HomeMy WebLinkAboutPACKET Town Board 2020-08-25(Instructions continued on page 2, Agenda begins on page 3)
The Mission of the Town of Estes Park is to provide high-quality, reliable services
for the benefit of our citizens, guests, and employees, while being good stewards
of public resources and our natural setting.
The Town of Estes Park will make reasonable accommodations for access to Town services,
programs, and activities and special communication arrangements for persons with disabilities.
Please call (970) 577-4777. TDD available.
BOARD OF TRUSTEES – TOWN OF ESTES PARK
TO BE HELD VIRTUALLY
Tuesday, August 25, 2020
7:00 p.m.
Board Room – 170 MacGregor Avenue
Estes Park, CO 80517
The Town Board of Trustees will participate in the meeting remotely due to the Declaration of
Emergency signed by Town Administrator Machalek on March 19, 2020 related to COVID-19 and
provided for with the adoption of Ordinance 04-20 on March 18, 2020. Procedures for quasi-judicial
virtual public hearings are established through Emergency Rule 06-20 signed by Town Administrator
Machalek on May 8, 2020 and outlined below.
ADVANCED PUBLIC COMMENT
Options for the Public to Provide Public Input:
1. By Public Comment Form: Members of the public may provide written public comment on a
specific agenda item by completing the Public Comment form found at
https://dms.estes.org/forms/TownBoardPublicComment. The form must be submitted by 12:00 p.m.,
Tuesday, August 25, 2020. All comments will be provided to the Board for consideration during the
agenda item and added to the final packet.
2. By Telephone Message: Members of the public may provide public comment or comment on a
specific agenda item by calling (970) 577-4777. The calls must be received by 12:00 p.m., Tuesday,
August 25, 2020. All calls will be transcribed and provided to the Board for consideration during the
agenda item and added to the final packet.
PUBLIC PARTICIPATION DURING BOARD MEETING
Options for participation in the meeting will be available by call-in telephone option or online via Zoom
Webinar which will be moderated by the Town Clerk’s Office.
CALL-IN (TELEPHONE OPTION):
Dial public participation phone number, 1-346-248-7799
Enter the Meeting ID for the August 25, 2020 meeting: 982 1690 2040 followed by the pound
sign (#). The meeting will be available beginning at 6:30 p.m. the day of the meeting. Please
call into the meeting prior to 7:00 p.m., if possible. You can also find this information for
participating by phone on the website at www.estes.org/boardsandmeetings by clicking on
“Virtual Town Board Meeting Participation”.
Request to Speak: For public comment, the Mayor will ask attendees to indicate if they
would like to speak – phone participants will need to press *9 to “raise hand”. Staff will be
moderating the Zoom session to ensure all participants have an opportunity to address the
Board.
Once you are announced by phone:
State your name and address for the record.
DO NOT watch/stream the meeting at the same time due to streaming delay and
possible audio interference.
Prepared 08-14-2020
*Revised
Page 1
NOTE: The Town Board reserves the right to consider other appropriate items not available at the time the agenda was
prepared.
PUBLIC PARTICIPATION (ONLINE):
Individuals who wish to address the Board via virtual public participation can do so through
Zoom Webinar at https://zoom.us/j/98216902040 – Zoom Webinar ID: 982-1690-2040. The
Zoom Webinar link and instructions are also available at www.estes.org/boardsandmeetings
by clicking on “Virtual Town Board Meeting Participation”. Individuals participating in the
Zoom session should also watch the meeting through that site, and not via the website, due
to the streaming delay and possible audio interference.
Start Time: The Zoom Webinar will be available beginning at 6:30 p.m. on the day of the
meeting. Participants wanting to ensure their equipment setup is working should join prior to
the start of the meeting at 7:00 p.m.
Request to Speak: For public comments, the Mayor will ask attendees 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.
You will experience a short delay prior to re-connecting with the ability to speak.
State your name and address for the record.
In order to participate, you must:
Have an internet-enabled smartphone, laptop or computer.
o Using earphones with a microphone will greatly improve your audio experience.
Join the Zoom Webinar.
o The link can be found above.
Click “Participate Virtually in the Regular Town Board Meeting of the Board of
Trustees”.
DO NOT watch/stream the meeting via the website at the same time due to delays and
possible feedback issues.
WATCH THE MEETING:
The Town Board meetings will be livestreamed at www.estes.org/videos and will be posted within 48
hours of the meeting at the same location.
Documents to Share: If individuals wish to present a document or presentation to the
Board, material must be emailed by Monday, August 24, 2020 by 8:00 a.m. to the Town
Clerk’s office at townclerk@estes.org.
Quasi-Judicial Proceedings
(Quasi-Judicial items will be marked as such)
Written Testimony
Must be submitted by mail to Town Clerk, PO Box 1200, Estes Park, CO 80517 or by
completing the Public Comment form at
https://dms.estes.org/forms/TownBoardPublicComment.
Members of the public may provide public comment or comment on a specific agenda item by
calling (970) 577-4777. All calls must be received by 8:00 a.m., Monday, August 24, 2020.
All comments received will be provided to the Board and included in the final packet material.
Oral Testimony
To ensure your ability to provide comments during the meeting, you must register by emailing
townclerk@estes.org or calling (970) 577-4777 by Monday, August 24, 2020 at 5:00 p.m.
During the meeting, any individual who did not register to speak on a quasi-judicial item may
join public participation by following either the Call-In or Online option previously mentioned.
Individuals who do not register prior to the meeting risk being unable to testify due to
administrative/technical difficulty during the meeting.
Written presentation materials or exhibits must be delivered to townclerk@estes.org by 8:00
a.m. Monday, August 24, 2020 in order to be presented during the meeting. No other written
presentations or exhibits will be accepted during oral testimony by any member of the public.
Packet Material
The packet material can be accessed through the following link: Town Board Packet or under
the Town Board section at www.estes.org/boardsandmeetings or you may request a paper
packet by emailing townclerk@estes.org or calling (970) 577-4777.
Page 2
NOTE: The Town Board reserves the right to consider other appropriate items not available at the time the agenda was
prepared.
AGENDA
BOARD OF TRUSTEES – TOWN OF ESTES PARK
Tuesday, August 25, 2020
7:00 p.m.
PLEDGE OF ALLEGIANCE.
(Any person desiring to participate, please join the Board in the Pledge of Allegiance).
PROCLAMATION – 100TH ANNIVERSARY OF THE PASSAGE OF THE 19TH AMENDMENT.
PROCLAMATION – CONSTITUTION WEEK.
AGENDA APPROVAL.
PUBLIC COMMENT. (Please state your name and address).
TOWN BOARD COMMENTS / LIAISON REPORTS.
TOWN ADMINISTRATOR REPORT.
CONSENT AGENDA:
1. Bills.
2. Town Board Minutes dated August 11, 2020 and Town Board Study Session Minutes
dated August 11, 2020.
3. Estes Park Planning Commission Minutes dated June 16, 2020 and Study Session
Minutes dated July 21, 2020 (Acknowledgement only).
4. Family Advisory Board Minutes dated July 2, 2020 (Acknowledgement only).
ACTION ITEMS:
1. PUBLIC HEARING - ORDINANCE 11-20 PROPOSED ELECTRIC RATE INCREASE:
Director Bergsten.
Present the electric rate study results.
Continue Public Hearing and Board Action to September 8, 2020 allowing for
additional public comment.
ADJOURN.
Prepared 08-14-2020
*Revised
Page 3
Public Trustee <publictrustee@estes.org>
Re: Liaison report for Board meeting: Word Product private
1 message
Marie Cenac <mcenac@estes.org>Tue, Aug 25, 2020 at 3:42 PM
To: Wendy Koenig <wkoenig@estes.org>
These are the opinions of Western Heritage Membership Committee liaison, Marie Cenac, Estes Park Town Trustee.
Transparency and good governance are priorities of the Estes Park Town Board and Town Administration. We also
demand that our volunteers be appreciated and treated fairly. We should expect the same for the organizations with
which we have close financial and working ties.
Western Heritage is the current organization sharing a MOU with the Town of Estes Park which describes the utilization of
our staff and our facilities in order to operate the town owned Roottop Rodeo with the majority of the financial commitment
being from tax payer monies. I feel that the town needs more transparency and accountability from Western Heritage
through better checks and balances. The current MOU, with the deadline of cancellation being September 1st, needs to
have those in place before it automatically renews.
According to the bylaws there is an election slated for their annual meeting dated for the third Thursday of September.
Although COVID has had its impact, it was communicated that the election would go on, as stated in those bylaws, thru
an email to both of the boards. It is required to call for nominations from the membership committee 30 days prior to that
annual meeting. To this date, there has been no call for nominations nor discussions, with the committee, as to how that
meeting could work, whether it be outdoors in groups or held virtually.
I feel that the Town Board of Estes Board, or its representative, should only consider signing any MOU with Western
Heritage once that election has been fulfilled in accordance to their own bylaws and that members are given a fair chance
to be elected to that board.
I am very concerned for the future of the the Town of Estes Park's Rooftop Rodeo and the wonderful group of dedicated
hardworking volunteers of the Western Heritage Committee and its board members if circumstances remain the same.
These recommendations should only be the first steps taken in order to help our relationship with the Western Heritage
organization move onto a healthier path.
Marie Cenac
Town of Estes Park Board of Trustee
On Tue, Aug 25, 2020, 2:24 PM Wendy Koenig <wkoenig@estes.org> wrote:
Hi Marie. Nothing received yet......Wendy
Sent from my iPhone
Town of Estes Park, Larimer County, Colorado, August 11, 2020
Minutes of a Regular meeting of the Board of Trustees of the Town of Estes
Park, Larimer County, Colorado. Meeting held in the Town Hall and Virtually in
said Town of Estes Park on the 11th day of August, 2020.
Present: Wendy Koenig, Mayor
Patrick Martchink, Mayor Pro Tem
Trustees Carlie Bangs
Marie Cenac
Barbara MacAlpine
Scott Webermeier
Cindy Younglund
Also Present: Jason Damweber, Assistant Town Administrator
Dan Kramer, Town Attorney
Jackie Williamson, Town Clerk
Absent: Travis Machalek, Town Administrator
Mayor Koenig called the meeting to order at 7:00 p.m. and all desiring to do so, recited
the Pledge of Allegiance.
AGENDA APPROVAL.
It was moved and seconded (Martchink/Cenac) to approve the Agenda as presented,
and it passed unanimously.
PUBLIC COMMENTS.
None.
TRUSTEE COMMENTS.
Trustee Younglund attended the Family Advisory Board (FAB) where they defined family
and identified the barriers to success, which are the same for both families and other
members of the community. The FAB would continue to develop funding guidelines and
an application process for childcare.
Mayor Koenig stated PRPA discussed the ability to shut down the coal fire plants prior to
2030 and determined it would be difficult to meet customer needs any earlier.
Trustee MacAlpine commented the Board of Adjustment met and approved a variance to
build six Habitat for Humanity homes located off of Raven Avenue. She joined a hike with
the Land Trust of the Thumb property being acquired to enhance the open space of the
valley.
Trustee Cenac attended the Visit Estes Park monthly meeting where it was announced
Trustee Webermeier would replace Mayor Koenig on the Board. RMNP Public Affairs
Officer Patterson provided an update on park activities, including time entry process,
alluvial fan trail improvements, increase in visitors prior to the timed entry, the need for
changes to the time entry during the rut this fall, and the closure of Fall River Road in
October for repairs. The 2% sales tax funding VEP has seen a 25% decrease in returns.
Accommodations have experienced an increase in last minute bookings in 2020.
TOWN ADMINISTRATOR REPORT.
None.
1. CONSENT AGENDA:
1. Bills.
2. Town Board Minutes dated July 28, 2020 and Town Board Study Session Minutes
dated July 28, 2020.DRAFTPage 5
Board of Trustees – August 11, 2020 – Page 2
3. Estes Park Board of Adjustment minutes dated June 2, 2020 (Acknowledgement
only).
4. Revised Policy 101 Division of Responsibilities – Revise appointments with the
appointment of Trustee Webermeier.
5. Revised Policy 306 Leave - Amending Holidays Observed and Floating Holidays.
It was moved and seconded (Cenac/Younglund) to approve the Consent Agenda,
and it passed unanimously.
2. PLANNING COMMISSION ITEMS:
1. ACTION ITEMS:
A. RESOLUTION 53-20 ELKHORN LODGE FINAL SUBDIVISION PLAT, 600
WEST ELKHORN AVENUE, ZAHOUREK CONSERVANCY, LLC, OWNER,
EAST AVENUE DEVELOPMENT, LLC, A TEXAS LLC, C/O JUSTIN MABEY,
APPLICANT. (Quasi-Judicial) Mayor Koenig opened the public meeting.
Planner Woeber reviewed the application requesting approval of a final plat for
the Elkhorn Lodge PUD consisting of 13 lots, with lots ranging from 0.276 to
3.291 acres in size. The preliminary plat was approved by the Town Board on
June 23, 2020.
Bill Kiefer/Elkhorn Condominium owner requested the lighting be addressed
within the development to ensure it meets dark sky lighting requirements of the
Development Code. Justin Mabey/Applicant stated the development’s intent
would be to meet the requirements and keep the lighting to a minimum. He
also stated additional shrubbery has been placed between the river and the
restaurant and parking lot to preserve the river atmosphere.
Mayor Koenig closed the public hearing. It was moved and seconded
(Younglund/Bangs) to approve Resolution 53-20 for the Elkhorn Lodge
Final Plat according to findings of fact with the findings and conditions
of approval recommended by staff, and it passed unanimously.
B. RESOLUTION 54-20 ELKHORN LODGE FINAL PLANNED UNIT
DEVELOPMENT (PUD), 600 WEST ELKHORN AVENUE, ZAHOUREK
CONSERVANCY, LLC, OWNER, EAST AVENUE DEVELOPMENT, LLC, A
TEXAS LLC, C/O JUSTIN MABEY, APPLICANT. (Quasi-Judicial) Mayor
Koenig opened the public hearing. Planner Woeber stated the 13 lot PUD
zoned CO Commercial Outlying would contain a variety of commercial,
accommodation and residential uses. The preliminary PUD was approved by
the Town Board on June 23, 2020. Mayor Koenig closed the public hearing. It
was moved and seconded (Younglund/Cenac) to approve Resolution 54-20
for the Elkhorn Lodge Final PUD according to findings of fact with the
findings and conditions of approval recommended by staff, and it passed
unanimously.
