HomeMy WebLinkAbout08/10/2023 - Energy Board - Agenda - Regular Meeting
ENERGY BOARD
REGULAR MEETING
August 10, 2023 – 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 13, 2023 MINUTES
4. [5:40] PLATTE RIVER INTEGRATED RESOURCES PLAN (Discussion, 75 Min.)
Javier Camacho, Platte River Power Authority
Masood Ahmad, Platte River Power Authority
5. [6:55] CAPITAL IMPROVEMENT DEBT ISSUANCE (Decision, 30 Min.)
Lance Smith, Director, Financial Planning & Assets, Utilities
6. [7:25] OUR CLIMATE FUTURE METRICS DASHBOARD UPDATE (Discussion, 30 Min.)
John Phelan, Energy Services Manager & Energy Policy Advisor
7. [7:55] BOARD MEMBER REPORTS (5 min.)
8. [8:00] FUTURE AGENDA REVIEW (5 min.)
9. [8:05] 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
Online Public Participation:
The meeting will be available to join beginning at 5:15 pm, August 10, 2023. 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 13, 2023 – 5:30 pm
222 Laporte Ave – Colorado Room
ROLL CALL
Board Members Present: Bill Althouse, Thomas Loran, Marge Moore, Bill Becker, Alan Braslau
(remote), Steve Tenbrink
Board Members Absent: Jeremy Giovando, Vanessa Paul, Brian Smith
OTHERS PRESENT
Staff Members Present: Christie Fredrickson, Phillip Amaya, John Phelan, Brian Tholl, Lance Smith,
Poorva Bedge (remote), Rhonda Gatzke, Councilmember Canonico, Kendall Minor, Cyril Vidergar
Members of the Public: Kevin Stearns
MEETING CALLED TO ORDER
Chairperson Tenbrink called the meeting to order at 5:30 pm.
ANNOUNCEMENTS & AGENDA CHANGES
None.
PUBLIC COMMENT
None.
APPROVAL OF MINUTES
In preparation for the meeting, board members submitted amendments via email for the June 8, 2023,
minutes. The minutes were approved as amended.
PACKET ITEM Q&A
Board members commented on reliability during severe weather events. Mr. Amaya said reliability is still
very strong, but there were two transformers (modified overheads that were not meant to be underground
but were installed out of necessity) that flooded and were pumped after this year’s record-setting rainfall.
Board members asked for clarification on some of the financial updates within Mr. Smith’s slides included
in the Board’s meeting packet. Mr. Smith explained the internal services fund supports general utility
things for all four utility services, there is a monthly transfer into that fund and at the end of the year the
budget will be reconciled based on what was spent throughout the year.
Mr. Phelan announced that the Utility was awarded the grant for their Zero Carbon Performance Code
Implementation under the Resilient and Efficient Codes Implementation of the IIJA (Infrastructure
Investment and Jobs Act).
SECOND APPROPRIATION OF FUNDS FOR A MODERN CUSTOMER
INFORMATION AND BILLING SYSTEM
Lance Smith, Director, Financial Planning & Assets, Utilities
ENERGY BOARD
REGULAR MEETING
Mr. Smith recapped what the Customer Information System (CIS) is and the purpose of the funding
request. The CIS is a modern customer self-service portal and billing system on a hosted platform. The
Utility is replacing its current 22-year-old billing system, which is essential to providing Fort Collins Utilities
customers the best and safest best customer experience to interact with their community owned utility.
The priority is to provide accurate billing, convenient billing solutions, and comprehensive real time data
that enhances our customer's understanding of how they use energy and water and how much they
cost. The project is expected to take two years to implement, beginning October of 2023, and cost a total
of about $14 million to implement, plus an ongoing annual subscription fee of $1.25 million per year.
Staff previously came to the Energy Board to request an initial funding appropriation of $4.25 million to
kick off project management, quality assurance, contract review, and contractual staffing. The Board
supported this request and understood there would be an additional funding request later in 2023 once
the solution provider was selected. Tonight, staff is seeking support for an additional $9.7 million in
funding to support Software as a Service (SaaS), software licensing, organizational change management,
testing protocol development and management, training development and initial training, and business
process analysis and alignment.
Board member Althouse said he was disappointed that the distributed energy resources management
system (DERMS) won’t be collecting data for rate base data. Mr. Phelan said that our current billing
system has integrations, and there are planned integrations between the new DERMS and the new billing
system. The billing system calculates the values, dollars, and cents, and the DERMS has data and two-
way communications with all devices. The calculations reside in the billing system, as they should.
Board member Becker asked if there will be money saved by not dedicating resources to the old system?
Mr. Smith said there are some resources being saved, but the subscription fees are higher than the
current maintenance cost of the existing system (approximately $700,000 annually).
Board member Moore moved the Energy Board support bringing an appropriation ordinance
forward for the consideration of the full City Council to support the licensing and full
implementation of the modernization of the Utilities Customer Information System – Customer
Self Service Portal.
Board member Becker seconded the motion.
Discussion:
Board member Loran said it is very important to have a flexible system that is adaptable to support
modernization. Board member Moore agreed and said it would be in the best interest of the software
company to be adaptable. Board member Althouse noted that IOUs are so streamlined and advanced in
this area and it would be wise to follow their lead.
Board member Braslau commented that the Utility has little choice, following the failure of the previous
billing modernization project, as the Utility cannot continue with the current system.
Vote on the motion: It passed unanimously 6-0, with 3 absent.
VICE CHAIRPERSON ELECTION
Chairperson Tenbrink nominated Board member Paul as the Energy Board Vice Chairperson. Board
members Loran, Althouse, and Braslau all advised they had also planned to nominate Board member
Paul.
Board member Paul advised via email ahead of the meeting that she would consent to the nomination, if
ENERGY BOARD
REGULAR MEETING
she were to be nominated. There are no further nominations. Nominations are now closed.
Chairperson Tenbrink moved to select Board member Tenbrink as the Energy Board Vice
Chairperson.
Board member Althouse seconded the motion.
Discussion:
None.
Vote on the motion: It passed unanimously 6-0, with 3 absent.
ENERGY BOARD OBJECTIVES
Chairperson Tenbrink reviewed the Board’s codified duties with the Board and briefly highlighted the
Board’s goals from their 2023 Work Plan.
Board member Loran said he thinks each presentation should begin with a red/yellow/green dashboard
visually showing how the City is meeting its climate goals, even if some of them aren’t updated every
single month. Board member Moore added she thinks staff are not as disconnected among themselves
as they may appear to the Board, but the Board can ask staff to help draw the connections more clearly.
Mr. Phelan said it’s important to point out that the 80% reduction goal has many components but the
piece that is critical is petroleum and natural gas, and there isn’t a separate goal in how much we have to
save in petroleum and natural gas to meet the community wide goal. There is some additional work that
would be needed to refine that goal. Board member Loran agreed and said he hopes there can be
second and third level goals to keep us forward looking, not backward.
Board member Althouse said he feels as though he cannot get many items from the Board’s work plan on
the Board’s agendas. He wants to know why the Board isn’t pushing harder to work to lower rates when
other utility companies are adding 100% local distributed resources which are driving rates down. He
noted a listed qualification to sit on this board is to be a visionary and innovative thinker and he doesn’t
feel like the Board is being visionary or innovative. Chairperson Tenbrink said he does not agree,
lowering rates is not the primary purpose of this board.
Mr. Minor added coming from a larger utility he thinks that a lot of things Fort Collins Utilities is doing from
an energy perspective are working toward the same greater goal as other utilities. Board member
Althouse said that there are loans available to utilities to help drive these goals. Board member Loran
said as a prosumer himself, Fort Collins Utilities rates are too low, some of the lowest in the country, for it
to profitable for him to join a Virtual Power Plant. There is no incentive to share his resources, so he
doesn’t see it as lowering rates.
Mr. Phelan said two things can be true, there is a lot more that the City could be doing with distributed
assets as a municipal utility; however, there are numbers on the gross solar capacity that is possible in
Fort Collins. With realistic numbers applied, it comes down to about 10%-15% of electricity use. The
solution lies within Platte River and distributed resources; it’s not an or. According to COSA (Colorado
Solar and Storage Association) Fort Collins has the highest density of solar anywhere in the state, but
that doesn’t mean we can’t double or triple it.
Mr. Vidergar advised this Board is not a policy driving or drafting, a rate setting, or a jurisdictional board.
Mr. Loran has provided great constructive plan for positive discussion within the confines of the Board.
The Energy Board is a body that City Council has empowered, but this board has always been an
ENERGY BOARD
REGULAR MEETING
advisory board and a resource group of subject matter experts. The function of the Board is not to come
up with a whole new set of priorities, but to vet the policy proposals within the set of priorities City Council
has set and to vet the policy proposals and evaluate the potential impact to customers and the
community, unless Council directs the Board otherwise.
Councilmember Canonico added that the Council Ad Hoc Committee for Boards and Commissions has
been working on more clarification of the role of Boards and Commissions, Staff Liaisons, Council
Liaisons. She noted that Council Liaisons are not supposed to direct the work of the Board, but more to
act as the voice of the Board back to the larger sitting Council.
BOARD MEMBER REPORTS
None.
FUTURE AGENDA REVIEW
Platte River will be here for the August meeting to present and discuss the IRP. Mr. Phelan will also try to
have something prepared for an Our Climate Future metric dashboard. Mr. Smith will be discussing a
debt issuance that is intended to fund capital improvements over the next three years for both Light &
Power and Connexion.
ADJOURNMENT
The Energy Board adjourned at 8:03 pm.
Resource planning update
Stay engaged
Stay informed
•prpa.org/2024irp
Submit additional questions and request community presentations
•2024irp@prpa.org
Agenda
•About Platte River Power Authority | Javier Camacho
•2024 Integrated Resource Plan process and timeline | Masood Ahmad
•Distributed energy resources planning and integration | Paul Davis
Regional identity and philosophy
About Platte River Power Authority
Platte River Power Authority is a not-for-profit, community-owned public power utility
that generates and delivers safe, reliable, environmentally responsible and financially
sustainable energy and services to Estes Park, Fort Collins, Longmont and Loveland,
Colorado, for delivery to their utility customers.
At a glance
Headquarters
Fort Collins, Colorado
General manager/CEO
Jason Frisbie
2023 projected deliveries of
energy to owner communities
3,301,376 MWh (~33% renewable)
Employees
297
Peak demand
707 MW on July 28, 2021
2023 projected deliveries of energy
5,174,234 MWh
Began operations
1973
Transmission system
Equipment in 27 substations, 263 miles of
wholly owned and operated high-voltage lines
and 522 miles of high-voltage lines jointly
owned with other utilities.
Foundational pillars
Platte River is committed to decarbonizing our resource portfolio without
compromising our three pillars:
•Reliability
•Environmental responsibility
•Financial sustainability
Resource Diversification Policy
Purpose
To provide guidance for resource planning, portfolio
diversification and carbon reduction.
Goal
To support owner community clean energy goals, we will
proactively work towards a 100% noncarbon resource mix by
2030 while maintaining our foundational pillars of providing
reliable, environmentally responsible and financially
sustainable energy and services.
