort Collins Utilities’ customers consume electricity from both Platte River
and local sources.
Vice Chairperson Moore asked if Platte River has excess wind generation and they sell it back regionally
or to the market, does that mean they may have to replace that energy later on with coal or another fossil-
based generation. Mr. Authier explained that while working through the resource accounting, he would
pull out all contract sales first, then what is available to the community, what the community is consumed,
and anything beyond that is what is sold. Board members wondered why Platte River would do that when
they also have climate goals, and Mr. Authier agreed that is a good question to review with Platte River
staff next month.
Once in the market, Platte River will generate electricity, selling all generation to SPP and regionally
through contracts. Platte River will set their resource prices and SPP will prioritize which regional
resources run. Platte River purchases electricity from the SPP market for its owner communities
(assumed as fossil), and at least as of today SPP does not track RECs, so they’re unbundled and
retained (for owner communities). If SPP cannot use a renewable resource, it's either stored for later if
possible, or curtailed with no REC created. For 100% renewable electricity, the OCF goal is based on the
community's consumption, while Platte River’s RDP goal is based on its total generation. Efficiency and
local renewables reduce regional purchases, which also reduces reliance on RECs. Grid flexibility aligns
the City’s consumption with local and Platte River renewable generation, going beyond annual
accounting, while minimizing renewable curtailment.
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Mr. Authier pointed out, while the concerns are still valid, as long as Platte River generates more
renewables than electricity the community consumes, Fort Collins could be looking at more RECs than
actual consumption, reaching its own 100% renewable electricity goal, even if Platte River does not.
Efficiency and local renewables reduce regional purchases, which reduces the City’s reliance on RECs,
and grid flexibility allows the community to align consumption with renewable generation and that is what
goes beyond the accounting. It will help minimize curtailment, because if it’s curtailed there are no RECs.
Mr. Walker noted that, while he doesn’t know much about it at this time, he is aware that the natural gas
turbines may have the possibility to convert to hydrogen power in the future. Board member Braslau said
he does not believe the turbines will ever be converted and that it is a marketing justification to soften the
blow of a natural gas turbine, it is not wise to bet on future technology.
Board members thanked Mr. Authier for his time and presentation and expressed how invaluable the
information is for them heading into the discussion with Platte River about their Integrated Resources
Plan (IRP).
REFINE QUESTIONS ABOUT PLATTE RIVER’S IRP
The Board previously drafted a list of questions for Platte River to help them better understand the IRP.
After Mr. Authier’s presentation the Board felt some of the original questions are clearer and would like to
update and refine their questions. The Board will work on the list of questions online over the next two
weeks and the Board Chair will give them a final review before passing them back to staff to provide to
Platte River ahead of the IRP presentation.
BOARD MEMBER REPORTS
None.
FUTURE AGENDA REVIEW
At the Board’s August regular meeting, The Board will hear a presentation from Platte River about their
Integrated Resources Plan. They will also use their Work Session to debrief from the regular meeting,
and possibly draft a positional memo to send to City Council.
ADJOURNMENT
The Energy Board adjourned at 8:40 pm.
2024 Integrated Resource Plan
2024 IRP results
Dr. Masood Ahmad, senior manager, resource planning
IRP introduction
An IRP is a planning process that integrates customer
demand and resources with utility resources to meet a utility’s
future electricity needs as per the policy and guidelines of the
governing body.
In our case, the IRP is a 20-year plan to meet:
Goals of Resource Diversification Policy (RDP)
State Clean Energy Plan
Typical IRP process is repeated every 3-5 years to plan for
industry changes including:
Technological progress
Consumer preferences
Regulatory mandates
The Western Area Power Administration requires us to
prepare an IRP every five years. We have accelerated filing
the IRPs due to our 2030 RDP goals.
Planning process:
Process started in the Fall of 2022.
Engaged nine external consultants from across the country to carry out research and studies.
Developed more than 25 different portfolios to evaluate.
Selected five portfolios and recommended one for implementation.
Community engagement:
36 unique engagement events reaching hundreds of people across our service region.
Three community listening sessions at our headquarters location.