3. REPORT AND DISCUSSION ITEMS:
1. CONTINUED DISCUSSION ON OPEN CONTAINERS. Assistant Town
Administrator Damweber summarized the discussions at the Town Board Study
Session on June 23, 2020 and the Town Board meeting on July 14, 2020. The
Board tabled the discussion until the full Board could be present for the discussion
due to the resignation of Trustee Zornes and appointment of Trustee Webermeier.
Discussion amongst the Board has been summarized: Questioned if allowing
open containers in downtown parks would encourage gathering for more than 10
minutes; concerned with gatherings and the need for an increase in enforcement
efforts by the Police Department; suggested the Board could consider open
containers downtown from 6 pm to 9 pm; the local restaurants are able to seat
people and relaxing the open containers law does not have the same impact as
this spring when the businesses were closed; the item should be tabled and DRAFTPage 6
Board of Trustees – August 11, 2020 – Page 3
reviewed in the future; and businesses are not requesting the change at this time.
The Board consensus was to table the issue.
Whereupon Mayor Koenig adjourned the meeting at 7:46 p.m.
Wendy Koenig, Mayor
Jackie Williamson, Town Clerk DRAFTPage 7
Town of Estes Park, Larimer County, Colorado August 11, 2020
Minutes of a Study Session meeting of the TOWN BOARD of the Town of
Estes Park, Larimer County, Colorado. Meeting held at Town Hall in the
Board Room and Virtually in said Town of Estes Park on the 11th day of
August, 2020.
Board: Mayor Koenig, Mayor Pro Tem Martchink, Trustees Bangs,
Cenac, MacAlpine, Webermeier and Younglund
Attending: Mayor Koenig, Mayor Pro Tem Martchink, Trustees Bangs,
Cenac, MacAlpine, Webermeier and Younglund
Also Attending: Assistant Town Administrator Damweber, Town Attorney
Kramer, Director Hunt and Recording Secretary Beers
Absent: Town Administrator Machalek
Mayor Koenig called the meeting to order at 5:30 p.m.
STANLEY HISTORIC DISTRICT OVERVIEW.
Director Hunt provided an overview of the Stanley Historic District. Highlights of the
overview included: history, structure and process for land-use regulation, litigation over
the years and five sets of regulations unique to the Stanley. Current use includes, hotel,
restaurants/bars, performance hall, wedding/event venue, and special events. In 1994
the Stanley Historic District Master Plan was adopted along with development
agreements for lots undeveloped in the subdivision. This was the same year the
property was purchased by the current owner, John Cullen. Director Hunt presented
plats of the Stanley area and reviewed specifics of the Master Plan and Stanley Historic
District structure. Town Attorney Kramer stated the Development Agreements signed
created vested rights establishing development through the guidelines of the Master
Plan. He stated the agreement for Lot 4 expired while the others rights remain in effect.
Director Hunt stated Lots 5, 6, and 8 are owned by the Town of Estes Park and held in a
conservation easement managed by the Land Trust. The Colorado Historic Foundation
manages the open space on Lot 1 and keeps informed on Stanley projects. Director
Hunt stated the Technical Review Committee (TRC), comprised of five members
including three staff appointed by the Town Administrator and two outside design
professionals provided by the Stanley, reviews major projects on the property. Building
permits for the Stanley projects do not follow special process rules, nor do they have
non-standard Building Code requirements or regulations. He added building permits and
plan review on many Stanley properties have been complex and difficult in recent years,
requiring multiple permits per project, and “partial” Certificates of Occupancy. He stated
this was primarily due to buildings predating the current codes. The Stanley main
campus developments traditionally have not gone to the Planning Commission, and
parking lots and parking changes on the main campus have gone straight to building
permit review. The Board questioned the maze being allowed on the southern side of
the Stanley Hotel which is prohibited in the Master Plan. He stated there are future
plans for the Stanley property noting the only proposal under TRC review is the
Carriage House scheduled for August 24, 2020.
TRUSTEE & ADMINSTRATOR COMMENTS & QUESTIONS.
None. DRAFTPage 8
Town Board Study Session – August 11, 2020 – Page 2
FUTURE STUDY SESSION AGENDA ITEMS.
Assistant Town Administrator Damweber requested Board interest to discuss Family
Advisory Board recommendations and childcare funding guidelines and it was
determined staff would bring more information to the Board for further discussion.
There being no further business, Mayor Koenig adjourned the meeting at 6:31 p.m.
Bunny Victoria Beers, Recording Secretary DRAFTPage 9
Page 10
RECORD OF PROCEEDINGS
Estes Valley Planning Commission
June 16, 2020
Board Room, Estes Park Town Hall
1
Commission: Acting Chair Matt Comstock, Commissioners Steve Murphree, Joe
Elkins, Matthew Heiser, Howard Hanson
Attending: Acting Chair Comstock, Commissioners Murphree, Elkins, Heiser,
Hanson
Also Attending: Director Randy Hunt, Senior Planner Jeff Woeber, Planner II Alex
Bergeron, Recording Secretary Karin Swanlund, Town Board Liaison
Barbara MacAlpine, Town Attorney Dan Kramer
Absent: None
OPEN MEETING
Acting Chair Comstock called the meeting to order at 1:30 p.m. The meeting was held
virtually via Google Meet and live-streamed on YouTube and Viebit.
APPROVAL OF AGENDA
It was moved and seconded (Heiser/Hanson) to approve the agenda and the
motion passed 5-0.
PUBLIC COMMENT:
None
CONSENT AGENDA
1. Study Session Minutes dated May 19, 2020
It was moved and seconded (Heiser/Elkins) to approve the consent agenda as
presented and the motion passed 5-0
ELECTION OF OFFICERS
Acting Chair Comstock agreed to continue as Chair. Commissioner Heiser
accepted the position of Vice Chair.
It was moved and seconded (Hanson/Heiser) to approve Matt Comstock as Chair for
the remainder of the year. The motion passed 4-0. (Murphree unavailable)
It was moved and seconded (Comstock/Elkins) to approve Matthew Heiser as Vice
Chair for the remainder of the year. The motion passed 4-0. (Murphree unavailable)
Page 11
RECORD OF PROCEEDINGS
Estes Valley Planning Commission
June 16, 2020
Board Room, Estes Park Town Hall
2
ACTION ITEMS
1. LOCATION AND EXTENT, TOWN OF ESTES PARK WATER DIVISION PHASE 1,
1360 BROOK DRIVE
Director Hunt explained to the Commission what a Location and Extent review is. He then
reviewed the staff report, which was prepared by Ayres Associates. The property is 5.6
acres of land, zoned I-1-Restricted Industrial, and is developed with a two-story building
and accessory buildings. Phase I will entail several interior improvements to the main
building, including the installation of a new automatic fire sprinkler and alarm system along
with an interior remodel. This phase will also include grading for the access drive and 16
parking spaces. Drainage and wildlife reports were submitted. Staff recommended
approval of the Location and Extent Review, with the possibility of some additional
landscaping along the Brook Drive boundary.
Commission Comments/Questions with Responses from Town Water
Superintendent Chris Eshleman and Engineer David Bangs, and Director Hunt: the
following is a summary of the Location and Extent discussion.
• Chapter 3 states that development plans should be submitted: Chapter 7 is the
yard-stick measure. The Planning Commission does not have to be the body to
review the development plan.
• Primary access is off of Acacia, not Brook Drive: Plans were routed to the Fire
Department and LETA, but LETA rarely reviews Location and Extent. The primary
access will be most likely be on the lower portion of the lot.
• Gravel drives have been considered to not be impervious in the past. Will this make
the 80% coverage: Gravel is regarded to be an impervious surface per chapter 13
definition. (recommended that this should be revisited with a code amendment)
• Sidewalk requirements: Kearney & Sons Excavating installed a sidewalk between
Brook and Acacia. A water main will cross Brook Drive and the sidewalk will be
completed when that is finished.
• Geologic hazards and riparian mark: The line of plants along the right-hand sign of
Fish Creek shows delineated limits of the flood plain. The fence along this line is a
visual block.
• Increased Water run-off to Brook Drive due to the 16 vehicle parking lot: The design
of asphalt makes the run-off an improvement over gravel. The grade of the site
has the run-off draining into Fish Creek.
• Privacy Fence: Planned installation before Phase II along Fish Creek Road.
Currently, the County is using the site for storage until their rebuild on Elm Road is
completed. This being an industrial site, there will be piles of dirt, pipes and
vehicles, but the applicant plans on being a good neighbor.
Page 12
RECORD OF PROCEEDINGS
Estes Valley Planning Commission
June 16, 2020
Board Room, Estes Park Town Hall
3
• Landscaping Plan along the residential side of Brook and Acacia? There are lilac
bushes above Brook Court and existing trees along Fish Creek. Applicant is open
to other landscaping ideas but contends this is an industrial site with industrial uses.
A minimal landscape model with more attention to keeping the site well maintained
and groomed would be appropriate.
• Extent of traffic increase: The traffic memo included a modest increase. The site
has had large equipment and the 50 peak trips per hour were not exceeded. There
will be very little public coming and most of the employees will enter and exit from
the lower Acacia entrance.
• What will the lot look like: There will be dirt piles that ebb and flow. Efforts will be
made to keep things neat and tidy.
• What will happen to the other two structures on the property: They were not part
of the plan, but they provide needed dry storage. The decision hasn't been made
yet.
• Retaining wall: This is part of Phase I
• How much more grading will be needed: The driveway and around the backside is
Phase I, the lower grading will be part of Phase II.
• Off-street parking, specifically the northwest parking space is within 15 feet of the
lot line: The limits of the paving will encroach slightly up the hill requiring some
excavation. This space was placed there due to existing utilities and easements
already in place. It is an increase and there are potential options for this particular
space.
• Moving of the water dispenser from 4th street: This is a consideration for Phase II,
but may depend on a future traffic study.
Commission comments: From a neighbor's perspective, this project will improve the site.
The plan addresses aesthetics, surface conditions, and provides improvements for the
residential areas. The extraneous uses will go away.
Public Comments:
An online comment was received from Karin Edwards asking what will be done to
maintain/improve the vegetation on the site and in the riparian corridor, and what will be
done to sustain Fish Creek? Coyote Willow is native and riparian and would be a good
choice.
A two-minute break was taken to allow for additional public comment. None was received.
It was moved and seconded (Hanson/Comstock) to approve the Water Division
application for a location and extent review with staff findings as presented. The
motion passed 5-0.
Page 13
RECORD OF PROCEEDINGS
Estes Valley Planning Commission
June 16, 2020
Board Room, Estes Park Town Hall
4
2. LOCATION AND EXTENT, TOWN OF ESTES PARK TRAILBLAZER BROADBAND,
1180 WOODSTOCK DRIVE
Director Hunt reviewed the staff report, which was prepared by Ayres Associates. The
property, which is zoned CO-Commercial Outlying, is developed with a 3,100 square foot
office building. The applicant seeks to demolish the interior space and refinish it with code-
compliant fixtures, equipment and materials. The only modification to the site will be the
removal of existing entry paving to accommodate the addition of a 65 square foot Entry
Foyer, which will be Phase II of the project. The principal concept behind this Location and
Extent review is to authorize the site for legitimate occupancy by a government agency.
There were no public comments received. Staff recommended approval.
Commissioner Comments/Questions
Vice Chair Heiser asked about the landscaping intent. Linda Swoboda, Project Manager,
stated that there would be minor landscaping along the perimeter. Ginny McFarland,
Project Designer, noted that the project would comply with code requirements in
anticipation of future development. Directed Hunt stated that landscaping is not required
as part of this review since the changes are so minimal. This review is for Phase I and II.
The design plans will be an administrative review by staff. It will not come back before the
Planning Commission if approved today.
A two-minute break was taken to allow for public comment. None was received.
It was moved and seconded (Murphree/Comstock) to approve the Town of Estes Park
Power and Communication Division's application for a Location and Extent Review
with staff findings as presented. The motion passed 5-0.
3. AMENDED PLAT, PARK SUITES, 215 PARK LANE
Senior Planner Woeber reviewed the staff report. The applicant requested approval of an
amended plat to reconfigure the existing lots. Plans are to keep one lot with a commercial
office building and to redevelop one lot for multi-family residential use. Staff recommends
approval of this Preliminary Amended Plat with the condition of labeling the lot lines more
clearly.
Commissioner Comments/Questions and Responses from Thomas Beck,
owner/applicant and Adam Kelly, engineer
Vice-Chair Heiser asked Attorney Kramer to explain the process involved if the
Commission does not agree with staff findings. Kramer answered that in general, it is the
Commissions' role to apply the review criteria to the application presented, and the
responsibility for interpreting the code lies with the Community Development Department.
Woeber clarified that tax parcels are assigned by the County Assessor and have nothing
Page 14
RECORD OF PROCEEDINGS
Estes Valley Planning Commission
June 16, 2020
Board Room, Estes Park Town Hall
5
to do with subdivision of lots and that this predates any Town requirements. Adam Kelly,
surveyor for the applicant, stated that even though you may have built a house over a
commonly owned property line in the past, it doesn't mean your right to a buildable parcel
goes away. There was talk of right-of-way and emergency access when fronting a building
to an alley. Heiser suggested the possibility of naming and addressing the building that
fronts the alley. Director Hunt clarified that the condition added was to clearly label what
was previously platted and what is being proposed. The dedication of easements will have
an acceptance signature block on the final plat approved by the Town Board of Trustees.
Thomas Beck, owner, stated that he intends to dedicate the easements for emergency,
sewer and access for all future tenants and owners. If the lot size can't meet code for
residential living, a variance may have to be applied for at the development plan stage.