Passed by Platte River’s Board of Directors in 2018
\
•Transmission and distribution infrastructure
investment must be increased
•Transmission and distribution delivery systems
must be more fully integrated
•Improved distributed generation resource
performance
•Technology and capabilities of grid management
systems must advance and improve
•Advanced capabilities and use of active end user
management systems
•Generation, transmission and distribution rate
structures must facilitate systems integration
•Battery storage performance must mature and
the costs must decline
•Utilization of storage solutions to include thermal,
heat, water and end user available storage
•An organized regional market must exist with
Platte River as an active participant
Accomplished
In progress
Awaiting technology
Progress since 2018
The 2024 IRP builds on the 2020
IRP and resource planning and
modeling that occurred in 2021
and 2022
•225 MW of Roundhouse wind
•Announcement to retire coal resources
•Developed a distributed energy resources strategy
•Filed 2020 IRP
•22 MW Rawhide Prairie Solar with 2 MWh battery
•150 MW Black Hollow Solar power purchase
agreement
•Additional solar and anergy storage RFPs
•Filed Clean Energy Plan with the state of Colorado,
which requires all electric utilities to achieve 80%
carbon reduction by 2030
•Entry into Southwest Power Pool Western Energy
Imbalance Service market
33.3% noncarbon resources
2023 budget system total2018 system total
61.8%15.0%
11.8%
8.2%
1.6%1.6%
Coal Wind Hydropower Solar Other purchases Natural gas
56.8%
22.7%
8.4%
7.4%
2.5%2.2%
Includes renewable energy credit
allocations to carbon resources
Due to drought conditions, not all
hydropower may be considered
noncarbon
24.8% noncarbon resources
33.3% noncarbon resources
2023 budget system total 2030 projected system total
88.4% noncarbon resources
Renewable resources Dispatchable resources (includes purchases)
Includes renewable energy credit
allocations to carbon resources
Due to drought conditions, not all
hydropower may be considered
noncarbon
33.3%
66.7%
88.4%
11.6%
Timeline
June July Aug Sept Oct Nov Dec Jan Feb Mar April May June
Community
engagement
Resource
planning
Ongoing public engagement in collaboration with owner communities
Listening
session
Listening
session
Listening
session
IRP modeling
Portfolio development
Review results
Board
presentation
IRP document
development
Reliability assessment
with renewables and DER
integration
•Pre-IRP studies
•Load forecasting
•Other inputs, assumptions
2024 Integrated Resource Plan
Masood Ahmad, resource planning manager
What is an IRP
•IRP is a planning process which integrates customer demand and distributed energy
resources (DERs) with utility resources to provide reliable, economical and environmentally
desirable electricity to customers
•Typically developed for the next 10-20 years and updated every few years
•IRP assists with preparing for industry changes including:
•Technological progress
•Consumer preferences
•Regulatory mandates
•Required by Western Area Power Administration (WAPA) every five years
•WAPA requires a short-term action plan and an annual follow up on plan execution
•Last IRP was submitted in 2020
IRP modeling process
•Load forecast
•DER potential
•Power price forecast
•Resource cost forecast
•Extreme weather models
•Renewable profiles
Input assumptions Portfolio development Reliability testing
•Resource mix
•Renewable
•New technology
•Least cost
•Carbon reduction
•Reserve margins
•Portfolio testing with
•Dark calms (low
supply)
•Extreme weather
(high demand)
•Different
wind/solar profiles
Plexos model
•Extreme weather modeling
•Load forecast, customer load
contributions/flexibility
•Market prices, volatility and
congestion
•Required reserve margin and ELCC
•Beneficial electrification
assessment
Studies
•Emerging technology screening
•Cost curves
•Time to maturity
•Dispatchable technology evaluation
•High flexibility
•Low carbon
•Proven technology
•Distributed energy resource
assessment
•Customer adoption rate
•Usage profiles
Complex modeling of an uncertain future Technology evaluation
Integration of renewable
resources
Currently planned renewable supplies
Renewable integration challenges
•Renewable intermittency
•Day to day operation
•Extreme weather operation
•Ensuring reliability in all weather conditions
•Serving load with intermittent renewable generation will require:
•Long duration energy storage
•DERs and flexible load
•Dispatchable generation
Renewable intermittency challenges
Hourly (Summer 2030 forecast) Extreme weather (Valentine’s week 2021)
Trends in renewable costs
0
5
10
15
20
25
30
35
40
Solar Wind$/MWh 2020 2023
75%80%
Technology evaluation and
implementation
•Currently available technology:
four-hour storage (short duration
storage)
•Major use cases include
clipping daily peaks (charge
and discharge within 24 hours)
Battery storage technology
•Technology is not viable for long
duration storage strategy
•Primary challenge in
decarbonization
•Example: adopting this
technology for 24 hours of
storage would cost $3 billion
and more than double rates
(2020 IRP portfolio 3)
Opportunities Challenges
•Exploring and possibly piloting
technologies
•Hydrogen
•Carbon sequestration
•Renewable fuels
•Will adopt when commercially and
economically viable
•DERs
Future technology
•Time to maturity
•Cost
Opportunities Challenges
Summary
•Resource planning is a data intensive and a complex modeling process
•Next steps: modeling, reviewing studies, engaging industry experts
•Your input is appreciated
Distributed energy resources
planning and integration
Paul Davis, distributed energy resources manager
Distributed energy resources
Energy
efficiency Demand
response
Distributed
generation
Distributed energy storageElectrification
Save energy and
save money by
using energy
more efficiently
Reduce
greenhouse gases
by replacing fossil
fuel use with
increasingly
decarbonized
electricity
On site noncarbon
generation
provides customer
benefits and
reduces utility
investments
Shift energy to align electric use to
renewable availability and to
decarbonize the electric system in
a cost effective and reliable
manner
Flexible DERs that can form a virtual power plant
Virtual power plant (VPP)
A VPP is a portfolio of flexible DERs that can provide customer and electric system benefits by
responding on a scheduled basis or in near real time to manage the electric supply-demand balance
Relies on advanced information systems to enable communication, coordination and
appropriate, secure data sharing among
•Customers that have participating DERs
•DER original equipment manufacturers, DER vendors or DER aggregators
•The electric systems operated by
•Owner communities’ distribution utilities
•Platte River Power Authority
•Regional electricity market
Key VPP functions needed
Communication, coordination and appropriate, secure data sharing
•Visibility: operational data from DERs in near real time to support system operation
•Predictability: ability to forecast load and flexible DER performance
•Control or dispatch: ability to achieve flexible operation through direct utility control
(within agreed parameters) and provide price signals to allow customer control
•Optimization: prioritization among different uses (e.g., customer benefits, distribution
system and renewable integration)
•Program management: customer enrollment, device registration, customer notification,
financial settlement (market, owner communities, customers), etc.
Advanced information systems that enable the VPP
(partial list)
Platte River and owner community shared system
•Distributed energy resource management system (DERMS): a system that monitors,
forecasts and coordinates dispatch of DERs
Owner community systems
•Customer information system (CIS): system that provides data to support customer
enrollment in the VPP, possible support for DER program financial transactions (future)
•Advanced meter infrastructure (AMI) and meter data management (MDM): systems that
support measurement and verification, energy analytics and time varying electric rates
•[Future] Advanced distribution management system: system that provides monitoring,
analysis, control, optimization and planning functions for the distribution system
DER integration timeline
•DER forecast and potential study (2023)
•VPP/DERMS planning: gap assessment and roadmap (2022 through 2023)
•DERMS request for proposal (Q3/4 2023)
•VPP/DER system implementation/integration (2024 - 2026)
•Integration with Fort Collins DERMS
•Flexible DER pilot program planning (2023 - 2024)
•Flexible DER pilot programs (late 2024 - 2027)
•Flexible DER programs scale (2028 +)
Timeline depends on
DER roadmap and
pace of system
integration
Questions
prpa.org/2024irp
501 Light & Power - Capital Improvements Needed 2024-2026
New Development $56,636,029
Asset Renewal / Replacement $27,885,003
Both New Development and Asset Renewal $20,055,000
Annexations $7,329,473
Energy Services $7,727,315
501 Light & Power Capital Investments $119,632,820
1680 Subdivision Construction
16800000 System Addition/Replacement $20,234,665
1680 Subdivision Construction Total $20,234,665
1940 Minor Capital - Vehicles & Equipment
19400000 Minor Capital - Vehicles & Equipment $1,875,000
SCO On Call Vehicle - Ford Explorer $50,000
Meter Shop Electric Transit Van Level II charger installation $5,000
Vehicles and Equipment- Clear backlog from supply chain issues $1,000,000
Substation Crew Truck $150,000
Substation PM Truck $100,000
Computer Hardware/Software- Ipads for all crew members, AVL software needs, PCs, OT EE needs $150,000
1940 Minor Capital - Vehicles & Equipment Total $3,330,000
501001 Substations
501001A001 Battery Banks $81,000
501001A002 Battery Chargers $80,000
501001A004 Oil Containment Walls $140,000
501001A005 Replace HVAC Units $168,000
501001A006 Transformer Radiator Replacements $300,000
501001A009 Feeder Relay/Monitoring Replacements $600,000
501001A010 - Wildlife Mitigation $200,000
501001A011 - Harmony Wall/Drainage Repair $450,000
501001A012 Transformer Maintenance $400,000
501001A013 Substation Maintence Equipment $850,000
501001A014 Install Capacitor Banks $160,000
501001A015 Transformer Oil Filtration $420,000
501001A016 Substation Security $800,000
501001A017 Install Power Quality Systems $39,000
501001A018 Substation Misc Capital $260,000
2025 501001A018 Substation Basalite Walls $900,000
501001A020 Equipment For CVR (Conservation Voltage Reduction)$800,000
501001A021 UF Feeder Upgrades $600,000
501001A022 Substation Surveilance $500,000
501001A023 XFMR N2 System Refurbishing ($40k ea)$320,000
501001A024 Gate Replacements ($20keac)$60,000
501001 Substations Total $8,128,000
501001 New Substations
501001A022 New Northeast Substation $10,410,200
501001A023 New Northeast Substation Land Acquisition $1,500,000
PRPA Drake Upgrade/Move Request $11,500,000
501001 New Substations Total $23,410,200
501 Light & Power - Capital Improvements Needed 2024-2026
501002 Service Center
501002B003 Cable Handling Facility for Cut-To-Length Program $1,575,000
501002B006 Warehouse Storage Yard Covered Structure $199,000
Minor Renovations, Space Planning $120,000
501002 Service Center Total $1,894,000
501004 Annexations - OH>UG Conversions & Not Annexed
501004C005 Clydesdale Park First & Second Annexations $1,347,839
501004D001 Miller Enclave $277,000
501004C004 Blehm_(REA) Annexation $625,607
501004C001 Mail Creek Crossing 2nd Filing $491,959
501004C002 Strauss Cabin Enclave $208,041
501004-2434 Riverwalk Annexation $343,120
501004-2440 Arapahoe Bend Annexation $205,401
501004C004 Blehm_(Xcel) Annexation $63,320
501004C003 Fox Hills Annexation $153,186
501004C006 Southwest Annexation $2,890,000
501004D002 Mulberry Enclave Subarea 6 (Greenfield)$324,000
Transformer Purchases for SW Annexation - Offcycle appropriation $400,000
501004 Annexations Total $7,329,473
501005 Feeders
501005D004 Install circuit 936 to unload circuits 804, 834, and 906 $788,323
501005D078 Circuit 628 to serve NE developments - Ph1 Mt Vista $749,421
501005D079 Upgrade and Extend 722 to unload circuits 704 and 738 $576,887
501005D082 New Circuit 338 to serve Mulberry road developments $1,611,362
501005D092 Circuit - Richards Lake circuit 638 Extension West to Turnberry $513,707
501005 Feeders Total $4,239,700
501008 Duct Banks
501008D081 Duct Bank to serve NE FC Devel Ph 1 $1,882,715
501008D090 Duct Bank on Carriage Pkwy Phase 2 - Fox Grove to Forelock Dr $232,440
501008D091 Duct Bank on Carriage Pkwy Ph 3- Forelock Dr to Mulberry $282,027
501008D093 Duct Bank on Mulberry -Timberline to Carriage Pkwy $3,644,962
501008D100 Duct - Richards Lake circuit 638 Extension West to Turnberry $92,320
501008 Duct Banks Total $6,134,464
501012 System Cable Replacements
501012C016 CAPITAL - Replacement Area 16 - Parkwood East $130,000
501012C017 CAPITAL - Replacement Area 17 - Trail West PUD $182,000
501012C019 CAPITAL - Replacement Area 19 - Evergreen Park $69,000
501012C021 CAPITAL - Replacement Area 21 - West Azalea $32,000
501012C023 CAPITAL - Replacement Area 23 - Village West 3rd $84,000
501012C024 CAPITAL - Replacement Area 24 - Wagon Wheel $66,000
501012C025 CAPITAL - Replacement Area 25 - Brown Farm 4th $58,000
501012F020 Cable Replacements - Ongoing $1,380,000
501012F021 Feeder Cable Replacements - Ongoing $1,418,860
501012 System Cable Replacements Total $3,419,860
501013 Operational Technology
501013G001 ADMS $3,000,000
501013G003 eSCADA Hardware/Software - Conversion $500,000
501013G011 Radio System Upgrades $714,254
501013G012 GPS & Underground Facilities Visualization $127,926
501013G014 L&P/Energy Services Systems Alignment $319,815
501013G016 OT, Meter Shop and Substation Lab $2,450,000
501013 Operational Technology Total $7,111,995
501014 Transformers
501014F022 Distribution Transformer Purchases & Replacements $12,273,782
Transformer purchases to assure appropriate service levels for 2024 - Offcycle appropriation $1,211,218
Transformer purchases to assure appropriate service levels for 2025 - Offcycle appropriation $5,400,000
501014 Transformers Total $18,885,000
501015 Streetlights
501015F023 Streetlight System Replacement $2,960,598
501015G009 LED Streetlight Control and Automation $360,000
501015 Streetlights Total $3,320,598
501 Light & Power - Capital Improvements Needed 2024-2026
501016 Distribution Automation
501016G010 Distribution Automation/FLISR $600,000
501016G011 Dbl Ckt Feeder Monitoring $123,000
501016 Distribution Automation Total $723,000
501017 System Relocations
501017J001 System Relocations - Road & Intersection Projects $750,000
501017 System Relocations Total $750,000
501025 Advanced Metering Infrastructure
501025G004 AMI Equipment and Tech Upgrade $685,400
501025G006 AMI Backhaul Network Hardware Tech Refresh $277,250
501025G007 AMI Test Network Expansion $191,900
501025G008 AMI New Technology Testing and Miscellaneous Capital $300,000
501025 Advanced Metering Infrastructure Total $1,454,550
501000 Electric Field Services
Health and Safety- AED refresh/additions $150,000
Tools and Equipment- upgrades/price increases to base needs $100,000
501000 Electric Field Services Total $250,000
501000 Operations & Technology
Electric Perspective of the Utilities Data Mart (Azure Synapse Solution)$70,000
501000 Operations & Technology Total $70,000
501000 Engineering
Consulting - Studies $1,100,000
501000 Engineering Total $1,100,000
605 460240 Locates
Equipment Upgrades for GPS locating/mapping (Base Stations and GPS capable locators)$120,000
605 460240 Locates Total $120,000
501026 Demand Respond Technology Upgrade
501026G014 Energy Services Peak Partners - GIWH $4,207,500
501026G015 Energy Services Peak Partners - EVSE $600,000
501026G016 Energy Services Peak Partners - PRO1 Thermostat Sunset $200,000
501026G017 Energy Services Peak Partners - Inverter Supervision & Control $250,000
501026 Demand Respond Technology Upgrade Total $5,257,500
501013 Operational Technology
501013G014 L&P/Energy Services Systems Alignment $319,815
501013G015 Utility Scale Energy Storage $2,150,000
501013 Operations & Technology Total $2,469,815
Light & Power Total Capital Investment Need:$119,632,820
CITY OF FORT COLLINS ENERGY BOARD
August 10, 2023
AGENDA ITEM SUMMARY
Issuance of 2023 Revenue Bonds from the Electric and Telecommunications
Enterprise Fund
STAFF Lance Smith, Senior Director of Finance
EXECUTIVE SUMMARY
The purpose of this item is to inform and seek the support of the Energy Board for the issuance of debt
to support capital improvements in Light & Power and Connexion. Two Ordinances will be considered
on August 15th. The first Ordinance will be an appropriation ordinance that City Council will consider to
appropriate $20M in bond proceeds for Connexion to complete its capital buildout once such funds are
available. The second Ordinance will be considered by City Council in its capacity as the Board
overseeing the Electric and Telecommunications Enterprise Fund. This second Ordinance, if passed,
would authorize the issuance of $60M in revenue bonds from this fund with the proceeds expected by
the end of October.