Dedicated IRP microsite with Q&A repository, IRP studies and IRP updates.
Dedicated email address for people to submit questions and from which people received answers and updates.
Public education and media.
Modeling and community engagement recap
IRP challenge
Create a transition plan to retire 431 MW of coal, currently providing over half of the low-cost energy and reliable
capacity. Replace this with low or no-carbon energy and capacity within six years.
Replace more than 2
million MWh of energy
and equivalent
capacity
Focus mostly on energy –
but capacity or reliability is
also critical
Solar Battery
storage
Wind VPP
Grid need: energy,capacity and flexibility
Reliable grid operation requires
energy, capacity and flexibility.
The IRP must plan for all three
attributes.
While wind and solar are excellent
sources of energy, they are not
able to provide capacity and
flexibility.These two vital
attributes must be procured from
other sources for successful grid
operation.
Resource type Energy Power/capacity Flexibility Feasibility for
Platte River
Nuclear √√Limited
Coal √√√
Gas √√√√
Hydro with storage √√√
Wind √√
Solar √√
Storage √√Limited √
Geothermal √√Limited
VPP √√Limited √
Energy – ability to do the work. Push electrons through the wires that do all the work.
Power/capacity – instantaneous energy. Energy at a fixed predictable rate or energy on demand.
Flexibility – Ability to change the power output on demand.
IRP process overview
External Studies
Renewable Resource Costs
Distributed Energy Resources
Load Forecast
Power and Commodity Price Forecast
Extreme weather and Dark calm analysis
Reliability – PRM and Effective Load Carrying Capability (ELCC analysis)
Emerging technologies screening
Dispatchable capacity requirements
All Renewable RFP issued
Research Institute – National Renewable
Energy Lab (NREL) & Electric Power Research Institute (EPRI)
Building electrification
Assess Electric Vehicle (EV) and
Distributed Generation (DG) impacts
Load shapes
Base, high and low scenarios
IRP model peak and energy demand
Portfolio Development Reliability Testing
Objective lowest cost and CO2
Constraint: must
meet Planning Reserve Margin
requirements
Resource portfolio testing with
o Dark Calms
o Extreme weather
o Wind & solar profiles
WAPA Filing
Clean Energy Plan
IRP 2024 Filings
Plexos Model
Model Parameters and
Constraints
Existing Resources
When, how much
and what technology?
Core IRP modeling and evaluation
Renewable intermittency challenges
Summer day supply demand Dark Calm during winter storm Uri, February 2021
Renewable cost challenges
Renewable cost at the time of RDP
Source : Level Ten Q3 PPA Price IndexSource : Lazard LCOE 13
Renewable costs after COVID
Summary of five portfolios
Portfolio
Total resource addition in 20 years, MWs Cost 2030 2035
Solar Wind 4-Hr
Storage LDES Thermal Distributed
Solar
Distributed
Storage
Total
renewable
+ storage
NPV, $
billion
CO2 tons
x000
CO2 tons
x000
No new carbon 600 885 2850 10 0 337 123 4,805 $5.34 126 104
Minimal carbon 600 885 1100 110 80 337 123 3,155 $3.37 127 36
Carbon-imposed cost 550 985 400 160 160 337 123 2,555 $2.78 196 54
Optimal new carbon 600 885 275 160 200 337 123 2,180 $2.77 241 74
Additional new carbon 450 985 175 110 280 337 123 2,380 $2.76 329 98
*All five portfolios include existing combustion turbines at Rawhide
Comparative portfolio costs
Comparative CO2 emissions and % reduction vs. 2005
Board approved portfolio
Consistent with RDP goals, maintains optionality for the future, and equitable access for all citizens
Reliability
Environmental responsibility
Financial sustainability
Flexibility
Proven technology
Future adaptability
Capable of achieving 100%
noncarbon goal when clean fuel
is available
Optimal new carbon is
the board approved portfolio
Transition: generation assets 2018 to 2030
Generation
•Coal is retired
•Noncarbon expands from 24% to 85%
•Natural gas generation less than 10%
•CO2 reduction of 2.75 million tons
Expense
•Platte River's power supply costs increase of about
87% due to general inflation and portfolio remaking
Noncarbon resources and lower carbon emitting natural gas replacing coal
Next steps
•New resource additions: renewables, storage and dispatchable
•Public engagement and education
•Continue planning for just transition at Rawhide
•Distributed Energy Resource integration and Virtual Power Plant implementation
*The IRP is a snapshot in time, but planning is a dynamic process. We will continue to optimize our plans
as conditions change.