Attorney Kramer stated that this is subdivision plat hearing and the Commission cannot
deny the application based on use. Mr. Kelly clarified that the L-shaped line on Lot 6A is
the existing asphalt area and can be removed for the final plat.
Director Hunt explained that Estes Park doesn't have a unified development code that
uses appropriate language to "blend" subdivisions and zoning provisions. Heiser noted
that the Development Code won't change if we keep finding ways to make things fit; we
need to work to make things better from a code perspective. It was agreed that code
amendments need to be done sooner rather than later. A study session on this topic is
the appropriate place for this discussion and will be planned for July.
It was moved and seconded (Hanson/Elkins) to recommend approval to the Town
Board of Trustees for the Park Suites Preliminary Amended Plat, being a Portion of
Lot 6, 7 and 8, Block 1, Second Amended Plat of the Town of Estes Park, as
described in the staff report, with the findings and condition recommended by staff.
The motion passed 4-0. (Murphree unavailable)
REPORTS
Study Session in July to discuss Code Amendments
Future meetings will be held on the Zoom platform. Training will be provided prior to July
21.
ADJOURN
There being no further business Chair Comstock adjourned the meeting at 4:15 p.m.
_________________________________
Matt Comstock, Chair
_________________________________
Karin Swanlund, Recording Secretary
Page 15
Town of Estes Park, Larimer County, Colorado July 21, 2020
Minutes of a Study Session meeting of the PLANNING COMMISSION of Estes Park, Larimer
County, Colorado. Meeting held virtually on Google Meet.
Commission: Chair Matt Comstock, Vice-Chair Matthew Heiser, Commissioners Joe
Elkins, Howard Hanson, Steve Murphree
Attending: Comstock, Elkins, Heiser, Hanson
Also Attending: Director Hunt, Senior Planner Woeber, Planner II Bergeron, Recording
Secretary Swanlund, Town Attorney Kramer
Absent: Murphree
Vice-Chair Heiser called the meeting to order at 11:00 a.m. This study session was held virtually via
Google Meet and was streamed and recorded on the Town of Estes Park YouTube channel.
Director Hunt reviewed the subject of this study session, which was wholly devoted to Estes Park
Development Code issues and concerns. In May of 2017, a master list of amendments needed was
presented to the Town Board and was approved. An outline list (approximately 50 items) was
presented for overall scope. Specific goals would be to shorten the Code by 25%, update language
and procedures to 21st Century standards and have clear and understandable regulations. The
Community Development staff hopes that pressing amendments can be moved on with “all deliberate
speed.” Attorney Kramer stated that the Code needs to be updated from scratch, but intermittent
fixes will be necessary. Director Hunt is submitting grant proposal for a comprehensive plan rewrite
and is hoping for a 50% match from the State. Ideally, a comprehensive plan should precede the
code amendment rewrite. If the grant is not received, the comp plan updating will be delayed, but
code amendment rewrites will still need to be done. An important question is how much more
development we can accomodate without overly degrading the quality of life that citizens value.
Vice-Chair Heiser remarked that moving forward, redevelopment incentives and finding ways to make
investing money in older properties worthwhile should be a priority. Director Hunt agreed and noted
that Building Code and Development Code updates should overlap with a comp plan rewrite, and that
is often overlooked. He recognized that redevelopment is our economic future. Landscaping
requirements and parking standards are also high-priority, as are essential processes to address and
update.
If no rewrite happens, Commissioner Hanson suggested making a clear list of priorities and moving
ahead with some urgency, having a benign effect on the Comp Plan. Perhaps using another
community’s code and modifying it to Estes Park could be an option rather than reinventing the
wheel. Attorney Kramer responded that a lot of the problems with our Code are nuts and bolts
problems about processes and getting everyone on board and understanding the ‘what’ and ‘why’ is a
process in its own right. Comstock wondered how to “eat the elephant”. Noting that the Commission
is compiled of new members and the upcoming schedule is light, he asked if it would it be possible to
do two amendments per meeting. Heiser suggested that staff reach out to local design professionals
and ask what they see as hurdles and what could help their process. It would be useful to streamline
the time frame and process. Residents in the county feel disenfranchised, and the Planning
Commission will be scrutinized.
Page 16
Planning Commission Study Session July 21, 2020 – Page 2
Attorney Kramer noted that the Planning Commission’s role is to make recommendations and review
processes to the Town Board of Trustees. Code Amendments are ordinances and would be action
items for the Board of Trustees.
Possible steps to take:
• Prioritize most urgent
• Look at another community’s Code
• Refer to an older version of Codes from Estes Park and find a middle ground
Amendments to get started on in September-October:
• Parking
• Downtown Building Height
Chair Comstock adjourned the study session at 12:55 p.m.
Karin Swanlund, Recording Secretary
Page 17
Page 18
Town of Estes Park, Larimer County, Colorado, July 2, 2020
Minutes of a regular meeting of the Family Advisory Board of the Town of Estes Park,
Larimer County, Colorado. Meeting held virtually on Google Meet, on the 2nd day of July,
2020.
Present: Rachel Balduzzi
Laurie Dale Marshall
Sue Strom
John Bryant
Jodi Roman
Christy DeLorme
Also Present: Cindy Younglund, Town Board Liaison
Jason Damweber, Assistant Town Administrator
Suzanna Simpson, Recording Secretary
Carlie Bangs, Trustee
Absent: Nancy Almond
Michael Moon
Guests: Chris Douglas, EVICS
Chair Dale Marshall called the meeting to order at 3:45 p.m.
PUBLIC COMMENTS:
None
TRUSTEE LIAISON REPORT
In lieu of a report, the board was introduced to Trustee Cindy Younglund, who is now
serving as the Trustee liaison.
APPROVAL OF MARCH MINUTES:
It was moved and seconded (DeLorme/Strom) to approve the March meeting minutes
and the motion passed unanimously.
FUTURE OF THE FAMILY ADVISORY BOARD
Chair Dale Marshall led the discussion about the future of the Family Advisory Board. She
stated that members have been feeling as though they are spinning their wheels and
there is a sense of frustration about the lack of action from the board. She mentioned that
a significant lesson learned from the community COVID-19 response is that collaboration
is essential. There has been hesitation from the board collectively to narrowly define a
Page 19
Family Advisory Board – July 2, 2020 – Page 2
family, and while she believes in that decision, it has also led to an inability to make solid
recommendations to the Town Board. Further, there is a sense that some board members
do not have clarity on the advisory role of the board and are frustrated at the inability to
be more action-oriented. She feels that the board might be more efficient, action-oriented
and productive if it was framed as a community services advisory board. This reframing
would broaden the scope of the board and allow subcommittees to work on specific areas
such as childcare, housing, or mental health. Further, there are multiple groups and
committees in town tackling many of these issues, and it would make more sense to have
them work on the subcommittees as well. As an example, the Estes Valley Childcare
Collaborative would be a logical subgroup as they have the expertise to support
recommendations around childcare.
Member Strom added that she has had a hard time understanding the role of the Family
Advisory Board and would need more direction as to how subgroups might work. Trustee
Bangs added her perspective as the Trustee liaison to the Transportation Advisory Board
and how that group has been able to come together to make recommendations to the
Town Board. Assistant Town Administrator Damweber stated that narrowly defining a
family is a challenge and he feels that reframing the work of the board will be more
productive and allow for more specific recommendations to be brought to the Town Board.
Member DeLorme inquired about the work of the Childcare and Housing Task Force and
asked if the Family Advisory Board could review the recommendations from the task
force.
Vice-Chair Balduzzi asked how the Family Advisory Board could receive better guidance
on the Town’s budget and strategic plan in order to have good information to base
recommendations on moving forward. Member Bryant added that a previous discussion
about the budget was really helpful to build a base of knowledge for the board. He
recommends building agenda items around the Town’s strategic plan and budget
timelines. Following this timeline allows the board to give informed and direct feedback to
the Town Board.
The board discussed the Town’s Outside Entity Funding process as one way to make
recommendations. The board was encouraged to educate themselves on this process.
Assistant Town Administrator Damweber will provide the board with information on
funding.
Member Roman added that she had concerns about a complete reframing and wondered
if subgroups would be structured the same as the board. Chair Dale Marshall explained
that she viewed this as a way to be more connected to the work of the other groups and
provide a means to collaborate with the groups that are working on the same issues in
the community.
Page 20
Family Advisory Board – July 2, 2020 – Page 3
OTHER BUSINESS:
Seeing no further business, the meeting was adjourned at 5:02 p.m.
NEXT MEETING
The next regular meeting of the Family Advisory Board will take place Thursday, August
6 at 3:30 p.m. The format will be virtual through the Town’s Zoom account.
Suzanna Simpson, Recording Secretary
Page 21
Page 22
PROCEDURE FOR PUBLIC HEARING
Applicable items include: Rate Hearings, Code Adoption, Budget Adoption
1. MAYOR.
The next order of business will be the public hearing on ACTION ITEM 1.
ORDINANCE 11-20 PROPOSED ELECTRIC RATE INCREASE.
At this hearing, the Board of Trustees shall consider the information
presented during the public hearing, from the Town staff, public comment,
and written comments received on the proposed electric rate increase.
Any member of the Board may ask questions at any stage of the public
hearing which may be responded to at that time.
Mayor declares the Public Hearing open.
2. STAFF REPORT.
Review the staff report.
3. PUBLIC COMMENT.
Any person will be given an opportunity to address the Board concerning the
Ordinance. All individuals must state their name and address for the record.
Comments from the public are requested to be limited to three minutes per
person.
4. MAYOR.
Ask the Town Clerk whether any communications have been received in regard
to the item which are not in the Board packet.
Ask the Board of Trustees if there are any further questions concerning the item.
Indicate that all reports, statements, exhibits, and written communications
presented will be accepted as part of the record.
Declare the public hearing closed.
Request Board consider a motion.
5. BOARD DISCUSSION.
Discussion by the Board.
Page 23
6. SUGGESTED MOTION.
Suggested motion(s) are set forth in the staff report.
7. DISCUSSION ON THE MOTION.
Discussion by the Board on the motion.
8. VOTE ON THE MOTION.
Vote on the motion or consideration of another action.
Page 24
UTILITIES Memo
To: Honorable Mayor Koenig
Board of Trustees
Through: Town Administrator Machalek
From: Director Bergsten
Director Hudson
Superintendent Lockhart
NewGen Strategies & Solutions, Consultant
Date: August 25, 2020
RE: Ordinance 11-20 Proposed Electric Rate Increase
(Mark all that apply)
PUBLIC HEARING ORDINANCE LAND USE
CONTRACT/AGREEMENT RESOLUTION OTHER______________
QUASI-JUDICIAL YES NO
Objective:
To provide reliable electric service for our customers by funding operations,
maintenance and capital improvements.
Present Situation:
The global pandemic has resulted in a one-year delay in the proposed electric rate
increases. To limit negative financial impacts Power and Communications has stopped
capital improvement projects and cut back on staff training, street light maintenance,
and a number of other activities. This is not sustainable.
The public can view on-demand, a complete presentation of the rate study given at the
March 10, 2020 Board Meeting. The following link to this on-demand video is titled
“Town of Estes Park Board Meeting - March 10, 2020 Part 1” and begins 23 minutes
into the meeting: Click Here: https://estesgovtv.viebit.com/player.php?hash=EXC3OATrLIQq
The Town’s public electric utility is a cost-based entity that relies solely on user fees to
operate. Costs and revenues must be balanced in order to maintain operations and
keep utilities in line with ever-increasing federal standards. We are proposing an
overall revenue increase of 5.9% spread out over three years.
The study also ensures equitable rates among customer classes, so that one customer
class does not subsidize another. Residential customers make up 70%, and small
Page 25
commercial (aka commercial) make up 22% of our customers. The following tables
show the proposed rate impacts:
The study includes charges for customers who opt out of smart metering. This is a new
charge to cover the cost of physically going to those customers’ premise to manually
read their meters.
Hard copies of the study and proposed rate sheet are located at the Municipal building
and library for the public to review. They are also on our website. The Study has been
marked up in red to indicate the proposed implementation delay of one year.
Proposal:
Staff proposes continuation of this public meeting to September 8, 2020 to allow for
additional public comments before a Town Board vote. Staff recommends
implementing the rate increases January 2021.
Advantages:
•Maintain adequate financial strength required to operate the enterprise
•Meet our bond covenants obligations
•Fund project required to improve reliability, quality and safety of our system
Disadvantages:
2023 ------
2023 ------
/2020
/2020
Page 26
Higher cost of electricity; however, our daily need for electricity requires reliable, safe
electricity.
Action Recommended:
Staff recommends proposes continuation of this public meeting to September 8, 2020.
Finance/Resource Impact:
Over three years electric revenues will increase 5.9%
Level of Public Interest
High, increases to utility rates will touch every Power and Communications customer
Sample Motion:
I move for the approval/denial continuation of the rate hearing to our September 8th
board meeting.
Attachments:
1. Ordinance 11-20
2. Rate Sheet
3. Rate Study Link
4. Revised Presentation
Page 27
ORDINANCE NO. 11-20
AN ORDINANCE AMENDING THE POWER & COMMUNICATIONS RATE
SCHEDULES OF THE TOWN OF ESTES PARK, COLORADO
WHEREAS, the Board of Trustees has determined that it is necessary to amend
the Electric Rate Schedules of the Town of Estes Park.
NOW, THEREFORE, BE IT ORDAINED BY THE BOARD OF TRUSTEES OF
THE TOWN OF ESTES PARK, COLORADO AS FOLLOWS:
Section 1: That the Town of Estes Park, Colorado Electric Rate Schedules shall
be amended to read as set forth in Exhibit A.
Section 2: These rate schedules will take effect the first full billing period in
January, 2021.
Section 3: This Ordinance shall be enforced thirty (30) days after its adoption and
publication.
PASSED AND ADOPTED by the Board of Trustees of the Town of Estes Park,
Colorado this ____ day of _______________, 2020.
TOWN OF ESTES PARK, COLORADO
By:
Mayor
ATTEST:
Town Clerk
I hereby certify that the above Ordinance was introduced at a regular meeting of the
Board of Trustees on the day of , 2020 and published in a
newspaper of general circulation in the Town of Estes Park, Colorado, on the day
of , 2020, all as required by the Statutes of the State of Colorado.