The remaining $40M in bond proceeds will be appropriated through a combination of additional off-
cycle appropriation ordinances to procure long lead-time materials and to design and construct a new
substation to meet anticipated load growth from new development, as well as the 2025-26 Budgeting
for Outcomes process which begins informally at the end of this year.
ACTION REQUESTED
Does the Energy Board support the issuance of revenue bonds from the Electric and
Telecommunications Fund for the completion of the Connexion buildout and needed capital
investments in Light & Power infrastructure?
BACKGROUND
Light & Power
Capital projects are identified through a ten-year capital improvement plan which is updated along with
the overall long-term financial plan for each utility every two years ahead of the biennial budget cycle.
The need to issue debt in the Electric and Telecommunications Fund has been planned for several years.
The 10-year capital improvement plan for Light & Power has consistently shown a need for at least one
debt issuance in the 2023-25 timeframe. Ahead of the 2023-24 Budgeting for Outcomes process the
following 10-year rate and debt financing forecast was provided to the Council Finance Committee in
November of 2021:
In October 2022, as the budget was being finalized, inflation made it necessary to update the 10-year
forecasts before presenting them again to this Board:
“Attachment 2 - Near-term Light & Power Capital Improvement Planning Update” identifies near-term
capital needs. This preliminary update indicates there will be near-term capital needs:
• $57M for new development including $23M for a new substation
• $28M for renewal or replacement of existing assets
• $7M for Annexations that have already occurred
• $7M for Our Climate Future investments through Energy Services
• $20M for transformers to serve new customers as well as new load growth from
beneficial electrification by existing customers
These needs will be the basis for the update to the ten-year capital improvement plan which will be
completed by October. That updated plan will then feed into the updated financial plan (See
Attachment 3 – 2022 10-Year Strategic Financial Plan for Light & Power) which will be presented to this
Board and the Council Finance Committee in November or December before the 2025-26 biennial
budget process begins in earnest in the first quarter of 2024.
Connexion
In March 2023, Council authorized the reimbursement of capital expenditures through the issuance of
bonds. Connexion has now exhausted all currently available funds. Staff presented updated financial
projections for Connexion at the January 10, 2023, Work Session. In that meeting, the capital project
estimate was updated, reflecting a need to access approximately $16 million additional capital to
complete the network build-out and customer ramp-up by the end of 2024. An additional $3 – $5
million for excess operating expenses was also estimated to be needed. The maximum aggregate
principal amount of the bonds issued for Connexion cannot exceed $20,365,000.
Financial Considerations
Bond covenants for revenue bonds require a debt coverage ratio of at least 1.20. The table below from
the city’s 2022 Annual Comprehensive Financial Report shows the net revenues available for debt
service have increased from $13.8M in 2018 to $26.3M in 2022 which has allowed the debt coverage
ratio to increase from a low of 1.76 in 2018 to 2.86 in 2022. The increase in the current debt service
Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Rate Increase 2.0% 3.0% 4.1% 4-5% 4-5% 3-5% 2-3% 2-3% 2-4% 2-5%
Debt Issued ($M)$55.0
Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Rate Increase 2.0% 5.0% 5.0% 4-5% 4-5% 4-6% 7-8% 7-8% 7-8% 5-6% 5-6%
Debt Issued ($M)$37.0 $46.0
requirements from $7.9M in 2018 to $9.2M in 2022 will continue to increase, as planned during
issuance, over the next few years for existing debt until it peaks at $10.2M. The maximum annual debt
service (MADS) is used by rating agencies to assess the risk of a debt issuance. Averaging the last 5 years
of net revenues available for debt service and the MADS results in a debt coverage ratio of 1.95.
This proposed $60M issuance would increase the debt service requirements by $4.2M for 21 years.
Assuming net revenues for debt service remain at $26.3M and debt service requirements peak at
$10.2M + $4.2M = $14.4M, the debt coverage ratio will remain above 1.80 throughout the repayment
period.
As the 10-year rate and debt forecast above shows, there is anticipated to be another debt issuance for
Light & Power capital investments. Rate adjustments are anticipated which will increase the net
revenue available for debt service to ensure that the debt coverage ratio will remain at or above the
strategic financial target of 2.0.
STAFF RECOMMENDATION
Staff recommends supporting this debt issuance and the associated appropriation Ordinance for
Connexion.
ATTACHMENTS:
Attachment 1 – PowerPoint presentation
Attachment 2 – Near-term Light & Power Capital Improvement Planning Update
Attachment 3 – 2022 10-Year Strategic Financial Plan for Light & Power
Headline Copy Goes Here
Senior Director of Finance for Utilities
Lance Smith
08-10-2023
Electric and
Telecommunications
Enterprise Fund 2023
Revenue Bond
Issuance
Headline Copy Goes Here
2
2023 Revenue Bond Issuance
•Combined debt issuance of $66.1M
•$40M for Light & Power capital investments
•$25.5M for Connexion buildout
•$0.6M for issuance costs
•Timeline
•Presented to the Council Finance Committee July 6th
•Being presented to the Energy Board Aug 10th
•Being presented to the City Council (and Electric and Telecommunications Enterprise Board) on August 15th
•Anticipated issuance in September with proceeds available by the end of October
•Issuance terms:
•Fixed interest rate with 21-year repayment
•Fixed interest rate
•Light & Power will make even debt payments until 2044
•Connexion will pay interest only for 19 years and pay off balance in 2044
Headline Copy Goes Here
3
Use of Bond Proceeds: Connexion
•At the January 10, 2023 City Council Work Session the need was identified for additional funding to complete
the network buildout and customer ramp-up
•The outlook still remains the same:
•Approximately $20M of additional funded is needed
•$16M capital buildout
•$4M near-term operations through 2024
•December 2024 is expected to be the point of maximum need with 2025 projected as breakeven (revenues
covering capital, operating expenses and debts service costs)
•Connexion has exhausted the $20M appropriation from L&P reserves
•In March 2023, City Council authorized Connexion to use bond proceeds to reimburse expenditures related to
construction
•Proceeds will be appropriated with the authorization for the debt issuance for Connexion.
Headline Copy Goes Here
4
Use of Bond Proceeds: Light & Power
•Prior to the 2023-24 Budgeting For Outcomes process the following 10-year rate and debt financing forecast
was provided to the Council Finance Committee in November of 2021:
•In October 2022, as the budget was being finalized, inflation made it necessary to update the 10-year forecasts
before presenting them again to this Board:
•There has been a near-term need for some debt financing of L&P capital investments being planned for
previously. Proceeds from this issuance will be appropriated through off-cycle appropriations and the 2025-26
Budgeting For Outcomes for Light & Power.
Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Rate Increase 2.0%3.0%4.1%4-5%4-5%3-5%2-3%2-3%2-4%2-5%
Debt Issued ($M)$55.0
Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Rate Increase 2.0%5.0%5.0%4-5%4-5%4-6%7-8%7-8%7-8%5-6%5-6%
Debt Issued ($M)$37.0 $46.0
Headline Copy Goes Here
5
Updated Capital Improvement Plan: Light & Power
•Ahead of the 2025-26 Budgeting For Outcomes process, the long-term financial plan will be
updated for Light & Power.
•Part of this update involves revisiting the 10-year Capital Improvement Plan
•Preliminary updates indicate there will be near-term capital needs:
•$57M for new development including $23M for a new substation
•$28M for renewal or replacement of existing assets
•$7M for Annexations that have already occurred
•$7M for Our Climate Future investments through Energy Services
•$20M for transformers to serve new customers as well as new load growth from beneficial electrification by
existing customers
Headline Copy Goes Here
6
Financial Impacts of Issuance
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Electric and Telecommunications Fund
Net Revenue Available For Debt Service
Debt Service Requirement
While funds available for debt service have increased, as planned, annual debt service has
also increased for Connexion.
Headline Copy Goes Here
0.00
2.00
4.00
6.00
8.00
10.00
12.00
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Electric and Telecommunications Fund
Net Revenue Available For Debt Service
Debt Service Requirement
Debt Coverage Ratio
7
Financial Impacts of Issuance
The debt coverage ratio has varied around 2.9 to 3.4 (meaning that the amount of funds
available to pay debt service has been 2.9 to 3.4 times what was needed). Revenue bond
covenants only require a debt coverage ratio of 1.2 so there is still debt capacity remaining.
Headline Copy Goes Here
8
Recommended Motion Language
I move that the Energy Board support the issuance of these revenue bonds
from the Electric and Telecommunications Enterprise Fund for the
completion of the Connexion build out and continued investments in electric
infrastructure to serve existing and new customers.
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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2022 10-Year Strategic Financial Plan
City of Fort Collins Utilities
Light & Power
UTILITIES
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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Table of Contents
Purpose of the Strategic Financial Plans ..................................................................................................... 3
2021 Financial Overview ............................................................................................................................ 3
2021 Revenues ........................................................................................................................................ 4
2021 Expenses ........................................................................................................................................ 6
Long-Term Financial Analysis ................................................................................................................... 9
Revenue Analysis.................................................................................................................................... 9
Expenditure Analysis – Light & Power ................................................................................................ 12
Operating Income Analysis – Light & Power ....................................................................................... 17
Capital Planning and Expenditure Analysis ......................................................................................... 18
Debt Analysis ........................................................................................................................................ 20
Reserves Analysis ................................................................................................................................. 23
Rate Analysis ........................................................................................................................................ 24
Financial Risk Assessment ....................................................................................................................... 27
Appendix A: Capital Improvement Plan .................................................................................................. 28
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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Purpose of the Strategic Financial Plans
The strategic financial plans are intended to provide a 10-year plan for the efficient and effective
financial management of each utility in a manner that is consistent with the City’s values and mission
and aligned with the City’s biennial Budget Process and Strategic Planning Process. Much of the long-
term strategic direction for each utility requires significant capital investment spanning more than one
budget cycle and while the magnitude of the required investment may be included in the capital
improvement plans, the financial capacity and strategies to meet these challenges is beyond the scope of
such plans. Capital improvement projects should be prioritized through an asset management program
to ensure alignment with the City’s strategic objectives and proper planning to achieve the targeted
levels of service for each utility to our community.