Renewables added since 2018
352 GWh 2.7X 4.2X
Responses to Energy Board’s questions
•PPA versus ownership of renewable resources
•Resource adequacy, dispatchable capacity and reliability
•Market operations
•Price volatility
•Financial viability and longevity of dispatchable capacity
•Green hydrogen
DER integration and VPP
implementation
Paul Davis, manager, distributed energy resources
Distributed energy resource (DER) integration
Energy efficiency
Save energy and
save money by
using energy more
efficiently
Electrification
Reduce green-
house gases by
replacing fossil
fuel use with
increasingly
decarbonized
electricity
Distributed
generation
On site
noncarbon
generation
Solar generation
Demandresponse Distributedenergy storage
Shift energy to align electric use to
renewable availability and to
decarbonize the electric system in
a cost effective and reliable manner
Electric vehicles, batteries and
traditional demand response
Flexible DER as part of a VPP
Virtual power plant (VPP)
Dispatchable capacity for Platte River and the owner communities
Based on integrated flexible DERs
•Customer DERs
•Utility DERs
Dispatchable capacity that can provide electric system benefits
•Reliability (power supply and delivery)
•Managing costs of DER integration
•Making better use of intermittent, noncarbon generation
Operated through advanced technologies
•Communication, monitoring and control
•Analytics and optimization
•Data engineering and management
•Dispatchable resource
•Resource adequacy
•Energy value
•Ancillary services (operating
and regulating reserves)
•Distribution system capacity /
reliability
VPP benefits and challenges
•Achieving a VPP that is visible,
measurable, predictable and
responsive in near real time
•Value stacking vs. mutually
exclusive benefits
•Coordination among:
•Owner communities
•Platte River
•“VPP ecosystem…”
VPP benefits VPP challenges
DER aggregators
Enable flexible DER
enrollment, registration,
communication and control to
DERs (e.g., AutoGrid, Voltus,
Tesla, Google Nest)
VPP
ecosystem
Customers
Provide the VPP assets
(flexible DERs like EVs,
storage, smart thermostats)
Local service providers
Retailers, contractors, consultants
involved in sale or implementation
of DERs (e.g., electricians, HVAC
installers, energy auditors)
DER original equipment
manufacturers (OEMs)
Make flexible DERs, provide
flexibility parameters,
communication and control to
DERs (e.g., Tesla,
Chargepoint, Google Nest)
Platte River Power Authority
and owner communities
VPP capacity from customer DERs
Platte River and owner community role
Invest in new systems
DER management systems (DERMS)
Advanced distribution management systems
Data management systems
Invest in VPP programs
Customer engagement and support
Incentives for participation
Operate the VPP to achieve system benefits
Customer role
Adopt DERs like electric vehicles (EVs), storage, and
smart devices
Enroll and participate in the VPP
50,000 DERs to provide 32 MW in 2030
Additional DERs in VPP (not shown in graph)
Customer solar (155 MW in 2030)
Distribution scale storage (20 MW in 2027)
Efficiency Works is a regional utility
collaboration that provides guidance and
resources to enable customers to use
energy effectively, work toward a
noncarbon energy future and build strong,
resilient communities for customers served
by Platte River Power Authority and its
owner communities of Estes Park, Fort
Collins, Longmont and Loveland.