Town Clerk
APPROVED AS TO FORM:
Town Attorney
Attachment 1
Page 28
TOWN OF ESTES PARK, COLORADO
PROPOSED Electric Rate Summary 2020-2023, Public Meeting 8/25/2020
On-Peak Off-Peak Standard
Customer Energy Energy Demand Rate for
Customer Rate Class Year (2)Charge Consumption Consumption Charge May thru
Month Charge Charge $/kW August
kWh $/kWh $/kWh
RESIDENTIAL (1)2020 $22.70 $0.1095 $0.00349 --- --- ---
Jan 2021 $23.47 $0.1119 $0.00000 --- --- ---
2022 $24.23 $0.1144 TBD --- --- ---
2023 $25.00 $0.1168 TBD --- --- ---
RESIDENTIAL DEMAND (1)2020 $26.10 $0.0654 $0.00349 --- $13.60 ---
Jan 2021 $26.90 $0.0645 $0.00000 --- $13.60 ---
2022 $27.70 $0.0636 TBD --- $13.60 ---
2023 $28.50 $0.0627 TBD --- $13.60 ---
RESIDENTIAL ENERGY TIME-OF-DAY (1)2020 $26.10 $0.1520 $0.00349 $0.0760 --- ---
Jan 2021 $26.90 $0.1566 $0.00000 $0.0806 --- ---
2022 $27.70 $0.1612 TBD $0.0852 --- ---
2023 $28.50 $0.1658 TBD $0.0898 --- ---
RESIDENTIAL ENERGY BASIC TIME-OF-DAY (1)2020 $26.10 $0.1345 $0.00349 $0.1077 --- $0.1095
Jan 2021 $26.90 $0.1470 $0.00000 $0.1038 --- $0.1119
2022 $27.70 $0.1595 TBD $0.0998 --- $0.1144
2023 $28.50 $0.1719 TBD $0.0959 --- $0.1168
SMALL COMMERCIAL (1)2020 $33.37 $0.1140 $0.00349 --- --- ---
Jan 2021 $33.25 $0.1154 $0.00000 --- --- ---
2022 $33.12 $0.1169 TBD --- --- ---
2023 $33.00 $0.1183 TBD --- --- ---
SMALL COMMERCIAL ENERGY TIME-OF-DAY (1)2020 $36.77 $0.1615 $0.00349 $0.0708 --- ---
Jan 2021 $36.51 $0.1526 $0.00000 $0.0763 --- ---
2022 $36.26 $0.1438 TBD $0.0818 --- ---
2023 $36.00 $0.1349 TBD $0.0872 --- ---
LARGE COMMERCIAL (1)2020 $45.23 $0.0625 $0.00349 --- $14.80 ---
Jan 2021 $45.49 $0.0633 $0.00000 --- $15.87 ---
2022 $45.74 $0.0640 TBD --- $16.93 ---
2023 $46.00 $0.0648 TBD --- $18.00 ---
LARGE COMMERICIAL TIME-OF-DAY (1)2020 $53.18 $0.0820 $0.00349 $0.0445 $17.45 ---
Jan 2021 $53.79 $0.0848 $0.00000 $0.0461 $18.30 ---
2022 $54.39 $0.0876 TBD $0.0478 $19.15 ---
2023 $55.00 $0.0904 TBD $0.0495 $20.00 ---
OUTDOOR AREA LIGHTING 2020 $ 36.49 --- --- --- --- ---
Jan 2021 $36.49 --- --- --- --- ---
2022 $36.49 --- --- --- --- ---
2023 $36.49 --- --- --- --- ---
RENEWABLE ENERGY CHARGE (1)2020 --- $0.0275 $0.00000 --- --- ---
Jan 2021 --- $0.0275 --- --- ---
2022 --- $0.0275 --- --- ---
2023 --- $0.0275 --- --- ---
MUNICIPAL RATE (1)2020 $0.00 $0.1171 $0.00349 --- --- ---
Jan 2021 $9.00 $0.1149 $0.00000 --- --- ---
2022 $18.00 $0.1128 TBD --- --- ---
2023 $27.00 $0.1106 TBD --- --- ---
Purchase Power
Rider $/kWh
Available to all residential customers and residential
customers with electric heat up to 25,000 kWh annually.
Available to existing customers on this rate, September
through April. All other times the Residential energy
charge would apply.
Available to all residential customers using electric
thermal storage heat.
Available to all residential customers not using electric
thermal storage heat. These rates apply September
through April. Standard rates apply May through August.
Available to all commercial customers with demands of
35 kW or less.
Available to all commercial customers using electric
thermal storage heat with demands of 35 kW or less
Available to all commercial customers with demands
exceeding 35 kW
Available to all commercial customers with demands
exceeding 35 kW
Available for lighting outdoor private areas
Voluntary participation available to all classes; charge
per 100 kWh block
Available for electricty use on municipal property
Attachment 2
Page 29
TOWN OF ESTES PARK, COLORADO
PROPOSED Electric Rate Summary 2020-2022, Public Meeting 8/25/2020
RMNP ADMINISTRATIVE HOUSING 2020 $22.70 $0.0690 N/A --- --- ---
Jan 2021 $22.70 $0.0690 N/A --- --- ---
2022 $22.70 $0.0690 N/A --- --- ---
2023 $22.70 $0.0690 N/A --- --- ---
RMNP SMALL ADMINISTRATIVE 2020 $33.37 $0.0456 N/A --- --- ---
Jan 2021 $33.37 $0.0456 N/A --- --- ---
2022 $33.37 $0.0456 N/A --- --- ---
2023 $33.37 $0.0456 N/A --- --- ---
RMNP LARGE ADMINISTRATIVE 2020 $45.23 $0.0185 N/A --- $12.50 ---
Jan 2021 $45.23 $0.0185 N/A --- $12.50 ---
2022 $45.23 $0.0185 N/A --- $12.50 ---
2023 $45.23 $0.0185 N/A --- $12.50 ---
NOTES:
1) Purchase Power Rider is a pass-through of wholesale increases from PRPA; TBD for years 2021-2023
2) The 2023 rates remain in effective until new rates are adopted by the Town Board.
Residential Energy "Basic" Time-of-Day is available for every residential customer except as stated above.
These rates apply only September thru April (for May thru August, the standard Residential rate applies):
ON-PEAK for Residential "Basic" Time-of-Day Customers: 4:00 pm to 7:00 pm weekdays
Updated 05-21-2020
Available to Rocky Mountain National Park residences
having an alternate power source delivered to Estes
Park's distribution system
Available to RMNP administrative accounts having an
alternate power source delivered to Estes Park's
distribution system with demands of 35kW or less
Smart Meter/Advanced Metering Infrastructure Opt-Out Fees - One Time Enrollment Fee of $75 and monthly fee of $20
Avoided Cost paid to Net Meter Customers = $0.0175, the wholesale cost of energy minus $0.01 for administrative costs
Available to RMNP administrative accounts having an
alternate power source delivered to Estes Park's
distribution system with demands exceeding 35kW
Fees for other work performed, such as service upgrades or line extensions, the developer or customer must pay for work performed.
Payment must be made before the work is scheduled. The payment covers the cost of labor, materials, equipment, and overhead.
Residential Energy Time-of-Day available only for residential customers using electric thermal storage heat:
OFF-PEAK for Residential Time-of-Day Customers: 1:00 pm to 3 pm and 10:00 pm to 6:00 am
weekdays and all day on weekends and holidays (New Years Day, Memorial Day, Independence Day,
Labor Day, Thanksgiving Day, Christmas Eve and Christmas Day)
ON-PEAK for Residential Time-of-Day Customers: 6:00 am to 1:00 pm and 3:00 pm to 10:00 pm
weekdays
OFF-PEAK for Residential "Basic" Time-of-Day Customers: 7:00 pm to 4:00 pm the following day and all day weekends and the
following holidays: Labor Day, Thanksgiving Day, Christmas Eve, Christmas Day and New Years Day
Page 30
TOWN BOARD MEETING
August 25, 2020
Action Item 1. Ordinance 11-20 Proposed
Electric Rate Increase.
Attachment 3 – Electric Rate Study can be
accessed by clicking here.
Attachment 3
Page 31
March 10, 2020
Financial Forecast, Cost of Service, and Rate Design Study
Cost of Service And Rate Design Process Overview
1
2
2023------
2023------
/2020
/2020
Attachment 4
Page 32
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
3
Cost of Service (COS)
Determine cost to provide electric serve to different customer classes,
identifying the fixed and variable cost components.
Rate Design
Use the COS results, rate strategy and policies to guide rate design.
Rates must fully recover all costs.
Rates In Three Steps
Framework and guide for COS, financial and rate related decisions for
(vision, goals, metrics, etc.)
Revenue Requirement
Identify cost to operate utility to determine rate revenue required to
keep utility financially solvent.
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Desired Outcomes
• Financial Strength
• Bond covenants
• Adherence to Cost of Service
principles
• Rate design
– Various service offerings
– Avoid complexity
– Transparency
– Funding conservation efforts
– Avoid Rate Shock
–Etc.
4
Economics
Fairness
Utility Financial Strength
Energy
Conservation
Understandable
Transparent
Adhere to
Laws/Regulations
Principles of
Cost of Service
Page 33
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Steps
5
STEP 1
STEP 2
STEP 4
STEP 3
STEP 5
Determine the revenue
requirement of the utility
Unbundle costs by functions
and services (purchased power,
distribution, customer services.)
Classify costs (demand, energy,
fixed, variable, etc.)
Allocate cost among customer
classes (residential, small
commercial, etc.)
Design rates that generate the
revenue requirement
Cost Allocation
Rate Design
Revenue Requirement
Determination
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Step 1 Revenue Requirement Determination
• Revenue Requirement (RR) equals the
revenue that must be generated from
electric rates
– Total system operating costs less other
sources of revenue, example, interest income
–Initially expressed one amount then divided
out to each customer class
6
Page 34
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Step 1 Revenue Requirement
7
Financial Forecasting
• 10 year projection
• Predicts utility financials:
•Revenues
•Expenses
•Capital Improvement Projects (CIP)
•Bond financing and payments
•Cash reserve requirements
•Etc.
• Enables scenario analyses which
helps us understand the impact on
electric rates (example, if a project is
bond financed vs using cash reserves)
P&C Financials were used as the basis to forecast future RR
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Step 1 Revenue Requirement
• Test Year RR is a projection of costs based on
changes (adjustments) in the cost of doing
business
– Adjustments
• Known and Measurable
• Prudent
• Reasonable and Necessary
8
P&C Financials
Dist. Engineering
Dist. Labor
Dist. Materials
Capital Projects
Adjustments
Known/measurable
Inflation/escalation
Load growth (development)
Future RR Target Year
(aka Test Year ‐TY)
TY Dist. Engineering
TY Dist. Labor
TY Dist. Materials
TY Capital Projects
Page 35
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Steps in the Rate Design Process
9
STEP 1
STEP 2
STEP 4
STEP 3
STEP 5
Determine the revenue
requirements of the utility
Unbundle costs by functions
and services (production,
transmission, distribution, etc.)
Classify costs (demand, energy,
customer costs, etc.)
Allocate cost among customer
classes
Design rates
Revenue Requirement
Determination
Cost Allocation
Rate Design
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Step 2 Functions
10
The Electric
Utility Grid
Configuration
Page 36
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Step 2 Functions
11
Platte River Power Authority
(PRPA)
“Generation” & “Transmission”
Town of Estes Park
Power & Communications
(P&C):
“Distribution” &
“Customer Service”
NEWGEN STRATEGIES AND SOLUTIONS, LLC
• The generation function is
responsible for producing
energy and meeting the
maximum customer demand
– The power plant portfolio is
sized to meet the maximum
demand requirements of the
system (PRPA)
– Energy is produced by wind,
solar and burning fuel to meet
customer demand over time
• Electricity is transmitted to the
Town through transmission
lines
Cost of Service and Rate Design Overview
PRPA - Generation and Transmission Functions
12
Page 37
NEWGEN STRATEGIES AND SOLUTIONS, LLC
• The distribution function
distributes electricity
from the substation to
customers
– Tree trimming
– Respond to outages
– Street light maintenance
– Billing
Cost of Service and Rate Design Overview
Town of Estes Park Distribution Function
13
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Steps in the Rate Design Process
14
STEP 1
STEP 2
STEP 4
STEP 3
STEP 5
Determine the revenue
requirements of the utility
Unbundle costs by functions
and services (production,
transmission, distribution, etc.)
Classify costs (demand, energy,
customer costs, etc.)
Allocate cost among customer
classes
Design rates
Revenue Requirement
Determination
Cost Allocation
Rate Design
Page 38
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Typical Cost
Functions
Typical Cost
Classifications
Production: Demand‐related
Energy‐related
Transmission: Demand‐related
Direct Assignments
Distribution: Demand‐related
Customer‐related
Direct Assignments
Customer Service: Utility Billing,
Customer questions
Cost of Service and Rate Design Overview
Step 3 Cost Classification
15
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Step 3 Cost Classification
• Fixed or Variable costs
– Fixed costs vary with capacity additions
• Examples: labor expense & depreciation
• Demand-related and customer-related costs are
fixed
– Variable costs vary with energy consumed,
delivered, or purchased
• Example: energy component of PRPA’s wholesale
rate
• Energy-related costs are variable
16
Page 39
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Steps in the Rate Design Process
17
STEP 1
STEP 2
STEP 4
STEP 3
STEP 5
Determine the revenue
requirements of the utility
Unbundle costs by functions
and services (production,
transmission, distribution, etc.)
Classify costs (demand, energy,
customer costs, etc.)