Whereas strategic planning sets the operational direction of where the utilities are going in the future,
strategic financial planning provides a financial context for this movement. The strategic financial plans
ensure the long-term operational and fiscal objectives and level of service targets for each of the utilities
are met in a financially sustainable and resilient manner. The strategic financial plans outline the
projected financial health, long-term revenues and expenditures, debt position and recommended
financial strategies necessary to achieve the operational objectives and targeted levels of service for each
of the four utilities over the next 10 years.
2021 Financial Overview
Note: This enterprise fund consists of both an electric utility and an internet utility. This report only speaks to
the electric utility.
As the table below shows, the three main financial metrics from a long-term financial planning
perspective were met in 2021. The operating margin, the excess in operating revenues after covering all
operating expenses including depreciation, continued to improve in 2021 driven by significant recent
rate increases at the upper limit of the targeted range as well as limited growth in operating expenses.
More modest rate adjustments in the next 10 years between 2 and 4% will be necessary to maintain this
positive operating margin.
The debt coverage ratio is shown as if there is no outstanding debt. This enterprise fund does have
outstanding debt of $129.6M at the end of 2021 related to Connexion, however, because it is not directly
Strategic Financial
Plan Target 2017 2018 2019 2020 2021 2022
Target
Operating Margin > 2.0%-3.6% -5.6% -1.1% 2.5% 5.6% 3.0%
Debt Coverage Ratio > 2.0 6.9 - - - --
Rate Adjustment < 5.0%3.45% 1.8% 5.0% 5.0% 3.0% 2.0%
Operating Margin = (Operating Revenues from Monthly Charges) - (Operating Expenses including depreciation)
(Operating Revenues from Monthly Charges)
Debt Coverage Ratio = (Net Pledged Revenues consisting of Operating Margin + Development Fees + Earned Interest)
(Annual Debt Service Expense)
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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associated with electric infrastructure, it is not driving any rate adjustments for electric services and
therefore not included in this table. The combined electric and internet net pledged revenues are
sufficient to maintain the targeted debt coverage ratio of 2.0 for this debt.
Operating revenues had grown through modest rate adjustments at a steady rate of 2-3% before
increasing 5% in 2021. Total energy sales continue to be flat with modest customer growth offset by
conservation efforts. This has allowed for the operating income to turn positive as operating expenses
have grown at a slower rate – still not exceeding the peak seen in 2018. However, inflationary pressures
are being seen across the utilities for materials and labor as we begin the 2023-24 budget cycle.
2021 Revenues
Total revenues associated with electric services grew by 7.0% in 2021 over 2020. Revenues for
residential services remain the largest contributor.
$120,000,000
$125,000,000
$130,000,000
$135,000,000
$140,000,000
$145,000,000
$150,000,000
2017 2018 2019 2020 2021
Light & Power Operations
Operating Revenue
Operating Expense
Residential Elec
Services,
$60,523,864
Commercial Elec
Services,
$44,604,468
Industrial Charges
for Services,
$32,596,311
PILOTs,
$8,275,824
Development
Fees/PIFs/Contributions,
$6,014,739
Other Misc,
$2,311,992
Electric Revenues -2021
$154.3M
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Operating revenues exceeded the budget by $8.3M in 2021 primarily driven by continued growth in
residential sales. This was consistent with what was seen in 2020, particularly after the COVID
pandemic began in March of 2020. Commercial and industrial revenues were closer to the budgeted
amounts in 2021 than in 2020 with commercial revenues slightly exceeding the budget. Non-operating
revenues from development fees were twice what was realized in 2020 and were adequate to cover the
system additions and replacements completed in 2021. Revenues are budgeted conservatively to account
for weather variability and other uncertainties.
The three-year trend below shows stable revenues throughout the pandemic and reflects the associated
shift from the workplace to remote work.
$ 6,015
$ 151
$ 32,596
$ 44,604
$ 60,524
$ 2,964
$ 340
$ 33,230
$ 43,450
$ 53,070
$ 0 $ 10,000 $ 20,000 $ 30,000 $ 40,000 $ 50,000 $ 60,000 $ 70,000
Development Fees
Green Energy Program Sales
Industrial Sales
Commercial Sales
Residential Sales
2021 Actual vs Budget Revenues ($K)
Budget
Actual
$ 6,015
$ 151
$ 32,596
$ 44,604
$ 60,524
$ 3,346
$ 242
$ 31,746
$ 41,396
$ 57,980
$ 3,493
$ 364
$ 32,701
$ 42,833
$ 51,586
$ 0 $ 10,000 $ 20,000 $ 30,000 $ 40,000 $ 50,000 $ 60,000 $ 70,000
Development Fees
Green Energy Program Sales
Industrial Sales
Commercial Sales
Residential Sales
Year Over Year Revenues ($K)
2019
2020
2021
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2021 Expenses
Total expenses for electric services and capital investment grew 3.8% in 2021 over 2020. With
depreciation, PRPA purchased power costs comprised 62% of total expenses. Without depreciation and
system additions, replacements and asset renewal expenses, none of which are included in rate
considerations, these purchased power costs represent 72% of expenses.
Operating expenses were below budget in 2021 by $6.4M primarily due to lower than anticipated energy
purchases. The purchased power expense from Platte River Power Authority (PRPA) was $4.7M below
budget before any weather normalization. Aside from the PRPA generation and transmission expense
which is not included in the graph below, Light & Power operations and administrative expenses were
very close to budget. Administrative expenses are expected to be below budget before the financials are
fully settled for 2021 over the next few months. PILOTs refer to the 6% transfer to the General Fund for
payment in lieu of taxes (PILOTs) and exceeded budget based on realized operating revenues which
themselves were higher than budgeted. Energy Services were $2.5M, or 32%, below budget and
essentially flat to the previous two years. Just as revenues are budgeted conservatively, expenses are
budgeted adequately to ensure that the annual appropriations made by City Council are not exceeded per
Municipal Code.
PRPA Purchased
Power, $91,717,204 System Additions /
Replacement /
Asset Renewal,
$11,009,549
L&P Operations,
$10,205,297
Administrative
Services, $9,666,806
PILOTs, $8,254,729
Community
Renewables,
$1,964,444
Energy Services,
$4,773,569
Depreciation,
$11,500,000
Electric Expenses -2021
$149.1M
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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The three-year trend below shows growth by major expense categories. The growth in administrative
expenses reflects increased costs associated with higher executive consulting expenses within Utilities,
updating the administrative charges model from general municipal services as well as higher than
anticipated bad debt expense related to the pandemic.
$ 6,139
$ 1,964
$ 4,774
$ 8,255
$ 9,667
$ 10,205
$ 6,515
$ 2,015
$ 6,999
$ 7,810
$ 9,388
$ 10,038
$ 0 $ 2,000 $ 4,000 $ 6,000 $ 8,000 $ 10,000 $ 12,000
System Addition/
Replacement
Community Renewables
Energy Services
PILOTs
Administrative Services
L&P Operations
2021 Actual vs. Budget Expenses ($K)
(Not including Purchased Power Expense)
Budget
Actual
$ 6,139
$ 1,964
$ 4,774
$ 8,255
$ 9,667
$ 10,205
$ 3,788
$ 1,684
$ 4,845
$ 7,879
$ 8,938
$ 9,726
$ 4,564
$ 1,316
$ 4,748
$ 7,649
$ 7,877
$ 9,857
$ 0 $ 2,000 $ 4,000 $ 6,000 $ 8,000 $ 10,000 $ 12,000
System Addition/
Replacement
Community Renewables
Energy Services
PILOTs
Administrative Services
L&P Operations
Year Over Year Expenses ($K)
2019
2020
2021
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Community renewables consist of energy purchased from “customer-generators” producing energy
through solar generation. The five-year trend shown below reflects the growth of such generation on the
distribution system. Most of the renewable energy provided to our customers is still purchased through
Platte River Power Authority (PRPA). These purchases are now part of the base Tariff 1 purchase
power agreement with PRPA as the previous Tariff 7 was eliminated in 2020. In 2021, 38% of PRPA’s
generation was non-carbon emitting energy.
The following graph shows the recent trend in purchased power expense through PRPA. The 2018 peak
in operating revenues was driven by the peak annual demand in energy which resulted in the highest
annual purchased power expense being realized as shown by this graph.
$ 0 $ 500 $ 1,000 $ 1,500 $ 2,000 $ 2,500 $ 3,000
2021
2020
2019
2018
2017
Renewable Energy Purchased from Customers ($K)
$ 89,500 $ 90,000 $ 90,500 $ 91,000 $ 91,500 $ 92,000 $ 92,500 $ 93,000 $ 93,500 $ 94,000 $ 94,500
2021
2020
2019
2018
2017
Year Over Year Purchased Power Expenses ($K)
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Long-Term Financial Analysis
Revenue Analysis
Light & Power revenues consist of operating revenues from monthly charges for services which includes a 6%
payment in lieu of taxes (PILOTs) that is transferred to the General Fund of the City and non-operating revenues
which consist of development fees, other minor fees (dark fiber leases, warehouse fees, etc.) and miscellaneous
revenues (interest, asset auctions, etc.). Approximately 59% of these revenues are passed directly through to
Platte River for generation and transmission charges and the 6% PILOTs revenue is transferred to the General
Fund. The remaining 35% of revenues consists of operating revenues and non-operating revenues which are
available to the Light & Power Enterprise Fund for operational and capital expenses although, as a standing
practice, non-operating revenue should not be relied upon for operational expenses. Energy conservation and
renewable energy programs also need to be covered in the remaining 35%.
With widespread adoption of air conditioning, Light & Power shifted from a winter peaking utility to a summer
peaking utility a few decades ago. The wholesale purchased power charges from Platte River Power Authority
have a seasonal component to the demand charge which is reflected below in the monthly revenue stream along
with the increased energy consumption in the summer months.
Operating revenues for this fund have grown substantially over the previous decade from $100M in 2011 to
$146M in 2021 while the amount of energy consumed by the community has remained flat over the same period.
Overall growth has just outpaced energy conservation efforts resulting in reduced energy use per customer but an
overall 0.2% annual increase in total energy consumed. Thus, the significant growth in operating revenues is
attributable entirely to rate increases that have occurred since 2011 and not growth in consumption.
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,000
$18,000,000
Electric Monthly Operating Revenues (2011 -2021)
2021
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
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The table below shows the annual revenues by major categories for the past 5 years. Residential revenues have
been growing more steadily than commercial and industrial revenues over the last 5 years. (The data here is not
adjusted for weather so as to accurately represent the revenues received.)
The table also shows that the non-lapsing revenues over this same period have come mostly from development
fees. Electric development fees peaked in 2016 although strong growth returned in 2021. The volatility of
development fees is much greater than that of operating revenues requiring caution before relying on development
fee revenues for necessary capital improvements or forecasting revenues.
0
500,000,000
1,000,000,000
1,500,000,000
$0
$20,000,000
$40,000,000
$60,000,000
$80,000,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Energy Sales (kWh)Operating RevenuesElectric Operating Revenues and Energy Sales (2011-2021)
Annual Demand (KWH)Residential Sales Commercial Sales Industrial Sales
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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Looking at revenues on an annual percent change basis shows a longer-term trend of 3-4% annual growth since
2011 with 2021 showing 6.76% growth in revenues (see table below). Development fees accounted for $2.6M of
the $9.8M increase in revenues in 2021 while the 3.0% retail rate increase accounted for most of the rest. Again,
revenue growth is being driven by rate increases and those rates for monthly charges have increased well above
the rate of inflation (0-2%) over each time horizon.