Energy advising
Product information and education
Facility and home assessments
Targeted incentives
Income qualified programs
Electrification and efficiency (EVs and buildings)
Enrollment in virtual power plant (VPP) programs
Providing distributed energy solutions:
Next steps for DER and VPP development
Continue collaboration with owner communities
Complete vendor selection and contracting for DERMS and VPP
Build DERMS infrastructure and initiate VPP programs
Q&A
QUESTIONS ABOUT PLATTE RIVER’S IRP
GENERATION QUESTIONS
1. Platte River obtains wind and solar generation through PPAs, yet thermal generation assets
are owned. Can you please explain why one asset class is owned and the other asset class
is purchased? How do ratepayers take advantage of the low to no marginal cost of
renewable energy power generation when using PPAs?
2. What percent of the time is Platte River planning on running thermal assets?
a. A single annual 100-hour dark calm period represents 1.15% of the available hours
in a year. For the other 98.85% of the time, could PRPA provide this generation by
extending the capacity of our existing natural gas peakers. Could they be used
except as “insurance policy” during dark calm events? This would require a much,
much smaller capital investment. Ancillary services can be provided by battery
systems, for example to cover the slower ramp-up time of these peakers as well as
for frequency stabilization.
3. How is Platte River planning on utilizing the planned battery storage assets? Will battery
storage assets be centralized or distributed? Will the batteries be used to smooth out
demand / supply imbalances? Will batteries provide auxiliary services? Will they provide
back up in the case of an outage? Or provide power during less than 100-hour dark calm
periods such as overnight? How many hours of dark calm energy supply is Platte River
planning to fulfill using battery storage?
4. Can debt of a new combined cycle aeroderived natural gas turbines be serviced by without
selling (exporting) natural gas power generation? Does the IRP model rely on exporting
fossil fuel production in order to be to be financially sustainable? Does exporting natural
gas power generation support the 2018 Resource Diversification Policy calling for the
pursuit of a 100% noncarbon energy mix by 2030?
5. When wind, solar generation, and hydroelectric resources are insufficient to meet FCU’s
load, and when renewable generated electricity coming from other regions is not available
on the market, power will be provided using “dispatchable” (fossil fuel) resources. Is this
compatible with our community’s goal of 100% renewable electricity other than through
using Renewable Energy Credits? The REC approach of claiming annualized overproduction
of wind and solar energy is not what the community has been asking for.
6. With a very large overcapacity in wind and solar generation, the cost and low efficiency of
hydrogen electrolysis becomes irrelevant. Why not use this to produce hydrogen in a very
scalable and distributed fashion including scalable and distributed hydrogen storage, and
then operate scalable and distributed hydrogen fuel cells to fill the gaps of wind and solar
production handling load?
7. How can Platte River and Fort Collins Utility work together to increase the installation of
distributed renewable energy resources in Fort Collins to increase reliability, energy
independence, and control rising costs of electricity?
8. When will “dispatchable” generation be dispatched? Is that only in times of peak demand,
when demand cannot be met without NG generation? Or will it be dispatched when prices
QUESTIONS ABOUT PLATTE RIVER’S IRP
reach certain thresholds, regardless of Platte River demand situation? If the latter, what
does that additional revenue mean for Platte River rate payers?
MARKET QUESTIONS
1. Will FCU pay a constant electricity price from the market through Platte River or will FCU
buy electricity from Platte River at market price?
2. What controls are in place to keep prices from rising thousands of percents during a storm,
or other shortage, like they did in Texas?
3. How do we best align rate schemes such as our current time of day rate to correspond to
market prices?
4. What is Platte River plan if electrical prices go negative? Do we need to have a plan to put
the electricity use somewhere else?
5. What is Platte River’s plan if they cannot sell their generated electricity because the price is
too high? (higher than other generators)
6. Since electricity flows like water, what process / financial incentives exist to help ensure
that Fort Collins buys the least amount possible of non-carbon generated electricity from
the market? How much of the power we buy is “dirty,” how do we avoid buying “dirty”
power?
7. Electrical generation has very high fixed costs and little to no variable costs for renewable
energy. At a high level, how is Platte River planning on pricing their carbon and non-carbon
generated electricity so that it is competitive in the market and yet still recoups fixed costs
8. What is the decision-making process for selling & buying carbon versus non-carbon
generated electricity to the market when both are available?
9. Please help us better understand “Resource Adequacy” in the context of Platte River in the
market structure, as well as the market’s resource adequacy requirements