Allocate cost among customer
classes
Design rates
Revenue Requirement
Determination
Cost Allocation
Rate Design
NEWGEN STRATEGIES AND SOLUTIONS, LLC
• Residential
• Residential Demand
• Residential Energy TOD
• Residential Energy Basic
TOD
• Small Commercial
• Small Commercial
Energy TOD
• Large Commercial
• Large Commercial TOD
• Outdoor Area Lighting
• Renewable energy
Charge
• Municipal Rate
•RMNP
Cost of Service and Rate Design Overview
Step 4 Twelve (12) L&P Rate Classes
18
Customer Classes are grouped by similar size, consumption,
requirements, and characteristics
Page 40
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Cost Allocation to Classes
• Cost of service differentials
– Different load characteristics
• Large Commercial (example Water Plants)
• T-Shirt shops
• Residential
– Different service voltages
– Metering (the YMCA is on one primary meter)
– Customer service requirements (net meters)
– Other
19
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
COS and Rate Making
Cost of Service vs. Rate Making
Cost accounting, allocate utility
costs with use, classification
Used to incentivize specific
behavior, example, net metering.
Rates do not have to match COS,
but industry practice is to align
rates with COS
Power Supply
(Demand and
Energy
Components)
Transmission
(Demand
Components)
Distribution
(Demand and
Customer
Components)
Customer
(Customer
Components)
Utility Functions:
20
Page 41
NEWGEN STRATEGIES AND SOLUTIONS, LLC
Cost of Service and Rate Design Overview
Potential Objectives for Tariffs and Rates
• Legislative and regulatory compliance
• Conservation/DSM (Behavior Modification)
• Distributed Generation
– Traditional
– Renewables (roof top solar)
• Revenue stability
• Alignment with cost of service
• Simplicity
• Other
21
22
2023------
2023------
/2020
/2020
Page 42
DISCUSSION
Page 43
Utility Department &
Finance Department
970-577-3560
rbergsten@estes.org
dhudson@estes.org
170 MACGREGOR AVE. P.O. BOX 1200, ESTES PARK CO. 80517 WWW.ESTES.ORG
Aug 17, 2020
Town of Estes Park Board of Trustees 170 MacGregor Ave Estes Park, CO 80517
RE: Response to June 8 Letter Concerning Electric Rates
Mayor Koenig and Town Trustees,
On June 8, 2020, Mr. David Standerfer sent an email with an unsigned, undated commentary on the Power and Communication rate study and the recommended rate increase for electric service. In this letter, Mr. Standerfer made several comments and included selected statistical data to support his position. This letter is staffs’ response to many of the claims and assertions made in this letter, hopefully providing more clarity into the proposed rates. Throughout the letter, Mr. Standerfer focused entirely on only one of three rate components used to calculate a customer’s electric bill. The three components are the base fee, consumption fee, and purchased power rider fee. It is important that the entire rate be considered when looking at impacts to customers. Part of the rate setting process involves looking at the individual components, setting them at the appropriate level, and then evaluating the total impact. At times, the costs recovered through the individual components are realigned based on modern rate design methodology. Under the current methodology, the base fee is the flat monthly component of the rate which is intended to cover most of the fixed costs of the system, i.e. the costs necessary to be ready to serve the customer regardless of the amount of power sold. The distribution system must be ready and in good working order, basic operations must be funded, and monthly billing processes must be in place. These costs are incurred each and every month regardless of the amount of power sold. The base fee should recover most of these costs. The base fee in the past was not adequately covering these costs so it has been systematically raised over the last few years to better align with this rate design methodology.
Page 44
Ordinance 11-20 - Staff Letter in Response
to Public Comment provided 06-08-2020
Utility Department &
Finance Department
970-577-3560
rbergsten@estes.org
dhudson@estes.org
170 MACGREGOR AVE. P.O. BOX 1200, ESTES PARK CO. 80517 WWW.ESTES.ORG
Capital costs and purchased power costs are additional costs that must be recovered through rates and these have been generally recovered through the consumption and purchased power rider components. The individual rate components are clearly displayed on each utility bill. Comments were made that increasing the base fee negatively impacts those who least can afford it. Actually, when you look at the impact of the total rate changes, it actually benefits the year-round residents, including those individuals who struggle the most with rate increases. Setting the base fee at a rate that recovers the fixed costs as discussed earlier is more equitable to all customers. These fixed costs are incurred whether a person uses no power during part of the year, like our seasonal residents, or whether a person uses power year-round. If the base fee was not increased to recover these costs, the costs would have to be recovered through increased rates for the consumption and purchased power rider components. The year-round resident would in effect subsidize the seasonal resident by paying the increased consumption and purchased power rider rates. A family living in Estes Park all year round using an average 700 kWH a month would have seen a 19.3% increase over the last 3 years. A family who did not use their second home and only paid a base fee would have seen the 239% increase indicated, covering their portion of fixed system costs. Much of the commentary was focused on the transfer of profits to the General Fund as the owner of the utility. This is an annual transfer approved through the budget process and has occurred for decades. Mr. Standerfer questioned the motives for the transfer and even accused the Town of raising the transfers specifically for new projects such as the Multi-Purpose Event Center and parking structure. Actually, the amount to be transferred is calculated by estimating utility revenues and then applying a percentage rate. The General Fund budget is then scaled to fit the available revenues, not the other way around as suggested. During development of the 2019 budget (mid-year in 2018) and the 2020 budget (mid-year in 2019), the Finance Director reduced the percentage of revenues transferred in an effort to limit growth in the amount transferred simply due to rate increases. The amount calculated and budgeted is transferred equally each month. Because the budget is based upon estimated revenues, the percentages of the resulting transfers to actual utility revenues can fluctuate but the following chart reflects these reduction efforts. Contrary to repeated accusations, the percentage of actual transfers to actual electric charges for service revenues has gone down. Staff currently plan to continue this effort to gradually reduce the amount transferred each year in an effort to bring this closer to an 8-9% target. This gradual approach provides for a more measured transition of General Fund operations to a lower dependence on transfers without resulting in a budgetary crisis of our own creation.
Page 45
Utility Department &
Finance Department
970-577-3560
rbergsten@estes.org
dhudson@estes.org
170 MACGREGOR AVE. P.O. BOX 1200, ESTES PARK CO. 80517 WWW.ESTES.ORG
Fiscal Year Ended December 31, Actual Electric Charges for Services Profit Transfer to the General Fund Percentage of Actual Transfers to Actual Charges 2015 $13,639,816 $1,351,884 9.91% 2016 13,907,893 1,391,740 10.01% 2017 15,287,109 1,646,929 10.77% 2018 16,381,233 1,731,228 10.57% 2019 $17,856,743 $1,772,928 9.93% As with most financial analysis, it is critical to try to compare “apples to apples.” The Town’s finances are no different. The Town’s operations have evolved over the years, with the Multi-Purpose Events Center accounted for separately from the General Fund until 2015, after which it became another department within the General Fund. The Community Reinvestment Fund must also be taken into account since its primary funding source is a transfer from the General Fund. After factoring out the transfers between these operations and comparing apples to apples, the “General Fund” expenditures totaled $12.7 million in 2011 compared to $18.4 million (unaudited number) in 2019. This was an increase of $5.7 million. During that same period, General Fund sales tax revenues grew from $7.6 million to $13.4 million, an increase of $5.8 million. This is not “growth on the backs of electric customers” as claimed. As is true for many major initiatives and projects, members of the public will have different perspectives and opinions. Trailblazer Broadband is a prime example. Over the last several years, increasing the availability of high-speed internet services within the Estes Valley has been a high priority for the community. In 2015, voters overwhelmingly (92%) chose for the town to have the right to develop and provide this service. Most recently, in a 2018 citizen survey, 2/3 of respondents wanted better internet service, ranking it the highest priority among 40 current and potential services. In response to this demand from residents and businesses alike, the Town leveraged the capabilities of the Light and Power Division’s smart grid system, expanding it to include delivery of high-speed internet services. In 2019, the Light and Power Division was renamed the Power and Communications Division and the Town Board approved the sale of revenue bonds to make the expansion of high-speed internet services a reality in direct response to the desires of the majority of the community. One of the primary benefits of a government owned and operated utility is access to the governing board and local officials who help manage that utility. Mr. Standerfer pointed out that approximately 53% of electric customers reside outside of the Town limits and do not elect the Town Trustees who approve the electric rates for all customers. However, it is not the ability to vote on the Town Trustees that provides the benefit but rather the
Page 46
Utility Department &
Finance Department
970-577-3560
rbergsten@estes.org
dhudson@estes.org
170 MACGREGOR AVE. P.O. BOX 1200, ESTES PARK CO. 80517 WWW.ESTES.ORG
relatively easy access to discuss concerns with the Town Trustees. Individual members of the public do not vote on Public Utility Commission members and probably have no idea about who they are, where they live, or if the PUC member even has been to Estes Park. However, chances are good that the customer will know how to contact the Mayor, Town Trustees, Utility Director and Finance Director. Customers know or can easily find out when the Town Board meets and how to contact them and/or relevant staff with questions or concerns. The June 8th letter from Mr. Standerfer is proof of that ease of access. Utility rate setting processes are held locally with hearings and discussion held during regular public Town Board meetings. All public input is welcomed, regardless of where the individual lives, including input from Mr. Standerfer. Trustees seriously consider the input received and then must make a decision with the entire utility in mind. Living and working in the local community, understanding of the local community, the topography of the area, and the internal workings of the electric system are important considerations that can be lost when going through a state-wide board such as the Public Utility Commission. The Public Utility Commission is critical when dealing with private for-profit utility companies. The individual customers of large corporate utilities such as Xcel Energy generally do not take part in the corporate board room conversations, limiting the individual customer’s ability to have direct input into rate considerations. The PUC performs a vital service by representing the interests of customers of these organizations, among other duties. This is not necessary in a local government owned and operated utility since customers can just email, call or participate during the very public rate hearings held locally. In conclusion, Mr. Standerfer raised three main questions as follows: 1)Is the Power and Communications Division a “municipally owned” utility service if53.4% of residential customers live in unincorporated Larimer County? Or should itbe treated as a privately-owned public utility? Yes, the system is a municipallyowned and operated utility under C.R.S. 31-15-707.2)Do the trustees of Estes Park have authority to unilaterally set utility rates? Or doesthe Public Utilities Commission have jurisdiction and authority? If not, whorepresents the majority? C.R.S. 40-3.5-102 explicitly assigns the Town Board ofTrustees the authority and responsibility to adopt all necessary rates, charges andregulations within the municipal utility’s authorized electric service areas which lieoutside the jurisdictional limits of the municipality. It goes on to state the rate shallnot discriminate between or among those customers within the authorized servicearea without PUC approval. In accordance with this, the Town charges the sameelectric rates to customers both inside and outside the Town limits, therefore notrequiring PUC approval.
Page 47
Utility Department &
Finance Department
970-577-3560
rbergsten@estes.org
dhudson@estes.org
170 MACGREGOR AVE. P.O. BOX 1200, ESTES PARK CO. 80517 WWW.ESTES.ORG
3)Did Town trustees have unilateral authority to obligate electric customers inunincorporated Larimer County to revenue bonds so that the Town could build a"for-profit" internet service? As a TABOR exempted Enterprise Fund (Article X,Section 20(2)(d) of the Colorado Constitution), yes, the Town Board of Trustees hasfull authority to issue revenue bonds without an election.Each customer is entitled to his or her opinion and those opinions are equally considered by the board. The Town strives for transparency and openness in conduct of the public’s business and providing a clear understanding and open discussion of utility rates is no exception.
Sincerely, Duane Hudson, Finance Director Reuben Bergsten, Utility Director
Page 48
Out of Control Utilities
The Power and Communications Division is
proposing another rate increase beginning in 2020.
If the trustees approve the proposed 2020 electric rate schedule, the base fee for residential service
will increase to $25 per month on January 1, 2022, marking a 432% increase in just 10.6 years.
In 10 years, the profit transfer from the Power and Communications Division to the Town’s General
Fund went from $958,589 (2009) to $1,772,928 (2019), an increase of 85%. The first substantial
increase occurred in 2013 and the second in 2017.
Meanwhile, from 2009 through 2019, property tax revenue was flat, averaging $343,715 annually
(including a full property tax refund of $357,008 in 2017). Estes Park property taxes remain one of
the lowest in Colorado, a fact that is rolled out when utility profits are challenged.
In 2019, profits from electric rates accounted for 9% of General Fund revenues, while property taxes
accounted for 2%. Property tax revenue in 2019 was just $31,287 more than in 2009, while revenue
from electric utility profits in 2019 was $814,339 more than in 2009. Clearly, the Town “targets”
electric utility profits over property taxes to balance the budget.
The base electric fee for residential customers
rocketed 239% in 3.3 years
Prior to the rate increase on May 25, 2011, the base fee for residential electric service was just $4.70
per month. On February 20, 2013, after three rate increases, the base fee was $6.70 per month.
The 2016 rate schedule, beginning September 5, 2016, raised the residential base fee by 239% in
just 3.3 years to $22.70 per month. In less than 8 years, the base fee for residential services
increased 383%.
In 2011, the profit transfer from the Power and Communications Division to the Town’s General
Fund was $1,039,550. In 2013, two years later, the profit transfer was $1,309,962, an increase of
$270,412, or 26% over 2011.
In 2016, the profit transfer to the Town’s General Fund was $1,391,740. In 2019, three years later,
the profit transfer to the Town’s General Fund was $1,772,928, an increase of $381,188, or 27.4%
more than 2016. As a result of the 2016 rate hike, the Town’s General Fund raked in $975,865 in
additional profits, nearly $1 million in just 3 years.
Nowhere in the 2016 rate study, FAQ announcement, or during presentations, did the Town disclose
that profits would grow by nearly $1 million in a single rate cycle, or how the Town would spend its
newfound money. Deception as a tactic? Clever indeed: 1) mislead the consumer with “utility”
gobbledygook, 2) withhold pertinent details, 3) rake in profits, and 4) pay for more government
ideas.
Page 49
Ordinance 11-20 Public Comment provided 06-08-2020
Do citizens even care? They do! The National Citizen Survey conducted in 2014, 2016, and 2018
evaluated governance in terms of “public confidence”, “acting in the best interest of Estes Park”,
“honesty”, and “fair treatment”. The 2018 results were significantly lower than 2016, and the 2016
results were lower than 2014. A trend going in the wrong direction.
The Town grew General Fund revenues by nearly
one million dollars in just 3 years on the backs of
electric customers.