Budget
Year 2017 2018 2019 2020 2021 2021
Customers 72,523 74,585 75,656 76,821 77,741 77,741
Annual Rate Adjustment 3.45% 1.80% 5.00% 5.00% 3.00% 3.00%
Residential Elec Services 48,155,049$ 50,193,559$ 51,585,680$ 57,979,597$ 60,523,864$ 53,070,000$
Commercial Elec Services 40,883,514$ 41,366,478$ 42,832,683$ 41,396,010$ 44,604,468$ 43,450,000$
Industrial Charges for Services 32,004,494$ 32,305,145$ 32,700,560$ 31,746,182$ 32,596,311$ 33,230,000$
Green Energy Program 399,322$ 380,138$ 363,727$ 241,815$ 151,080$ 340,000$
PILOTs 7,287,813$ 7,453,720$ 7,648,671$ 7,879,394$ 8,275,824$ 7,810,000$
Operating Revenue 128,730,192$ 131,699,040$ 135,131,321$ 139,242,998$ 146,151,547$ 137,900,000$
Development Fees/PIFs/Contributions 5,490,709$ 4,302,440$ 3,492,813$ 3,345,800$ 6,014,739$ 2,895,000$
Interest Revenue 457,811$ 429,785$ 478,827$ 422,134$ 318,381$ 247,660$
Transfers In -$ -$ -$ -$ -$ -$
Other Misc 2,362,133$ 1,758,453$ 2,114,025$ 1,258,384$ 1,839,131$ 1,155,000$
Non-Operating Revenue 8,375,563$ 6,576,363$ 6,395,988$ 5,252,125$ 8,172,251$ 4,297,660$
Revenue Bonds -$ -$ -$ -$ -$ -$
Operating/Capital Grants & Contributions -$ -$ -$ 59,366$ -$ -$
External Revenue -$ -$ -$ 59,366$ -$ -$
Total Revenues 137,105,754$ 138,275,403$ 141,527,308$ 144,554,489$ 154,323,798$ 142,197,660$
Budget
Year 2020 2021 2021
10 Yr
Annualized
Trend
5 Yr
Annualized
Trend
3 Yr
Annualized
Trend
1 Yr
Annualized
Trend
Customers 76,821 77,741 77,741 1.62%1.74% 1.39% 1.20%
Annual Rate Adjustment 5.00% 3.00% 3.00% 3.80%3.65% 4.33% 3.00%
Residential Elec Services 57,979,597$ 60,523,864$ 53,070,000$ 4.29%5.10% 6.44% 4.39%
Commercial Elec Services 41,396,010$ 44,604,468$ 43,450,000$ 3.30%2.14% 2.54% 7.75%
Industrial Charges for Services 31,746,182$ 32,596,311$ 33,230,000$ 4.24%1.49% 0.30% 2.68%
Green Energy Program 241,815$ 151,080$ 340,000$ -10.89%-17.45% -26.48% -37.52%
PILOTs 7,879,394$ 8,275,824$ 7,810,000$ 3.90%3.17% 3.55% 5.03%
Operating Revenue 139,242,998$ 146,151,547$ 137,900,000$ 3.90%3.16% 3.53% 4.96%
Development Fees/PIFs/Contributions 3,345,800$ 6,014,739$ 2,895,000$ 11.31%-1.12% 11.82% 79.77%
Interest Revenue 422,134$ 318,381$ 247,660$ -7.76%-9.15% -9.52% -24.58%
Transfers In -$ -$ -$
Other Misc 1,258,384$ 1,839,131$ 1,155,000$ 0.32%-4.12% 1.51% 46.15%
Non-Operating Revenue 5,252,125$ 8,172,251$ 4,297,660$ 5.71%-1.65% 7.51% 55.60%
Total Revenues 144,554,489$ 154,323,798$ 142,197,660$ 3.53%2.86% 3.73% 6.76%
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Looking out over the next ten years through the long-term financial model, revenues are expected to continue
trending upward as residential development continues and modest rate adjustments are necessary for Platte River
Power Authority to meet the 2030 climate goals and the distribution system is renewed. Beneficial Electrification
will be a focus in the coming decade which may increase energy sales and in turn revenues. The graph below
shows a forecasted annual growth of 3.8% in future operating revenue (solid green line) which is consistent with
the growth over the past decade. The green area shows the range of revenues considered in the stochastic analysis
for the long term financial model.
Non-operating revenues are expected to remain within the range seen over the past decade with modest inflation
offsetting the impacts of redevelopment becoming more common requiring less development fees than “green
field” development and investment policies remain conservative. The uncertainty over the next decade appears
large due to the volatility of the development fees. Any unanticipated grant revenue would positively impact the
financial health of the utility and as such is not modelled here.
Expenditure Analysis – Light & Power
Light & Power operating expenses are shown below in the categories consistent with the monthly financial
operating report. The two expense categories on that monthly report made to Platte River Power Authority
(PRPA) are not included to provide some relative scale for the expenses that remain within the municipality. The
direct operational costs are shown in purple, community renewable and energy efficiency program expenses in
shades of green and the administrative expenses in shades of yellow. The payment in lieu of taxes is shown
second from the bottom. Depreciation is a non-budgetary expense so it is shown on top. Total operating
expenses have grown at an annual rate of 3.6% over the past decade. Without depreciation and PRPA expenses
considered, operating expenses have grown at an annual rate of 4.7% over the past decade. This rate of annual
growth is assumed to be tightly managed in the analysis and forecasts below.
$0
$50,000,000
$100,000,000
$150,000,000
$200,000,000
$250,000,000
2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031
Operating Revenues (2011 -2031)
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Operating expenses in the Light & Power Fund have grown well above the rate of inflation over the past decade.
The most critical factor in the financial health of this Fund is to manage operational expenses to grow no more
than 3.0% annually. The increased capital investments in system renewal should help with O&M labor expense,
as the Connexion build-out has done since 2018, but significant attention will need to be given to operational
expenses within each Business Unit to ensure adequate revenues to make these investments.
The table below shows operating and non-operating expenses by the major categories shown on the Monthly
Financial Operating Report (MOR).
$-
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
$40,000,000
$45,000,000
$50,000,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Electric Operating Expenses (2011 -2021)
less PRPA Expense
L&P Operations
PILOTs
Admin Services - CS&A
Admin Services - General Fund
Other Payments & Transfers
Energy Services
Purchase Pwr - Community Renewables
Depreciation
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Purchased Power – Tariff 1 - Increased purchase power costs are offset directly by increased operating revenues
through rate increases each year. The upward trend is driven mainly by year over year wholesale rate increases by
Platte River. As PRPA moves toward its 2030 goal of 100% renewable energy, it is expected that annual retail
rate adjustments of 1.5-2.5% will be needed until 2030. These rate increases are included in the rate projections
modeled here.
Renewables PRPA - A set amount of renewable energy (76,000 MWh / yr) has been purchased each year from
Platte River toward internal renewable energy goals until 2021. These costs were rolled into the Tariff 1
purchased power costs beginning in 2021.
Community Renewables – The growth seen here over the past decade was driven primarily by the Solar
Purchased Power Program (SP3) which took advantage of a State program allowing for any renewable energy
purchased under certain conditions to count triple toward the Renewable Energy Standard. This was
accomplished through 20 year purchased power agreements at a fixed rate. Ongoing adoption of distributed
generation will continue to increase this expense through similar purchased power agreements as well as rooftop
solar excess energy purchases.
L&P Operations – This line item represents the largest and most direct expenses associated with providing
electric services to the community. These expenses have been managed tightly in recent years although there was
Budget
Year 2017 2018 2019 2020 2021 2021
Annual Demand (KWH)1,499,034,911 1,516,929,428 1,483,954,714 1,457,336,159 1,476,408,624 1,495,938,741
Purchase Power -Tariff 1 PRPA 89,413,232$ 92,104,424$ 91,707,977$ 89,411,750$ 91,717,204$ 94,493,000$
Purchase Power - Renewables PRPA 1,900,007$ 1,899,993$ 1,900,000$ 1,900,000$ -$ 1,900,000$
Purchase Pwr - Community Renewables 754,063$ 770,017$ 1,315,861$ 1,683,711$ 1,964,444$ 2,014,700$
L&P Operations 10,034,802$ 10,836,548$ 9,857,112$ 9,726,245$ 10,205,297$ 10,037,738$
Energy Services 5,952,237$ 6,495,792$ 4,747,851$ 4,844,966$ 4,773,569$ 6,999,124$
PILOTs 7,287,813$ 7,453,711$ 7,648,671$ 7,879,376$ 8,254,729$ 7,810,000$
Admin Services - CS&A 5,832,953$ 5,883,633$ 6,318,644$ 7,335,602$ 7,394,617$ 7,394,617$
Admin Services - General Fund 1,163,489$ 1,192,576$ 1,107,453$ 1,135,139$ 1,090,628$ 1,090,628$
Other Payments & Transfers 701,670$ 1,236,452$ 450,755$ 466,839$ 1,181,561$ 1,181,561$
Depreciation 10,325,278$ 11,209,564$ 11,518,342$ 11,420,843$ 11,500,000$ 12,000,000$
Total Operating Expenses 133,365,544$ 139,082,709$ 136,572,666$ 135,804,472$ 138,082,049$ 144,921,368$
Debt Service 1,992,263$ 142,254$ 25,223$ 25,228$ 12,656$ 12,660$
System Addition/Replacement 6,209,847$ 4,490,883$ 4,564,438$ 3,788,421$ 6,139,007$ 5,559,120$
Capital (other than Sys Add)8,950,979$ 5,517,340$ 5,758,112$ 4,053,113$ 4,870,542$ 7,647,504$
Total Non-operating Expenses 17,153,090$ 10,150,476$ 10,347,772$ 7,866,762$ 11,022,205$ 13,219,284$
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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an increase of 4.9% in these costs in 2021. Managing this growth to a more moderate level in the future will be
very important to the financial success of this utility.
Energy Services – This expense category includes energy efficiency and conservation programs as well as
customer rebates and incentives. As the table below shows, these expenses have been decreasing in recent years
while the budget has remained closer to previous levels.
Payments in Lieu of Taxes (PILOTs) – This is a transfer to the General Fund set at 6% of operating revenues.
As such, any increase in this expense is directly offset by higher operating revenues.
Administrative Services – Administrative Service expenses from the Utilities internal Customer Service and
Administration areas increased significantly over the past few years. This is in part due to staffing issues related
to upgrading the billing system and to higher consulting costs associated with having an interim Executive
Director for almost two years. It will be important to limit growth in these expenses going forward.
Administrative Services from the General Fund has seen more modest increases over this same period. In 2021,
bad debt was also significantly higher than in previous years due to the “no shut-offs” policy implemented during
the Covid-19 pandemic. This is expected to return to a more manageable level beginning in 2022.
System Additions and Capital – The intermediate term downward trend reflects the extraordinary capital
investments made 3-7 years ago which included deployment of the advanced metering infrastructure ($36M
investment) and the construction of the new Customer Service building at 222 LaPorte (~$15M investment). The
one-year change reflects the level of development seen in 2021 consistent with the significant increase in
development fees seen in the revenues over 2020.
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Looking out over the next ten years through the long-term financial model, expenses will need to be tightly
managed so as not to exceed the rate of inflation in total. This will be particularly challenging as most of the
operating revenue goes to purchased power expenses which are expected to grow above the long-term rate of
inflation – purchased power costs are assumed to increase at 2.25% annually. The dotted black line in the chart
shows the current trend on operating expenses. The solid red line into the future assumes operating expenses
other than purchased power and PILOTs also grow at a rate of only 2.9% annually consistent with the historical
growth. The uncertainty in operating expenses is large and highlights the importance of stochastic modeling
rather than showing a single forecasted value a decade into the future.
Budget
Year 2020 2021 2021
10 Yr
Annualized
Trend
5 Yr
Annualized
Trend
3 Yr
Annualized
Trend
1 Yr
Annualized
Trend
Annual Demand (KWH)1,457,336,159 1,476,408,624 1,495,938,741 0.2% -0.4% -0.9% 1.3%
Purchase Power -Tariff 1 PRPA 89,411,750$ 91,717,204$ 94,493,000$ 2.8% 1.0% -0.1% 2.6%
Purchase Power - Renewables PRPA 1,900,000$ -$ 1,900,000$ -100.0% -100.0% -100.0% -100.0%
Purchase Pwr - Community Renewables 1,683,711$ 1,964,444$ 2,014,700$ 21.6% 36.6% 16.7%
L&P Operations 9,726,245$ 10,205,297$ 10,037,738$ 3.2% -0.3% -2.0% 4.9%
Energy Services 4,844,966$ 4,773,569$ 6,999,124$ 4.6% -6.7% -9.8% -1.5%
PILOTs 7,879,376$ 8,254,729$ 7,810,000$ 3.9% 3.1% 3.5% 4.8%
Admin Services - CS&A 7,335,602$ 7,394,617$ 7,394,617$ 5.4% 2.6% 7.9% 0.8%
Admin Services - General Fund 1,135,139$ 1,090,628$ 1,090,628$ 0.6% -6.2% -2.9% -3.9%
Other Payments & Transfers 466,839$ 1,181,561$ 1,181,561$ 10.2% 15.8% -1.5% 153.1%
Depreciation 11,420,843$ 11,500,000$ 12,000,000$ 4.4% 4.5% 0.9% 0.7%
Total Operating Expenses 135,804,472$ 138,082,049$ 144,921,368$ 3.2% 0.9% -0.2% 1.7%
Debt Service 25,228$ 12,656$ 12,660$ -38.5% -63.6% -55.4% -49.8%
System Addition/Replacement 3,788,421$ 6,139,007$ 5,559,120$ 0.1% -12.8% 11.0% 62.0%
Capital (other than Sys Add)4,053,113$ 4,870,542$ 7,647,504$ -7.7% -14.8% -4.1% 20.2%
Total Non-operating Expenses 7,866,762$ 11,022,205$ 13,219,284$ -5.1% -15.1% 2.8% 40.1%
Total Expenses 143,671,234$ 149,104,254$ 158,140,652$ 2.3% -1.0% 0.0% 3.8%
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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Operating Income Analysis – Light & Power
The operating income for this Fund has been negative for 6 of the last 10 years. This was initially an intentional
effort to draw down Reserves but because of continued negative operating income rate increases were necessary
beginning in 2017 as part of the solution to address this ongoing shortfall. Operating income turned positive
beginning in 2019 with the proposed rate increases before the pandemic and has increased through 2021. This
trend is expected to continue provided operating expenses are controlled.