What about families who struggle financially to pay for rent, food, childcare, and medical services,
among other necessities? Electricity is one of the most essential services in daily life, yet residential
base fees skyrocketed 239% in 3.3 years while the Town raked in more profits. What value did
families receive for digging deeper into their pockets? More importantly, what did families give up?
What about retirees who are living on a fixed income? According to the U.S. Census, residents 65
and older represent 33% of the population living in the 80517-zip code area. What about 44% of
households who make less than $45,000 annually, or the 25% of households who make less than
$30,000 annually? How did this effect their pocketbook?
Fact: A family with two children living in an 800 square foot home pays the same residential base
fee as a family living in a 3,200 square foot home. Targeting electric utility profits to grow
government puts an unfair burden on those who can least afford this life-essential service.
Now, four years later, the Town wants to hike electric rates again, and it’s justifying it with the same
“utility” gobbledygook. In 2020 the Power and Communications Division is planning to transfer
$1,720,029 in profits to the Town’s General Fund. Does the Power and Communications Division
really need more money?
The Town of Estes Park doesn’t have a revenue
problem, it has a spending problem.
The sharp increase in profit transfers from the Power and Communications Division in 2013 and
again in 2017, coincided with the trustee’s approval of the new Event Center (February 2013) and
approval of the parking structure (December 2016). The payment on the Event Center is
approximately $515,000 annually through December 1, 2027. The payment on the parking
structure is approximately $400,000 annually through January 1, 2032. Combined, the Town has a
$915,000 drag on its budget. Is this the reason the Town needed to rake in an additional $1 million
in just 3 years? Is this the real reason behind paid parking?
In 2011, the Town’s General Fund expenditures were $10.8 million. In 2019, the Town’s General
Fund expenditures were $19.7 million, an 82% increase in just 8 years. More employees, more
buildings, more vehicles, and more government ideas. The parking garage sits empty and the event
center is underutilized. Now the Town is launching a for-profit internet service. Will Trailblazer be
successful? If not, the burden shifts to the utility customer.
Page 50
In 2011, sales tax revenue for the General Fund
was $7,422,537. In 2019, it was $13,071,474,
a 76% increase in 8 years.
In the last 8 years, beginning in 2012, sales tax revenue going to the General Fund increased an
average of 7.45% year-over-year. In the last 3 years, beginning in 2017, sales tax revenue for the
General Fund increased an average of 8.43% year-over-year.
In 2019, the sales tax revenue going to the General Fund was a whopping $5.65 million more than in
2011, excluding 1A sales tax revenue that raised more than $14 million in 5 years. Please reflect on
this for just a moment. After citizens approved a 1% sales tax in April 2014, 60% going to local road
repair, the Town still didn’t have enough money. So, in July 2016, trustees approved an increase in
the base electric rates and tapped the consumer for an additional $1 million over a 3-year period to
pay for more government.
More government ideas? More Spending
More debt?
What could possibly go wrong?
As of November 14, 2019, the Town trustees unilaterally raised approximately $26 million through
revenue bonds to build the Town’s high-speed internet infrastructure – a subscription-based, for-
profit business venture known as Trailblazer. Internet is not a life-essential “public” service, yet
every electric customer is now responsible for paying off any portion of the revenue bonds and
interest not met through subscriptions, including those families who can least afford it. Why did the
Town align a risky business venture to an essential utility?
The Town is now fully committed to the buildout of Trailblazer. There is no turning back. In the
post COVID-19 economy, will consumer priorities and purchasing behavior change? In other words,
will consumers rein in discretionary spending? If so, will there be enough subscribers to meet
Trailblazer’s debt payments? If not, stand by for another rate hike.
How did the Town finance its spending
splurge over the past six years?
In February 2013, The Town used the Town Hall municipal building and a portion of the parking lot
as collateral to finance construction of the event center ($6,075,000). In December 2016, the Town
used the 18 Hole Golf Course and two buildings as collateral to finance the upper levels of the
parking garage ($4,225,749). In November 2019, after the town ran out of high value property to
collateralize, they offered up electric customers as bond guarantors so that the Town could build its
state-of-the-art internet service, including “bragging rights” over Longmont ($26,000,000).
Next up? Paid parking in downtown to raise more revenue. And after that? A stormwater
“utility” to raise tens of millions for taming mother nature and protecting those who eagerly
Page 51
purchased property adjacent to mountain rivers. More government debt, more spending, and less
money for the people who earn it. Will the Town ever be satisfied?
Who do we hold accountable? Is it the high-priced consultants who cheer from the sidelines? Is it
Town staff who come up with grand ideas, craft the narrative, and offer creative financing? Is it the
trustees who fail to ask the hard questions? Is it “We” the people?
Over 53% of the residential electric customers
have no voice at the ballot box, and no choice.
On April 24, 2020, there were 3,992 residential electric customers residing inside the Town of Estes
Park (i.e., eligible voters) and 4,568 customers residing in unincorporated Larimer County. Over
53% of “We” the people have zero protections and no political recourse at the ballot box, a crucial
argument since municipally owned utilities operate independently of Colorado’s Public Utilities
Commission.
The long-held legal position has been that citizens retain ultimate authority and control over
municipally owned utilities. If unhappy with rates or service, the “electorate” can replace trustees
on election day. But when 53.4% of non-residents generate a substantial share of the utility profits,
thereby keeping Town property taxes low, is there any incentive for the Town’s electorate to act
(i.e., the law of inverse consequence)?
Town trustees use their authority to set electric rates and approve utility revenue bonds, but
represent just 46.6% of residential electric customers (i.e., eligible voters). The majority, on the
other hand, have no vote, cannot serve as a trustee, or run for mayor. With no vote and no choice,
the majority are left to the “whims and excesses” of Town government. “We” the people are
effectively silenced.
Should municipally owned utilities be a profit center, or should utilities operate as a not-for-profit
service? The most logical explanation for leaning on utility profits to help balance the budget is that
“public permission” is not necessary. Just hire consultants for legitimacy, cleverly craft the
narrative, raise rates incrementally, and hope that no one notices.
Several questions arise:
Is the Power and Communications Division a “municipally owned” utility service if 53.4% of
residential customers live in unincorporated Larimer County? Or should it be treated as a
privately-owned public utility?
Do the trustees of Estes Park have authority to unilaterally set utility rates? Or does the Public
Utilities Commission have jurisdiction and authority? If not, who represents the majority?
Did Town trustees have unilateral authority to obligate electric customers in unincorporated
Larimer County to revenue bonds so that the Town could build a “for-profit” internet service?
Page 52
Email received from Mr. David Standerfer
Board of Trustees Public Comment Form
The Board of Trustees want to hear from members of the community. The following
form was created for general public comment or public comment on any agenda items.
The Town Board of Trustees will participate in meetings remotely due to the Declaration of
Emergency signed by Town Administrator Machalek on March 19, 2020 related to COVID-19
and provided for with the adoption of Ordinance 04-20 on March 18, 2020.
Regular meetings of the Town Board are held on the second and fourth Tuesdays of each
month at 7 p.m. Agendas and the agenda item list below will be posted the Wednesday prior to
each meeting.
Click here to view the current Agenda.
Please enter your full name. (This information is required to ensure the Town keeps accurate records of public
comment.
Name *
Stance on item:*
Public comment must be received by noon the day of the Town Board meeting. All comments will be
compiled for Board distribution prior to the meeting.
Agenda items are available the Wednesday prior to each Town Board meeting. To provide public
comment on an upcoming item please use the drop down below to select the Agenda item title.
Agenda Item Title *
Public comment can be attached using the Upload button below or typed into the text box below.
File Upload
Connie Phipps
For Against Neutral
Ordinance 11-20 Proposed Electric Rate Increase.
If you do not see the Agenda Item Title please email public comment to townclerk@estes.org.
Files are limited to PDF or JPG.
25 MB limit. Video files cannot be saved to the final packet and must be transcribed before submitting.
Ordinance 11-20 - Public Comment received 08-21-2020
Page 53
Comments for the
Board of Trustees:*
Please note, all information provided in this form is considered public record and will be included as permanent record for
the item which it references.
Limited to a maximum of 1000 characters.
The proposed residential electric rate increase is not justified. The electric rate study
is a "tutorial" on how power is received and distributed - - NOT about actual
revenues and expenditures that would indicate a need for increased rates.
The transfer of $1,771,928 from the Light and Power Fund to the General Fund in
December, 2019, is excess income. (Budget: Light & Power Fund Details, Town of
Estes Park). WHY IS THIS RATE INCREASE REQUESTED? The base rate in 2016
was $6.70 or $7.70 depending on rate class and rises steadily to $22.70 and $26.10
in 2019. This is a flat customer charge that has nothing to do with usage and is an
increase of almost 250% and now requesting $9 more per month!
The current base rate in Longmont is $15.25.
There are many low income residents/households that cannot afford these
continued, unnecessary increased.
The rate increase should be denied.
Page 54
August 24, 2020
Dear Mayor and Trustees,
The proposed residential electric rate increase by adding $9 to the base electric charge
is not needed. The increase is not justified.
The electric rate study results is only a tutorial on how power is used and transferred - -
not on budget or costs and revenue balance.
Attached are sheets of information pertaining to the Light and Power Budget. I have numbered these pages at the bottom.
Please look at the Light and Power Fund Final Budget (Page 97 which is my sheet# 1 ).
There is a transfer to the General Fund out of the Light & Power Fund of $1,772,928
after all expenses.
Note that the supply source cost has remained fairly level from 2017 to 2019.
According to the Town of Estes Park, Notes to Financial Statements, December 31,
2018, Note 6 states that annually both the Light and Power and Water Funds subsidizes
the General Fund out of surplus revenues. If the Light and Power Fund has a surplus, it
does not require the additional rate increase to fulfill it's obligation to customers.
If you look at the Electric Rate Summary, my sheet #2, you will see that the base rate in
2016 was $6.70 or $7.70 depending on rate class and rises steadily to $22.70 and
$26.1 0 in 2019. This is an increase in the base rate of almost 250% - -there's
something wrong with this picture! And now asking $9 more! I feel that we have been
overcharged apparently for years? There is definitely a lack of transparency.
There are many low income residents who cannot afford these continued, unnecessary increases. Additionally, since there are surplus Light and Power funds, the town should
look at establishing a relief fund where households having adverse financial consequences due to CoVID may apply and receive help. (Similar to the City of Grand
Junction). The town needs to postpone collections of past due accounts for another six
months until we get through the pandemic.
The rate increase must be denied.
Sincerely,
Connie Phipps 585 Wonderview Ave.
Estes Park, Colorado
Ordinance 11-20 - Public Comment received 08-24-2020
Page 55
CoverHe Data
Debt service ratio•
Bond covenant requirements
Light & Power Fund Details
Enterprise Fund, #502
Town of Estes Park -2019 Budget.xlsx
Actuals Budget
2017 2018
9.18 4.57
1.25 1.25
•oebt service l'lltio = (tollll revenues· total expenditures+ capital+ future vehide replacement+debt
90 days operating coverage• (>1.00) 2.50 1.46
•go day O&M l'lltio = fund balance/(ltollll expenditures· capital-fut veh repl-transfers out-debt svc) x .251
Fund balance $ 8,325,317 $ 5,295,248 $
(90 day coverage -O&M per above) (3,331,690) (3,616 459)
Net fund balance after 90 dav covera1e $ 4 993 627 $ 1678 790 $
Summarv of exoendlture tvnes
Source of Supply $ 7,350,123 $ 7,544,166 $
Personnel
Salaries 2,253,646 2,253,678
Benefits 1,048,975 919,388
Operations & Maintenance 3,013,150 4,099,382
Capital 2,603,399 2,988,552
Debt Service 446,307 446,632
Transfers out 1646,929 1 731 233
$ 18 362 529 $ 19 983 031 $
Personnel FTE Level
Utllltles Director 0.58 0.58
Utllltles Superintendent 0.00 0.00
line Superintendent 1.00 1.00
Crew Chief 1.00 1.00
Lead Lineworker 4.00 4.00
lineworker 5.00 5.00
Line Equipment Speclallst 3.00 3.00
Groundworker 2.00 2.00
Material Mgmt. Speclallst 1.00 1.00
Utility Field Speclallst 1.00 1.00
Meter Technician 1.00 1.00
Meter Technician -Temporary 0.33 0.33
Administrative Assistant 0.70 0.70
Administrative Assistant -Shop 1.00 1.00
Utllltles Coordinator 0.60 0.60
Project Manager 1.00 1.00
Document Technician 0.00 1.00
Facilities Manager 0.07 0.07
Town Clerk 0.48 0.48
Administrative Assistant 0.48 0.48
Administrative Assistant 0.48 0.48
Human Resource Manager 0.48 0.48
Finance Director 0.26 0.26
Accounting Manager 0.26 0.26
Accountant 0.26 0.26
Accounts Payable 0.26 0.26
Utility Billlng Specialist 0.68 0.68
Payroll Technician 0.20 0.20
Administrative Clerk 1/11 (21 1.22 1.22
Town Administrator 0.48 0.48
Assistant Town Administrator 0.48 0.48
Executive Secretary 0.48 0.48
Public Information Officer 0.48 0.48 Total 30.26 31.26
-I
Est Actuals Flnal Budget
2018 2019
12.26 6.68
1.25 1.25
2.70 2.50
9,487,970 $ 8,598,866
(3 517,460) (3,434,514)
5 970 510 $ 5 164 352
7,554,166 $ 7,554,806
2,256,839 2,493,681
� 911,568 988,213
3,698,046 3,014,563
2,232,691 1,942,000
446,632 470,213
1 731,233 1,772,928
18 831,175 $ 18,236 404
0.58 0.58
0.00 0.00
1.00 1.00
1.00 1.00
4.00 3.00
5.00 6.00
3.00 2.00
2.00 3.00
1.00 1.00
1.00 1.00
1.00 1.00
0.33 1.00
0.70 0.70
1.00 1.00
0.60 0.60
1.00 1.00
1.00 1.00
0.07 0.07
0.48 0.48
0.48 0.48
0.48 0.48
0.48 0.48
0.26 0.26
0.26 0.26
0.26 0.26
0.26 0.26
0.68 0.68
0.20 0.20
1.22 1.22
0.48 0.48
0.48 0.48
0.48 0.48
0.48 0.48
31.26 31.93
Page 98 of 134 Page 56
Light and Power Fund
Enterprise Fund, #502
Town of Estes Park -2019 Budget.xlsx
Actuals Budget
2017 2018
Debt Service
BANK FEES $ 150 $ 0
PRINCIPAL ON BONDS 295,000 305,000
INTEREST ON BONDS 151,157 141,632
PRINCIPAL/CAPITAL LEASE 0 0
INTEREST/CAPITAL LEASE 0 0
$ 446,307 $ 446,632
Capital
METERS $ 0 $ 515,000
TRANSFORMERS 0 157,824
COMMUNICATION EQUIPMENT 0 35,000
LABORATORY EQUIPMENT 2,552,304 0
TOOLS 0 40,638
OTHER EQUIPMENT 0 100,000
TRUCKS 0 0
STREET LIGHTS 0 50,000
OVERHEAD LINES 14,278 637,832
UNDERGROUND CONDUCTORS 7,568 568,826
CUSTOMER SERVICE LINES 0 150,000
FIBER OPTIC INSTALL 29,249 597,806
SOFTWARE DEVELOPMENT 0 135,626
$ 2,603,399 $ 2,988,552
-I�-
Est Actuals Final Budget
2018 2019
$ 0 $ 400
305,000 320,000
141,632 129,813
0 15,500
0 4,500
$ 446,632 $ 470,213
$ 515,000 $ 100,000
157,824 150,000
15,000 160,000
0 0
40,638 25,000
100,000 162,000
39,753 0
50,000 20,000
401,334 695,000
195,500 0
275,682 300,000
351,960 250,000
90,000 80,000
$ 2,232,691 $ 1,942,000
Page 100 of 134 Page 57
TOWN OF ESTES PARK, COLORADO
Electric Rate Summary 2016-2019
Customer Rate Class
RESIDENTIAL ..
Available to all residential customers and residential
customers with electric heat up to 25,000 kWh
annually.
·------IIAL i.:=.�."'-.N!:._• �
Available to existing customers on this rate, September
through April. All other times is Residential energy
charge.
RESIDENTIAL ENERGY TIME-OF-DAY .,.
Available to all residential customers using electric
thermal storage heat.
RESIDENTIAL ENERGY BASIC TIME-OF-DAY ..
Available to all residential customers not using electric
thermal storage heat These rates apply September
through April. The standard Residential rate applies
May through August-see sixth column to the far right
SMALL COMMERCIAL .,.
Available to all commercial customers with demands of
35 kW or less.
� -• ·-•.�I '••••--.;,:.-.. -
Available to all commercial customers using electric
thermal storage heat with demands of 35 kW or less
LARGE COMMERCIAL ""
Available to all commercial customers with demands
exceeding 35 kW
LARGE COMMERICIAL TIME-OF-DAY ""
Available to all commercial customers with demands
exceeding 35 kW
OUTDOOR AREA LIGHTING
Available for lighting outdoor private areas
Year
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
2016
Sept '16
2017
2018 2019
On.Peak
Customer Energy
Charge Consumption
$/Month Charge $/kWh
$6.70 $0.11229
$10.70 $0.10885
$14.70 $0.10890
$18.70 $0.10920
$22.70 $0.10950
$7.70 $0.07175
$12.30 $0.06505
$16.90 $0.06508
$21.50 $0.06526
$26.10 $0.06544
$7.70 $0.13054
$12.30 $0.13650
$16.90 $0.14130
$21.50 $0.14700
$26.10 $0.15200
$7.70 $0.13100
$12.30 $0.13500
$16.90 $0.13350
$21.50 $0.13400
$26.10 $0.13450
$9.85 $0.10958
$15.73 $0.10800
$21.61 $0.11000
$27.49 $0.11200
$33.37 $0.11400
$10.85 $0.13510
$17.33 $0.14300
$23.81 $0.15000
$30.29 $0.15600
$36.77 $0.16150
$13.35 $0.05709
$21.32 $0.05355
$29.29 $0.05640
$37.26 $0.05950
$45.23 $0.06250
$15.70 $0.07296
$25.07 $0.07000
$28.12 $0.07350
$35.77 $0.07750
$53.18 $0.08200
$10.77 -
$17.20 -
$23.63 -
$30.06 -
$36.49 -
-�-
ESTES� PARK
COLORADO
Off.Peak Standard
Energy Demand Rate for
Consumption Charge Maythru
Charge $/kW August $/kWh $/kWh ------------- --
10.62 -$12.00 --$12.50 --$13.10 --$13.60 -
$0.07100 --
$0.06820 --
$0.07060 --
$0.07345 --
$0.07595 --
$0.10721 -$0.11229
$0.10812 -$0.10885
$0.10691 -$0.10890
$0.10731 -$0.10920
$0.10771 -$0.10950- --------------
$0.06571
$0.06269 --
$0.06576 --
$0.06839 --
$0.07080 ---$11.14 --$13.00 --$13.65 --$14.25 --$14.80 -
$0.04484 $13.40 -
$0.03795 $15.25 -
$0.03985 $16.00 -
$0.04202 $16.85 -
$0.04446 $17.45 ----------------
Page 58
SERVICE ADDRESS:
Service Period
EL 3/2/2020
WA 3/2/2020
CYCLE
02-43
4/2/2020
4/2/2020
Days
31
31
BILL DATE
4/16/2020
Meter Number
77086619
18904319
DUE DATE
5/5/2020
Mutiplier
100.0000
1000.0000
Units KWH
TGAL
CURRENT CHARGES
SERVICE CONSUMPTION CHARGE TOTAL
CUSTOMER CHARGE
USAGE
WHOLESALE POWER COST
TOTAL ELECTRIC
BASE FEE
WATER USAGE
TOTAL WATER
CITY TAX
TOTAL CURRENT CHARGES PREVIOUS BALANCE DUE NOW TOTAL AMOUNT DUE
.00
570.00 570.00
2000.00 2850.00
22.70
62.42 1.99
42.33 18.75
4.36
87.11
61.08
4.36
152.55
.00
152.55
Last Bill Amount
Payments
Adjustments
Balance Forward
148.87
-148.87
.00
.00
Current Reading
74.22
1762.39
Previous Reading
68.52
1757.54
�
570.0
4850.00
Special Bilt Message
The Town of Estes Park will continue to
support its utility customers during the
COVID-19 pandemic. All penalties and
late fees, as well as all shut offs for
nonpayment, have been suspended.
Please continue making full or partial
payments as you cam. Water and
electric payments may be made at the
curbside utility payment box on
MacGregor Avenue, or at
www.estes.org/onlinepayments
If you have questions or concerns,
please reach out to our Utility Billing
team at 970-577-4800.
UTILITY BILLING OFFICE HOURS: MONDAY -FRIDAY 8 AM-5 PM
TOWN OF ESTES PARK, P.O. BOX 1747, ESTES PARK, CO 80517-1747
PHONE: 970-577-4800 AFTER HOURS EMERGENCIES: 970-586-5335 "(1 www.estes.org
Page 59
ELECTRIC RATE STUDY - FINAL DRAFT
Town of Estes Park, Colorado
Estes Park Power and Communications
REPORT | February 2020
www.newgenstrategies.net
PREPARED BY:
SUSTAINABILITYSTAKEHOLDERSECONOMICSSTRATEGY
Due to COVID-19, the Town of Estes Park chose to delay proposed rates by one year.
The Electric Rate Study was not revised. Delays in proposed rates are marked in red.
Economics | Strategy | Stakeholders | Sustainability
www.newgenstrategies.net
225 Union Boulevard
Suite 305
Lakewood, CO 80228
Phone: (720) 633-9514
February 5,2020
via email
Mr.Reuben Bergsten
Utilities Director
Town of Estes Park
170 MacGregor Ave.
Estes Park,CO 80517
Subject:Electric Cost of Service and Rate Design Study
Dear Mr.Bergsten:
NewGen Strategies Solutions,LLC is pleased to submit the enclosed report to the Town of Estes Park
conveying the analysis,conclusions,and recommendations from the conduct of a comprehensive cost of
service and rate design study for the electric utility.This project could not have been completed without
the assistance of the Town of Estes Park’s staff for which we are very grateful.
We appreciate the opportunity to assist you in this important project.Please contact me if you have any
questions regarding this report.
Sincerely,
NewGen Strategies and Solutions,LLC
Joe Mancinelli
President and CEO
Economics Strategy Stakeholders Sustainability
Table of Contents
Section 1 PROJECT SUMMARY 1 1
Introduction 1 1
Electric Utility Description 1 1
Projected Energy Requirements 1 2
Usage Characteristics by Customer Class 1 2
Financial and Rate Making Tools 1 3
Financial Forecast 1 4
Cost of Service and Rate Design Process Overview 1 5
Cost of Service Results 1 6
Rate Design 1 7
Section 2 REVENUE REQUIREMENT 2 1
Revenue Requirement...................................................................................................2 1
Section 3 COST OF SERVICE 3 1
Functionalization of Revenue Requirement 3 1
Purchased Power Function 3 1
Distribution Function 3 1
Customer Service Function 3 2
Revenue Requirement by Function 3 2
Classification of Costs 3 3
Allocation of Costs 3 4
Customer Class Allocation Factors 3 4
Cost of Service Results 3 7
Cost of Service Results Compared to Current Revenue 3 9
Section 4 RATE DESIGN 4 1
Rate Design Offerings 4 1
Rate Design Objectives 4 2
Electric Rate Structure 4 3
Rate Design Results 4 3
Residential Service R)4 3
Residential Demand Service RD)4 7
Residential Energy Time of Day Service RE)4 8
Residential Energy Basic Time of Day Service RB)4 8
Small Commercial Service C)4 9
Small Commercial Energy Time of Day Service CE).........................................4 11
Large Commercial Service CL)4 12
Large Commercial Time of Day Service CT)4 14
Municipal Service M)4 14
Rocky Mountain National Park Administrative Housing AH)4 15
Rocky Mountain National Park Small Administrative Service AS)4 15
Rocky Mountain National Park Large Administrative Service AL)4 16
Table of Contents
ii
Renewable Energy Charge 4 16
Outdoor Area Lighting 4 17
Revenue Adequacy of Proposed Electric Rates 4 17
Section 5 CONCLUSIONS AND RECOMMENDATIONS 5 1
Conclusions 5 1
Rate Recommendations 5 1
Avoided Cost for Net Meter Customers 5 2
AMI Opt Out Fees 5 2
Other Work Performed 5 3
List of Tables
Table 1 1 Estimated Annual Energy Requirements 1 2
Table 1 2 2022 Summary of Projected Electric Utility Characteristics by Customer
Class 1 3
Table 1 3 Comparison of 2022 Revenues Under 2019 Rates with Cost of Service
Results 1 7
Table 2 1 Revenue Requirement Development 2 3
Table 3 1 Revenue Requirement by Function 3 2
Table 3 2 Functionalized Revenue Requirement 3 3
Table 3 3 Classified Revenue Requirement 3 4
Table 3 4 Demand Allocator Comparisons 3 5
Table 3 5 Energy Allocator Comparisons 3 6
Table 3 6 Unbundled Cost of Service Results by Customer Class 000)1)3 7
Table 3 7 2022 Revenue Shortfall with No Rate Increases 3 9
Table 4 1 Retail Rate Customer Class Sub Customer Class 4 2
Table 4 2 Residential Service Cost of Service,Current,and Proposed Rates 4 4
Table 4 3 Residential Demand Service Cost of Service,Current,and Proposed Rates 4 7
Table 4 4 Residential Energy Time of Day Service Cost of Service,Current,and
Proposed Rates 4 8
Table 4 5 Residential Energy Basic Time of Day Service Cost of Service,Current,
and Proposed Rates 4 8
Table 4 6 Small Commercial Service Cost of Service,Current,and Proposed Rates 4 9
Table 4 7 Small Commercial Energy Time of Day Service Cost of Service,Current,
and Proposed Rates 4 11
Table 4 8 Large Commercial Service Cost of Service,Current,and Proposed Rates 4 12
Table 4 9 Large Commercial Time of Day Service Cost of Service,Current,and
Proposed Rates 4 14
Table 4 10 Municipal Service Cost of Service,Current,and Proposed Rates 4 15
Table 4 11 Rocky Mountain National Park Administrative Housing Service Cost of
Service,Current,and Proposed Rates 4 15
Table 4 12 Rocky Mountain National Park Small Administrative Service Cost of
Service,Current,and Proposed Rates 4 16
Table 4 13 Rocky Mountain National Park Large Administrative Service Cost of
Service,Current,and Proposed Rates 4 16
Table 4 14 Renewable Energy Charge Cost of Service,Current,and Proposed Rates 4 16
Table of Contents
iii
Table 4 15 Outdoor Area Lighting Cost of Service,Current,and Proposed Rates 4 17
Table 4 16 Revenue Requirement and Projected Rate Revenue from Proposed
Rates 4 17
Table 5 1 AMI Opt out Enrollment and Monthly Fees 5 2
List of Figures
Figure 1 1:Financial and Cost of Service Tools and Relationships 1 4
Figure 1 2:Financial Forecast Model Development 1 4
Figure 1 3.Cost of Service Process 1 6
Figure 4 1.Residential Service Rate Comparison 4 5
Figure 4 2.Residential Service Billing Impacts:Percent Change in Bills from 2019 to
2022 4 6
Figure 4 3.Residential Service Billing Impacts:Dollar Change in Bills from 2019 to
2022 4 7
Figure 4 4.Small Commercial Energy Service Rate Comparison 4 9
Figure 4 5.Small Commercial Energy Service Billing Impacts:Percent Change in
Bills from 2019 to 2022 4 10
Figure 4 6.Small Commercial Energy Service Billing Impacts:Dollar Change in Bills
from 2019 to 2022 4 11
Figure 4 7.Large Commercial Service Rate Comparison 4 12
Figure 4 8.Large Commercial Service Billing Impacts:Percent Change in Bills from
2019 to 2022 4 13
Figure 4 9.Large Commercial Service Billing Impacts:Dollar Change in Bills from
2019 to 2022 4 14
Appendix A – Histograms and Cost Curves from Selected Customer Classes
Figure A 1.Residential Demand Rate Comparison
Figure A 2.Residential Demand Billing Impacts:Percent Change in Bills from 2019 to 2022
Figure A 3.Residential Demand Billing Impacts:Dollar Change in Bills from 2019 to 2022
Figure A 4.Residential Energy Time of Day Rate Comparison
Figure A 5.Residential Energy Time of Day Billing Impacts:Percent Change in Bills from 2019
to 2022
Figure A 6.Residential Energy Time of Day Billing Impacts:Dollar Change in Bills from 2019
to 2022
Figure A 7.Residential Basic Energy Time of Day Rate Comparison
Figure A 8.Residential Basic Energy Time of Day Billing Impacts:Percent Change in Bills from
2019 to 2022
Figure A 9.Residential Basic Energy Time of Day Billing Impacts:Dollar Change in Bills from
2019 to 2022
Figure A 10.Small Commercial Energy Time of Day Rate Comparison
Figure A 11.Small Commercial Energy Time of Day Billing Impacts:Percent Change in Bills
from 2019 to 2022
Figure A 12.Small Commercial Energy Time of Day Billing Impacts:Dollar Change in Bills from
2019 to 2022
Figure A 13.Municipal Rate Comparison
Figure A 14.Municipal Billing Impacts:Percent Change in Bills from 2019 to 2022
Figure A 15.Municipal Billing Impacts:Dollar Change in Bills from 2019 to 2022
Table of Contents
iv
Appendix B
Schedule 1 Electric Ten Year Financial Plan
Schedule 2 Functional Unbundling of Test Year Revenue Requirement
Schedule 3 Classification of Purchased Power Costs
Schedule 4 Classification of Distribution Costs
Schedule 5 Classification of Customer Costs
Schedule 6 Cost of Service by Customer Class
Schedule 7 Revenue Summary by Customer Class
Schedule 8 Proposed Rate Schedules
Economics Strategy Stakeholders Sustainability
Section 1
PROJECT SUMMARY
Introduction
In November 2018,the Town of Estes Park,Colorado Town or Estes Park)/Estes Park Power and
Communication EPPC or the Utility)hired NewGen Strategies and Solutions,LLC NewGen)to develop a
Financial Forecast Forecast),Cost of Service COS)and proposed Rate Design Study analysis,collectively
the Study Study),for their electric utility.