($50,000,000)
$0
$50,000,000
$100,000,000
$150,000,000
$200,000,000
$250,000,000
201120122013201420152016201720182019202020212022202320242025202620272028202920302031Operating Income 2011 -2031
Operating Income
Operating Revenue
Operating Expense
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Capital Planning and Expenditure Analysis
Note: Appendix A shows the anticipated capital investments and expected year of investment.
Ahead of the biennial budget cycle, the long-term financial models are updated to determine if any rate
adjustments are needed as well as if there is a need to issue debt for upcoming capital investments. The financial
models require a review of the 10-year capital investment plans and a need to re-prioritize the anticipated projects
along with any new investments. An updated CIP was developed in October 2021 ahead of discussions with the
Council Finance Committee.
The development of prioritized CIPs is necessary to ensure efficient use of capital to optimize the levels of service
being provided to our community. This prioritization has been an elusive goal since the first CIP was developed
in 2016. Progress has been made on identifying the service level metrics for this utility but setting service level
targets and the relative weights of those service levels remains to be done. Additionally, the 10-year CIPs have
fluctuated significantly from one budget cycle to the next (every 2 years) which makes financial planning more
challenging than more stable and refined CIPs would require for each utility including this one. After the 2021
CIP deadline of October 1st an additional $65M was added to it over the next two weeks which increased the 10-
year capital needs by 40%. This type of volatility in long-term planning efforts is very unsettling.
The current 10 Year capital improvement plan (CIP) anticipates almost 50% more capital investment over the
coming decade than was realized in the previous decade. The investments over the past decade involved
significant work by outside labor including the Utility Customer Service Building and the deployment of smart
meter infrastructure suggesting the amount of capital work intended to be done in house over the coming decade
is much more than a 50% increase. This increase is largely driven by new capacity needs, anticipated annexations
which require significant capital investment with no associated development fee revenue, a new substation, and
asset replacement of aging infrastructure.
$0
$50,000,000
$100,000,000
$150,000,000
$200,000,000
$250,000,000
$300,000,000
2016 CIP 2017 CIP 2019 CIP 2021 CIP 10/01 2021 CIP 10/15
Light & Power 10 Year Capital Improvement Plan Totals (NOT inflated)
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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The current 10 Year CIP consists of $221M of identified capital investments which consists of $57M of new
capital needs for the anticipated growth in system demands over the decade as well as $52M for system renewal
investments, $43M for anticipated annexations, $40M for new technology, $18M for substation investments and
$10M for facilities and vehicles. (All projects are identified in 2021 dollars so that a consistent inflation can be
applied to all future projects.)
The following chart shows the annual capital investment made each year with the amount of approved capital
investment remaining at the end of the year. In addition to the annual lapsing appropriation for System Additions
/ Replacements which is intended to provide adequate funding to meet all new infrastructure associated with new
development, each year new capital appropriations are made for asset renewal programs and specific projects
which add the capital investment remaining from previous years. The amount of capital appropriations remaining
at the end of each year exceeds the realized annual capital investment made each year. At the end of 2021, the
amount of capital appropriated from previous budget cycles was $13,045,076. This $13M shown in green will
require more than two years to invest at the recent rate of investment shown in light red without any additional
capital appropriations being requested.
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031Annual Capital InvestmentCapital Investments 2022 -2031
(in 2021 dollars)
Technology and Other Annexations Transformers, Cables & Duct Banks
System Additions Substations Last 10 Yr Ave Annual Capital $
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While there is some lead time related to capital investments because of the policy of fully funding each capital
investment up front, this build-up of capital work reduces the agility to adapt capital investments as priorities may
change. The capital improvement plan discussed below and included in Appendix A is recommending that an
additional 46.7M be appropriated in the 2023-24 budget cycle for capital work. It is recommended that a long-
term strategic resource plan be developed to execute all currently funded and future capital investments before
debt is issued for any capital investment.
The electric system is almost entirely an underground distribution system that has been built over the last 30-50
years. These underground assets have performed well over their useful life, allowing the community to benefit
from a very reliable electric system, but based on the current CIP it is expected that significant capital investment
will need to be made in the coming decades to renew this aging infrastructure. The need for asset lifecycle
management strategies (from installation to replacement) for all major electric assets needs to be an area of focus
for Asset Management and L&P Operations in the next few years so that the necessary investments are prioritized
and adequate funding is available as needed in the future.
Annexations into the City limits typically result in this utility taking over service from a neighboring utility. This
requires compensating the neighboring utility for stranded assets and sometimes for lost future revenue.
Additionally, it involves reconfiguring and rebuilding the existing infrastructure without any development fee to
offset the capital investment. Thus, annexations can be a significant expense for this utility. The Mulberry
Annexation is the most significant contributor to the Annexations category as this annexation is estimated to cost
electric ratepayers at least $50M to acquire and rebuild the infrastructure to meet standards as well as requiring
the addition of a new substation to adequately serve these customers and other growth in the northeast corner of
the growth management area. A deferment of this annexation by a few years would relieve some of the potential
constraints on this fund.
Debt Analysis
Last Bond Rating: AA- (in 2021)
While operating revenues are intended to cover all operating expenses, debt issuances are an important source of
funding for capital investments for any utility. Debt issuances also establish generational equity by having the
generation of customers benefiting from the investment funding the investment through the debt repayment rather
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
2015 2016 2017 2018 2019 2020 2021
Light & Power Capital Spend and Year End Appropriations
Spent w/ System Additions
Spent w/o System Additions
YE Appropriations w/o System Additions
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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than having current customers pay for investments that are necessary to serve future generations. Given the
significant increase in capital investment that is expected over the next decade, significant levels of debt will be
necessary even after the use of all available reserves and anticipated development fees.
The long-term financial modeling relies on objective criteria to drive financial decisions such as when to issue
debt. The use of objective criteria allows for future debt issuances to be modeled and to provide clear reasoning
as to why an issuance is needed in any given year based on the current CIP. Debt issuances are based on the
following criteria.
1. If capital investments are anticipated to exceed available reserves over the next 3 years a debt issuance is
assumed to be sufficient to cover the next 2 years capital investments and leave 125% of the minimum
required reserve. This recommendation is presented to the Council Finance Committee ahead of the
biennial budget cycle.
2. Because there are costs associated with debt issuances a balance is struck between frequently issuing debt
and making efficient use of the generated capital by limiting the frequency of debt issuances to no more
than once every 3 years.
The electric utility had historically operated without any debt prior to 2010. While this was a very strong
financial position, it was one that resulted in cross generational subsidies as assets were bought by one generation
of ratepayers and then effectively used by subsequent generations of the community. This should be revisited
particularly when interest rates are extremely low which may not last much longer based on recent inflationary
pressures.
In 2010 this utility issued two revenue bonds totally $16M to receive a matching grant from the Department of
Energy for the deployment of advanced metering infrastructure. This debt was retired early in 2018 from reserves
to allow for the issuance of $142M in electric revenue bonds to support the ballet approved initiative to build
Connexion.
The existing debt was reviewed by Standard and Poor’s again in 2021 which reaffirmed the debt’s (AA-) bond
rating based on the realized electric revenues and financial outlook. The output from the long-term financial
model that is the basis of this plan was provided to the analysts for their revised bond rating. This modeling
indicates that based on the most recent CIP it will be necessary to issue debt likely in the 2023-24 budget cycle to
fund the anticipated $50M in capital investments over these two years. Given capital investment was $11M in
2021 with an additional $13M of work identified and funded at the end of 2021 before adding another $13M in
2022, it is recommended that resources are identified to complete this work before any debt is issued.
The chart below shows the historical and future debt related with electric capital investments including a potential
$41M issuance in the 2023-24 budget cycle. (This chart does not include the $130M outstanding debt related to
Connexion which is tied through the bond covenants to electric revenues.)
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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The debt coverage ratio for this Fund has been well above the bond covenant minimum requirements of 1.15-1.2
as well as above the internally recommended ratio of 2.0 necessary to be viewed as favorably as possible by the
rating agencies. This is true even when recognizing the debt associated with Connexion (although the chart below
does not include that debt).
The actual debt capacity for this utility Enterprise Fund is very large due to the large amount of revenues collected
from development fees as well as the utility’s operating income before depreciation. As such, any necessary debt
issuance is not expected to degrade the bond rating below the current (AA-) rating. The debt capacity of the
Enterprise Fund is limited by the outstanding debt held by PRPA as the rating agencies recognize the proportional
ownership of that debt by Fort Collins Utilities. The stochastic modeling assumes that future interest rates would
fluctuate within a range between 2.0 and 4.0%.
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
$40,000,000
$45,000,000
201120122013201420152016201720182019202020212022202320242025202620272028202920302031Outstanding Debt 2011 -2031
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
201120122013201420152016201720182019202020212022202320242025202620272028202920302031Debt Coverage Ratio
Debt Coverage Ratio
Recommended Minimum
Bond Covenant Minimum
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Reserves Analysis
Financial Management Policy 5 specifies Fund Balance Minimums for Enterprise Reserves. It also states that
additional reserves should be set aside for anticipated capital investments. The graph below reflects the total Fund
Balance as well as the portion of that balance that is available for capital appropriations above and beyond the
minimum required reserve balance and any existing capital appropriations. The long-term financial modeling
objectively determines when additional capital investment should come from Available Reserves and when it
should come through rates or more immediately through debt issuances.
Based on the strong revenues realized in 2021 that exceeded the budget by $12.0M along with operating expenses
being $6.4M below budget, it is estimated that over $18M was added to Available Reserves in 2021.
The available fund balance is expected to continue to increase due to positive operating income through the
necessary rate adjustments and operating expenses are limited in their year over year growth. This increased
Available Reserve balance will allow for more system renewal investments to be made without significant rate
increases in the future. The actual increase in Available Reserves reflected below is larger than recommended but
it is being driven by the timing of capital investments in the unprioritized CIP. A more strategic approach would
result in slightly lower rate increases and less debt issuances being needed to achieve the same capital
investments.
Debt Capacity Estimation
Interest Rate:3.00%
Net Pledged Revenue (5yr ave):$15,296,600
Debt Coverage
Ratio
Debt Capacity
(10 yr Debt)
Debt Capacity
(15 yr Debt)
Debt Capacity
(20 yr Debt)
1.0 $131 $183 $228
1.2 $109 $152 $190
1.4 $93 $130 $163
1.6 $82 $114 $142
1.8 $73 $101 $127
2.0 $65 $91 $114
2.2 $59 $83 $104
2.4 $54 $76 $95
2.6 $50 $70 $88
2.8 $47 $65 $81
3.0 $44 $61 $76
Outstanding Debt in 2021:$129.6 M
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
$70.0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Estimated$ Millions501 -Light & Power Fund
Fund Balances
AVAILABLE Fund Balances
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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In early 2022 it was determined that an additional $20M in funding was needed for Connexion to complete the
initial build-out of the fiber infrastructure. After consideration of several potential financing approaches including
issuing new debt, it was determined that use of Available Reserves within the shared enterprise fund was the best
approach. If a debt issuance is needed in this enterprise fund before this drawdown is covered by Connexion
revenues, Connexion will adhere to the terms of that issuance. If no such issuance is necessary, then Connexion
will compensate the electric utility for the lost interest it would have earned on the Available Reserves. This
intra-enterprise agreement will be presented for formal consideration by the City Council in March 2022. The
chart below reflects this anticipated arrangement being formally adopted at that time and reflects the anticipated
drawdown based on the most current financial modeling for Connexion and assumes all capital appropriations are
made as presented currently in the CIP.
(The graph below does not include the anticipated $18.0M addition to the Available Reserves from the positive
2021 financial performance because the modeling results discussed with the Council Finance Committee in
November 2021 assumed 2021 would be consistent with the budget only.)
Rate Analysis
Prior to the 2015-16 budget cycle rate adjustments were subjectively determined. Beginning with the 2015-16
budget cycle objective financial metrics were established to determine necessary rate adjustments. This change
allowed for future rate adjustments to be modeled and to provide clear reasoning as to why a rate adjustment is
needed in any given year. There are three financial metrics which drive a need for a rate adjustment.
1. Operating Income – If the combined operating income for the previous two years was negative, a rate
increase is made in the next year sufficient to generate enough operating income in the coming two years
to offset those losses. The two-year period allows for some weather or economic variability and is
consistent with the City’s biennial budget cycle.
2. Debt Coverage Ratio – A debt coverage ratio is recommended by the bond rating agencies to support the
current enterprise fund bond ratings. This debt coverage ratio is well above the minimum specified in the
bond covenants which could trigger bondholders to request a rate increase on their behalf. If the debt
$0
$10,000,000
$20,000,000
$30,000,000
$40,000,000
$50,000,000
$60,000,000
$70,000,000
201120122013201420152016201720182019202020212022202320242025202620272028202920302031Available Reserves 2011 -2031
Connexion Use of Reserves
Available Funds less Connexion
Available Funds less Connexion
AND No Debt Issuance
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
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coverage ratio is forecasted to drop below 2.0 in the coming year, a rate increase sufficient to raise the
debt coverage ratio to 2.1 is assumed in the financial modeling and is recommended to the Council
Finance Committee ahead of the biennial budget cycle.
3. Available Reserves – If an enterprise’s reserve balance is anticipated to drop below the minimum required
reserve level in the next year, a rate increase sufficient to maintain the minimum required reserve is made
at the beginning of that year in the financial modeling and is recommended to the Council Finance
Committee ahead of the biennial budget cycle.
The sum of these three rate adjustments is the needed rate adjustment for the following year. In addition to these
three objective criteria for rate adjustments, a 5.0% ceiling is imposed in any given year, consistent with the stated
objective of “gradual, modest rate adjustments”, which may require smoothing such an increase over the two
years of a budget cycle to not have a large rate increase one year and then no rate adjustment the next. These
same objective criteria are applied to the other 3 utility’s financial models.
For this enterprise fund there is also a need to adjust rates to offset any wholesale purchased power rate increases
from PRPA. As purchased power expenses are approximately 70% of annual operating expenses, 70% of any
wholesale rate increase is needed to be made to retail rates to offset this cost increase. This is included within the
5.0% rate ceiling.
The results of the financial modeling which applies the same objective strategies for raising rates and issuing debt
as the other utilities are presented below along with the forecasted debt issuance in 2023. This ten-year rate
forecast is shared with the community to be open and accountable to the ratepayers.
Modest rate adjustments will be necessary each year in the coming decade of approximately 2% to offset
anticipated PRPA wholesale rate increases toward their 100% renewable by 2030 goal. Additional rate increases
will be necessary for distribution investments as well.
Light & Power 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Rate Increase 2.0% 3.0% 4.1% 3-4% 3-4% 3-4% 2-3% 2-3% 2-4% 2-4%
Debt Issued ($M)$41.0
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%201120122013201420152016201720182019202020212022202320242025202620272028202920302031Rate Increases 2011 -2031
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
26 of 31
The rate structure for residential customers has changed twice in the past decade. In 2012, a three-tiered, seasonal
increasing block rate structure was adopted with the intent of encouraging energy conservation. This change from
a flat, non-seasonal rate structure was implemented along with an 8.3% rate increase which resulted in significant
community pushback that first year. The intent of the three-tiered residential rate structure was to promote energy
conservation. Based on analysis done in 2013 comparing weather normalized residential use in 2011 and 2012
there was no measurable change in energy consumption.
Then in 2015, after the deployment of the advanced metering infrastructure, a twelve-month rate pilot study was
done considering a seasonal, time-of-use residential rate as well as a seasonal, tiered, time-of-use residential rate.
The result of this pilot was the adoption of the seasonal, tiered, time-of-use residential rate for all customers
beginning in October of 2018. The result of this implementation was reviewed in 2019 and showed a statistically
significant reduction of 1.9% in total energy consumption as well as a statistically significant reduction in the
residential contribution to the coincident peak of 7.5%. Subsequent wholesale power increases have been less for
Fort Collins residents than in the other PRPA cities due to these reductions and the resulting load curve.
The chart below shows the weekday residential TOU rate schedule. Weekends and holidays are considered off-
peak.
In 2019 a pilot rate was implemented for low-income customers called the Income Qualified Assistance Program
(IQAP). This program is intended to reduce the utility burden for these customers to the same portion of
household income as a customer with the median area household income by providing a discount of almost 25%
on their electric, water and wastewater monthly charges. In 2021, IQAP customers average monthly electric bill
was $57.02 compared to other residential customers who paid $76.26 on average. It is expected that this pilot rate
will be formally adopted in the coming years.
(Insert a paragraph describing the solar adoption rate and the recent effort to have the cost of that excess solar
energy to come together in 2030 with the anticipated wholesale solar rate from PRPA.)
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
27 of 31
Financial Risk Assessment
Below is a list of identified financial risks for this utility. Each risk is preliminarily categorized as high, medium
or low according to both the likelihood and consequence of it being realized. Further assessment of these
financial risks, particularly with operational input, may change the likelihood and consequence of each and may
identify other significant financial risks. This additional assessment should be done as part of the biennial budget
cycle. These financial risks are associated with operational management and anticipated capital needs and
highlight the need for close collaboration between the financial and operational departments within Utilities as
well as the importance of having a refined, prioritized 10-year capital improvement plan rather than an a more
exhaustive list of potential capital needs that may or may not be necessary.
Risk RealizationRisk ID Risk Likelihood Consequence Mitigation Needed?Risk Description
LPFR1 CIP Volatility High High Yes
Long-term financial planning requires planning for uncertainties with more uncertainty requiring more conservative planning to achieve expected financial metrics; significant volatility on long-term capital plans increases uncertainty in the actual capital investment needs leading to inefficient use of capital, higher rate increases and less financial agility to meet operational needs
LPFR2 Undefined Service Level Metrics / Targets / Weights Medium High Yes
The impact of high CIP volatility can be lessened by optimizing such investments to meet expected levels of service through an objective, quantitative prioritization methodology based on predefined service level metrics with established targets and relative weights; not having these tools to optimize capital investment poses a significant financial risk to the utilityLPFR3Operating Expense Increases Medium High Yes OpEx assumed to not exceed 3.0%; exceedance would limit funds for capital needs and drive further rate increasesLPFR4PRPA 100 % by 2030 costs Medium Medium Beyond Control Wholesale increases are expected annually of 2-3% through 2030; higher increases will limit room for increases to meet distribution needs and contribute to rate fatigue
LPFR5 Retail Rate Fatigue Medium Medium Beyond Control Annual rate adjustments will be necessary to meet both wholesale and distribution needs; rate fatigue would require a financial reassessment of ability to meet operational targets
LPFR6 Mulberry Annexation Medium Medium Beyond Control The timing and how this annexation is implemented could result in costs being shared by all ratepayers and require investment on a schedule that may impact other planned capital investments
LPFR7 Unidentified Capital Projects Medium Low No As service level targets are established and asset management plans developed and Beneficial Electrification is implemented unanticipated capital needs may require more capital investment than currently plannedLPFR8Municipal Broadband Financial Support Low Medium No Any additional financial support from electric ratepayers will limit capital for L&P needsLPFR9System Reliability Low Low No A real or perceived decline in service reliability could accelerate system renewal investments and lead to less efficient use of capital
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan
28 of 31
Appendix A: Capital Improvement Plan
Below is a list of identified capital projects expected to be completed over the next decade. These projects are
grouped into the following categories:
System Additions – infrastructure that will be necessary to serve new growth areas
Substation Improvements – system renewal costs for substation infrastructure as well as an additional substation
to serve the northeast portion of the community
Transformers, Cables and Duct Banks – system renewal costs for existing distribution transformers, cables and
duct banks
Annexations – anticipated annexation areas will require acquisition of existing infrastructure from neighboring
utility providers as well as upgrading that infrastructure to the City’s standards
Technology and Other Improvements – improvements to existing buildings used to house staff and warehouse
stock as well as capital projects associated with updating / adopting new technologies
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan 29 of 31
501 - Light & Power Utility 10-Year CIP Funding Recommendation
Project Name 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
1680 Subdivision Construction
16800000 System Addition/Replacement $5,725,243 $5,700,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000
501001 Substations
501001A001 Battery Banks $20,000 $59,000 $20,000 $20,000
501001A002 Battery Chargers $40,000 $20,000 $40,000
501001A003 LTC (Load Tap Changer) Inspection and Repair $105,000 $105,000 $105,000 $105,000 $105,000
501001A004 Oil Containment Walls $70,000 $70,000 $70,000
501001A005 Replace HVAC Units $44,000 $44,000 $44,000 $22,000 $22,000 $22,000 $22,000 $22,000 $22,000
501001A006 Transformer Radiator Replacements $78,000 $103,000 $103,000 $78,000 $78,000 $78,000 $78,000
501001A009 Feeder Relay Replacements $189,000 $95,000
501001A011 Transformer Re-furbishing $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000
501001A012 Install Capacitor Banks $80,000 $80,000 $80,000 $80,000 $80,000
501001A013 Transformer Oil Filtration $170,000 $170,000 $85,000 $85,000 $85,000 $85,000 $85,000 $85,000 $85,000 $85,000 $85,000
501001A014 Substation Security $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000
501001A016 Install New 735 Power Quality Meters $13,000 $13,000 $13,000 $13,000 $13,000
501001A017 Substation Misc Capital $100,000 $100,000 $100,000 $60,000 $60,000 $60,000 $60,000 $60,000 $60,000 $60,000 $60,000
501001A018 Substation Basalite Walls $305,000 $594,000
501001A020 Equipment For CVR (Conservation Voltage Reduction)$75,000 $75,000
501001A021 PRPA Circuit Switcher Installations $40,000
501001A022 New Northeast Substation $6,649,200 $3,761,000 $0
501001A023 New Northeast Substation Land Acquisition $1,085,000
501005 Feeders
501005D004 Install circuit 936 to unload circuits 804, 834, and 906 $514,000
501005D011 Install circuit 324 to unload circuit 308 $1,040,000
501005D012 Install circuit 302 to serve Mulberry Annexation $2,160,000
501005D055 Circuit 602 to serve NE Developments - Ph3 Mt Vista $1,300,000
501005D060 Install circuit 624 to serve Developments in NE Ft. Collins $1,080,000
501005D076 Install circuit 706 to unload circuits 704 and 738 (see also 501005D079)$500,000
501005D077 Install circuit 322 to serve Mulberry Annexation $720,000
501005D078 Circuit 628 to serve NE developments - Ph1 Mt Vista $1,300,000
501005D079 Upgrade and Extend 722 to unload circuits 704 and 738 (See 501005D076)$1,050,000
501005D080 Extend East Vine Circuit 622 - Railroad to I25 $395,000
501005D081 Circuit 324 Carriage pky ph1 - Prospect to fox grove $220,000
501005D082 New Circuit 338 to serve Mulberry road developments $1,080,000
501005D083 Circuit - NE Sub Ckt 1 $528,000
501005D084 Circuit - NE Sub Ckt 2 $648,000
501005D085 Circuit - NE Sub Ckt 3 $628,800
501005D086 Circuit - NE Sub Ckt 4 $744,000
501005D087 Circuit - NE Sub Ckt 5 $744,000
501005D088 Circuit - NE Sub Ckt 6 $1,044,000
501005D089 Circuit - NE Sub Ckt 7 $888,000
501005D090 Circuit - NE Sub Ckt 8 $1,044,000
501005D091 Circuit - Timberline 338 extension $612,000
501008 Duct BanksSubstationsSystem AdditionsTransformers, Cables & Duct Banks
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan 30 of 31
501008D081 Duct Bank to serve NE FC Devel Ph 1 $1,102,200
501008D090 Duct Bank on Carriage Pkwy Phase 2 - Fox Grove to Forelock Dr (1X2 w/ 20% Contingency)$693,000
501008D091 Duct Bank on Carriage Pkwy Ph 3- Forelock Dr to Mulberry (1X2 w/ 20% Contingency)$140,000
501008D093 Duct Bank on Mulberry -Timberline to Carriage Pkwy (2X4 w/ 20% Contingency)$2,239,200
501008D094 Overland Trail Duct Bank Drake to Prospect (1X2 w/ 20% Contingency)$570,000
501008D095 Duct Bank Extend East Vine Circuit 622 - Railroad to I25 $825,000
501008D096 Duct Bank on Carriage Pkwy Phase 1 - Prospect to Fox Grove $693,000
501008D097 Duct Bank - NE circuit 1 & 2 $352,800
501008D098 Duct Bank - NE circuit 3 $2,376,000
501008D099 Duct - Timberline 338 Extension $1,368,000
501012 System Cable Replacements
501012C009 CAPITAL - Replacement Area 9 - Valley Hi $149,000
501012C012 CAPITAL - Replacement Area 12 - Woodlands PUD $86,000
501012C013 CAPITAL - Replacement Area 13 - Village West 9th $207,000
501012C016 CAPITAL - Replacement Area 16 - Parkwood East $130,000
501012C017 CAPITAL - Replacement Area 17 - Trail West PUD $182,000
501012C018 CAPITAL - Replacement Area 18 - Edora Acres $101,000
501012C019 CAPITAL - Replacement Area 19 - Evergreen Park $69,000
501012C020 CAPITAL - Replacement Area 20 - The Ridge PUD $117,000
501012C021 CAPITAL - Replacement Area 21 - West Azalea $32,000
501012C022 CAPITAL - Replacement Area 22 - Larkborough $131,000
501012C023 CAPITAL - Replacement Area 23 - Village West 3rd $84,000
501012C024 CAPITAL - Replacement Area 24 - Wagon Wheel $66,000
501012C025 CAPITAL - Replacement Area 25 - Brown Farm 4th $58,000
501012F020 Cable Replacements - Ongoing $690,000 $690,000 $690,000 $690,000 $690,000 $690,000 $690,000 $690,000 $690,000
501012F021 Feeder Cable Replacements - Ongoing $230,000 $230,000 $230,000 $230,000 $230,000 $230,000 $230,000 $230,000 $230,000 $230,000 $230,000
501014 Transformers
501014F022 Distribution Transformer Purchases & Replacements $792,811 $1,041,257 $795,000 $795,000 $795,000 $795,000 $795,000 $795,000 $795,000 $795,000 $795,000
501004 Annexations
501004C005 Clydesdale Park First & Second Annexations $1,011,000
501004D001 Miller Enclave $277,000
501004D002 Mulberry Enclave $324,000 $6,529,000 $4,322,500 $4,322,500 $4,322,500 $7,551,700 $7,551,700 $7,551,700 $10,572,000
501004D003 East Horsetooth (PVREA) Enclave
501004D003 East Horsetooth (Xcel) Enclave
501004D004 Taft Hill & Harmony Enclave
501004E001 PVREA GMA Area
501004E002 Xcel GMA Area
501002 Service Center
501002B003 Cable Handling Facility for Cut-To-Length Program $1,575,000
501002B004 700 Wood Street Backup Power and Dual Feed ATO $519,000
501002B005 Overland Disaster Recovery Site for SCO $450,000
501002B006 Warehouse Storage Yard Covered Structure $199,000
1940 Minor Capital - Vehicles & Equipment
19400000 Minor Capital - Vehicles & Equipment $929,000 $625,000 $625,000 $625,000 $625,000 $625,000 $625,000 $625,000 $625,000 $625,000 $625,000
501009 CMMS–Maintenance ManagementAnnexationsTransformers, Cables & Duct BanksTechnology and Other
City of Fort Collins Utilities 2022 10-Year Light & Power Strategic Financial Plan 31 of 31
501009G002 Operational Technology - Maximo $300,000
501015 Streetlights
501015F023 Streetlight System Replacement $986,866 $986,866 $986,866 $986,866 $986,866 $986,866 $100,000 $100,000 $100,000 $100,000 $100,000
501015G009 LED Streetlight Control and Automation $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000 $120,000
501016 Distribution Automation
501016G010 Distribution Automation/FLISR $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000
501017 System Relocations
501017J001 System Relocations - Road & Intersection Projects $230,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000 $250,000
501025 Advanced Metering Infrastructure
501025G004 AMI Equipment and Tech Upgrade $650,300 $664,000 $10,700 $10,700 $10,700 $10,700 $10,700 $10,700 $10,700 $10,700 $10,700
501025G005 AMI Wide Area Network (WAN)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
501025G006 AMI Backhaul Network Hardware Tech Refresh $0 $234,600 $42,650 $112,000
501025G007 AMI Test Network Expansion $191,900
501025G008 AMI New Technology Testing and Miscellaneous Capital $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 $100,000
501026 Demand Respond Technology Upgrade
501026G013 Energy Services Peak Partners - DCU3 Refresh $435,500
501026G014 Energy Services Peak Partners - GIWH $0 $1,402,500 $1,402,500 $1,402,500 $1,402,500 $1,402,500 $1,402,500 $1,402,500 $1,402,500 $1,402,500 $1,402,500
501026G015 Energy Services Peak Partners - EVSE $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000
501026G016 Energy Services Peak Partners - PRO1 Thermostat Sunset $200,000
501026G017 Energy Services Peak Partners - Inverter Supervision & Control $250,000
501013 Operational Technology
501013G001 ADMS Strategic Upgrades - Business Releases 3-6 $450,000 $580,000 $970,106 $660,951 $714,254 $351,797
501013G003 eSCADA Hardware/Software $74,624 $74,624 $74,624
501013G011 Radio System Upgrades $0 $628,970 $42,642 $42,642 $42,642 $42,642 $42,642 $42,642 $42,642 $42,642 $42,642
501013G012 GPS & Underground Facilities Visualization $127,926
501013G014 L&P/Energy Services Systems Alignment $106,605 $106,605 $106,605
501013G015 Utility Scale Energy Storage $150,000 $2,000,000 $2,000,000 $2,000,000 $2,000,000
Utility Billing System Upgrade $4,000,000
Total $17,326,344 $28,838,521 $21,903,168 $25,160,114 $21,266,262 $19,469,208 $21,128,142 $23,690,339 $21,200,542 $21,185,542 $22,486,842Technology and Other
Learn more ways to manage your energy at fcgov.com/conserve
How do you fit in?
COMMUNITY ENERGY USE SNAPSHOT
Per capita reductions from 2005
Building square footage
increased by 24%,
but buildings are 11%
MORE EFFICIENT.
SINCE 2005
29%POPULATION INCREASED14%ENERGY USE INCREASED ONLY Thanks to residents and businesses improving
eciency and practicing conservation.ELECTRICITY17%Electricity use
per capita is the
lowest it’s been
since 1986.
2022 Community Energy Report
Together, we are achieving results in eciency, renewables and grid flexibility to reach our goals
and transform community energy systems.
Our Climate Future expresses a vision for sustainability by achieving our climate, energy and waste goals while
improving our community's equity and resilience. This annual update includes gains made towards meeting 80%
carbon reduction and 100% renewable electricity by 2030. More information on Our Climate Future can be found
at fcgov.com/OurClimateFuture.
OUR IMPACT
Despite a growing population, eciency
programs have helped limit the increase
in electricity use. It would be 22% higher
without Utilities’ programs.
Utilities
Actual Community
Electricity Use
Residential Eciency Savings:
87M kWh
Business Eciency Savings:
260M kWh
Fort Collins is designated a Smart Energy Provider
by the American Public Power Association.NATURAL GAS12%8%PETROLEUMSaved Electricity from Eciency
2005
2022
2010
2015 2020
Business Eciency Savings:
260M kWh
Grid Flexibility
With Peak Partners, customers reduced electric
demand by 1,800 kW during peak times,
helping the entire grid. Peak Partners customers
can shift their usage to o peak times, some
saving 30% on the water heating portion of
their bill.
The average residential
customer uses about 614
kWh per month
(or 7,368 kWh per year).
Auxiliary aids and services are available for persons with disabilities.
Esta informacin puede ser traducida, sin costo para usted. 970-212-2900 23-25342
X 100
Customer electricity savings from programs
totaled 48M kWh (almost 3% of the community's
annual use), equivalent to the electric use of
6,400 homes.
Energy Savings
Reliability
With 99.9958% reliability, most residents
did not experience an outage.
Community Economics
Customer projects
generated more than $47M
in local economic benefits
through reduced utility bills,
direct rebates and
leveraged investments, and
also supported 219+ jobs.
Did you Know?
As our energy mix
adds more renewables,
going electric in our
homes and businesses
becomes an essential
solution to addressing
the climate emergency.
Local Renewables
Installed 460 new renewable energy
systems, adding 5,700+ kW.
There are now 3,120+
solar systems in the
community that provided
2.6% of our electricity.
Our Climate Future is all about making Big Moves towards
goals like 100% renewable electricity and ecient,
emissions-free buildings. See how you can make your own
big moves at fcgov.com/OurClimateFuture.
Our Power Sources Are Shifting
LOOKING FORWARD
Our Climate Future
DOWN 41%from 2005
Electricity Carbon Emissions
Peak Usage
One in five customers are
adjusting their thermostat
for summer peak periods.
2030 Goal: 100% RENEWABLE
About 65% of residential customers
showed a decrease in annual electric
bills with TOD pricing.
2005
76% Fossil Fuels
22% Hydro
2% Wind
0% Solar
2022
31% Wind
6% Solar
51% Fossil Fuels
12% Hydro
Our Climate Future Metrics Dashboard Update
08-10-2023John Phelan, Energy Services Manager
2
Agenda
Our Climate Future and (Loran) Framework
Reporting methods and timelines
Available metrics
Framework sections
Discussion
3
2022 Energy Reporting
4
Our Climate Future Goals
•Primary
-Community Carbon: Reductions of 50% by 2026, 80% by 2030
(2005 baseline)
-100% renewable electricity by 2030 (5% from local sources)
•Additional
-Achieve a 20% reduction in forecast electricity (2021 to 2030)
-Annual reliability metrics of:
–Customer Average Interruption Duration Index (CAIDI) less than 45 minutes
–System Average Interruption Duration Index (SAIDI) less than 30 minutes
–System Average Interruption Frequency Index (SAIFI) is less than 0.66
annually
-Achieve a 10% reduction in forecast natural gas use (2021 to 2030)
-Adopt and enforce updated energy codes on a three-year cycle
-Achieve bidirectional demand flexibility capacity of 5% of peak loads by 2030
Learn more at https://www.fcgov.com/climateaction/about-ocf
5
Energy Board Framework (Loran)
≠
6
Energy Board Framework (Loran)
Objective: identify forecast of metric results
7
Reporting Availability and Timeline
•Primary
-Community Carbon Annual (mid-year)
-Percent renewable electricity Annual (mid-year)
-Percent local renewable electricity Annual (mid-year)
•Additional
-Cumulative electricity savings Annual (mid-year)
-Reliability metrics CAIDI, SAIDI, SAIFI Quarterly (rolling)
-Cumulative gas savings Annual (mid-year)
-Demand flexibility capacity Annual (mid-year)
8
Combined Metrics and Framework
Percent renewable Community Carbon CAIDI, SAIDI, SAIFI
Percent local renewable Cumulative electricity savings
Cumulative gas savings
9
Combined Metrics and Framework
Misalignments
1.Grid flexibility target is not represented
2.Pricing boundary is not a Council policy
10
Combined Metrics and Framework
Misalignments
3.Community carbon goal and “electrification”
-Carbon goal has many factors and interactions
-Annual gas, ground travel and IPPU inventory components track the
primary outcomes (beyond electricity)
11
Energy Board Framework (Loran)
Discussion
•Should not ignore Platte River; 88% not RE metric
•Have metrics for local electricity (MWh and MW capacity)
12
Energy Board Framework (Loran)
Discussion
•Very useful breakdown; “YOU ARE HERE”
•We do not have a model for all the components
13
Energy Board Framework (Loran)
Discussion
•Clear connection to asset management, grid flexibility and pricing
•We do not have a model for all the components
•Historically discussed as a boundary condition
14
Energy Board Framework (Loran)
Discussion
•Utilities has control over about 1/3 of cost components
•Historically discussed as a boundary condition
15
Discussion
Discussion – What is helpful to the board and council?
•Do these four categories capture the right information?
•We have tracking metrics for all; we have forward metrics for some
•Most have only annual results