The Study determined the total cost of providing electric services,the cost responsibility for the various
customer classes,and the design of rates to safeguard the financial integrity of the utility.The total cost
of providing services predominately includes operations and maintenance O&M)expenses,debt service,
and cash capital outlays required to rebuild and modernize the Electric System System).This Electric Rate
Study Report Report)discusses the process,analyses,and recommendations related to the Study.
The Town’s fiscal year FY)is from January 1 to December 31.Unless otherwise stated in this Report,all
data presented herein is shown in FYs.The Study included an analysis of an estimated Test Year Revenue
Requirement Revenue Requirement),an unbundled COS analysis based on FY 2022 Test Year),a rate
analysis,and the development of proposed new electric rates for several customer classes.Various policy
issues were also identified and discussed.EPPC provided the majority of the System specific data utilized
for the Study.In certain cases,where information was not ava ilable,NewGen developed estimates based
on our experience and publicly available information.Analyses were performed in accordance with
generally accepted industry practices for municipal electric utilities.
Our report contains five sections as follows:
Section 1 Project Summary:Provides an overview of the Study and EPPC
Section 2 Revenue Requirement:Discusses the development of the Revenue Requirement
Section 3 Cost of Service:Provides the COS results through functionalization,classification,and
allocation
Section 4 Rate Design:Presents the proposed electric rates for full requirements service
Section 5 Conclusions and Recommendations:Summarizes conclusions and recommendations
Electric Utility Description
During the Test Year,EPPC is projected to serve,approximately 11,000 retail electric customers with
annual electricity sales of approximately 127 million kilowatt hours kWh).EPPC serves all customers
within the Town,as well as some customers outside the Town.T he electricity supplied to Rocky Mountain
National Park RMNP)is provided by the United States Bureau of Reclamation and the Town is only paid
to deliver that electricity.
Section 1
1 2
Purchased Power / Transmission
Estes Park is one of four owner communities of the Platte River Power Authority Platte River).Platte
River provides the power and owns,operates and purchases transmission capacity for its owner
communities.Platte River initiated wholesale rate changes,which impact the rates and rate structures
for EPPC,and are incorporated into the analysis conducted for this Study.
EPPC Distribution
The EPPC distribution system consists of a total of approximately 330 circuit miles of conductor,of which
approximately 35%are underground.The distribution system has approximately 231 miles of secondary
line,approximately 32%are underground.
Projected Energy Requirements
EPPC’s electric consumption used in the Study is shown in Table 1 1 and is based on estimates made for
the Test Year 2022.Total consumption reflects sales to EPPC retail customers plus System losses of
approximately 4.54%.Energy sales to retail customers were based on EPPC’s projected energy sales
during the Study period.
Table 1-1
Estimated Annual Energy Requirements
Test Year
Retail Sales
kWh)
System
Losses
kWh)
Total Net Energy
for Load (kWh)
2022 127,367,597 6,060,260 133,427,858
Usage Characteristics by Customer Class
The COS analysis examines detailed customer usage characteristics by customer class.Table 1 2
summarizes these characteristics for the existing customer classes,including estimated revenue
generated at 2019 rates in the 2022 Test Year by each customer class and the number of customers in
each customer class,according to EPPC’s electric utility statistics.
PROJECT SUMMARY
1 3
Table 1-2
2022 Summary of Projected Electric Utility Characteristics by Customer Class
Customer Class
Rate
Code(s)
Retail kWh
Sales(1)
No. of
Customers(1)
Revenue at
Current
Rates
Avg. Annual
kWh Sales
per Customer
Avg. Annual
Revenue per
Customer
Residential Service R/RD/RE/RB 57,610,664 8,152 $ 8,749,429 7,067 $ 1,073
Small Commercial C 28,933,187 2,357 4,347,393 12,276 1,845
Small Commercial Energy Time-of-Day CE 679,330 29 85,069 23,738 2,973
Large Commercial CL 35,687,102 113 3,695,196 316,410 32,762
Large Commercial Energy Time-of-Day CT 137,894 1 18,327 137,894 18,327
Municipal M 3,340,617 74 442,979 44,897 5,954
RMNP Administrative Housing (2)AH 9,232 4 1,738 2,308 434
RMNP Small Administrative (2)AS 269,060 22 21,154 12,230 962
RMNP Large Administrative (2)AL 700,510 6 39,490 116,752 6,582
Total 127,367,597 10,758 $ 17,400,775 11,839 $ 1,617
1) Based on a projection from data for 2018 provided by EPPC
2) Electricity provided by the United States Bureau of Reclamation. The Town is paid to deliver the electricity.
Financial and Rate Making Tools
NewGen created three core financial and rate modeling tools.These tools work together and are
integrated to help EPPC make rate and financial related decisions.The tools help EPPC manage the
financial performance of the utility,forecast debt requirements,and rate changes needed for operations
and capital,and translate system wide rate changes into customer class specific rates and bill impacts.
The figure below illustrates the relationship between the tools,their recommended use,and when they
should be updated.
Section 1
1 4
Figure 1-1: Financial and Cost-of-Service Tools and Relationships
Financial Forecast
The financial forecast model is used to optimize the mix of rate changes and debt issues to meet the
electric system financial needs,perform multiple analyses,and identify the key drivers impacting financial
performance.The results of this analysis created the final Revenue Requirement and formed the basis
for the final recommendations for rate changes.This process is summarized in Figure 1 2.
Figure 1-2: Financial Forecast Model Development
Financial
Forecast
Cost of
Service
Rate Design
Impacts
Recommended Use
Apply system wide rate changes
to customer classes
Calculate customer class specific
cost of service and rate
structures
Ensure equity and alignment with
rate strategy
Forecast financial performance
and key financial metrics
Calculate debt and rate funded
capital needs
Calculate system wide rate
changes and scenarios
Update in conjunction with cost
of service
Update fixed and variable
components within customer
class
Update to base or pass through
rate components
Design customer class base and
pass through rates
Fixed and variable rate design
Proof of revenue adequacy
Monthly bill impacts
Update every five years
Update for major changes to
system e.g.,power supply,
new industrial customer,class
consolidation)
Update annually
Significant changes in capital
and/or changes in debt/cash
needs
When to Update
Test Year Revenue
Requirement and Rate
Revenues
EPPC Operating and Capital
Expenses,Audited Rate
Revenues
Forecast Revenue
Requirement and
Revenues
EPPC System Load,
Rates and Expense
Forecasts
Adjust Use of Debt
and Rate Changes
to Cover Costs
EPPC Customer Base
Rate Changes and
Annual Debt Issues
PROJECT SUMMARY
1 5
NewGen developed a ten year financial forecast model for EPPC to evaluate rate changes required to
meet the financial needs of the utility.NewGen reviewed historical and budgeted operating data,capital
expenditures,and operating expenses in the development of the financial forecast.
Cost of Service and Rate Design Process Overview
The COS and rate design process includes five steps as follows:
1.Determination of the Revenue Requirement This first step examines the utility’s financial needs
and determines the amount of revenue that must be generated from rates.For municipal utilities,
the revenue requirement is determined on a cash basis.”A cash basis”analysis examines the
cash obligations of the utility such as O&M expenses,debt service,cash funded capital projects,
transfers,any required contributions to reserves,and payments to the Town.Rates are set such
that the utility can pay its bills on an annual going forward basis.
In preparing our analysis of the electric rates and the development of the revenue requirement,
NewGen relied upon records of operation,customer billing data,and other detailed information
and data compiled and provided by the Town and EPPC’s management and staff.
2.Functionalization and Sub functionalization of Costs The revenue requirement is then assigned
to the particular function or sub function of the utility.Utilities,like Estes Park,typically have
purchased power production,transmission,distribution,and customer services functions.As
indicated,Platte River provides the purchased power production and transmission functions for
EPPC.Distribution sub functions may include distribution infrastructure by voltage,metering,
services,etc.Customer sub functions include billing and collections,customer service,meter
reading,etc.
3.Classification of Costs Once costs are functionalized,costs are then classified based on the
underlying nature of the costs.Of particular importance is the determination of fixed versus
variable costs.Fixed costs remain a financial obligation of the utility regardless of the amount of
energy used whereas variable costs fluctuate based on System energy requirements.Further,
fixed and variable costs are associated with utility requirements to meet customer demand,
energy,and customer service needs.
4.Allocation of Costs Once costs are classified,they are then allocated to the various customer
classes.Allocation factors align with cost classification.Therefore,demand related costs are
allocated on measures of customer class demand such as customer class contribution to the
System coincident peak CP).Energy allocation factors are based on energy consumed by
customers.Customer allocation factors are based on the number of customers.
5.Rate Design The fifth and final step is rate design,which translates COS results into rates for
each customer class.
Section 1
1 6
These first four steps in the COS process are depicted in the figure below.
Figure 1-3. Cost of Service Process
Cost of Service Results
Section 3 of the Report describes the COS process.The results of the COS analysis provide a detailed
assessment of the costs required to serve each of the customer classes.These customer class costs are
unbundled into utility functions and classified into demand,energy,and customer components.customer
class costs are compared to the projected revenues under current rates to determine if current rates are
sufficient to meet costs.Once completed,the COS analysis is the basis for rate design.A comparison of
the Revenue Requirement by customer class and revenues collected under 2019 tariffs is shown in Table
1 3.
PROJECT SUMMARY
1 7
Table 1-3
Comparison of 2022 Revenues Under 2019 Rates with Cost of Service Results
Customer Class
Revenue
Requirement
Projected Revenues
Under 2019
Rates ($)
Projected
Over /
Under)
Recovery ($)
Difference
Residential Service $ 9,343,420 $ 8,749,429 ($ 593,991) (6.8%)
Small Commercial 4,456,635 4,347,393 (109,242) (2.5%)
Small Commercial
Energy Time-of-Day 81,613 85,069 3,456 4.1%
Large Commercial 4,084,202 3,695,196 (389,006) (10.5%)
Large Commercial
Energy Time-of-Day 20,772 18,327 (2,445) (13.3%)
Municipal 387,246 442,979 55,733 12.6%
RMNP Administrative
Housing 3,195 1,738 (1,457) (83.9%)
RMNP Small
Administrative 25,009 21,154 (3,855) (18.2%)
RMNP Large
Administrative 30,126 39,490 9,364 23.7%
Total $ 18,432,217 $ 17,400,775 ($ 1,031,442) (5.9%)
The COS indicates that overall projected costs exceed System rate revenues under 2019 rates by
approximately 5.9%.
Rate Design
Rate design is the culmination of a COS study as the rates and charges for each customer class are designed
to equitably and fully recover the System wide COS and customer class revenue requirements by the end
of the rate period.Section 4 of the Report describes proposed rate design for each cu stomer class.EPPC’s
electric rates include the following components:
Customer Charge
Energy Charge
Demand Charge as applicable)
Wholesale Power Cost Adjustment
Time of Use Charges as applicable)
Renewable Rider as applicable)
Base rates include the customer charge,energy charge,and demand charge,and are applied to the
appropriate monthly billing determinants e.g.,number of customer months,kWh consumption,etc.)to
project the new rate revenues by customer class.These projected revenues from the proposed rates are
compared to the Revenue Requirement to ensure that rates generate sufficient revenue to recover the
Revenue Requirement.
Section 1
1 8
Based on a review of the existing rate structure,it was determined that the cost recovery components
e.g.,customer,energy,and/or demand charges)were not in alignment with the COS results.Proposed
rates in the Study were designed to move each customer class closer to its COS while evaluating the impact
of rate changes on customers’monthly bills.NewGen performed a detailed analysis of monthly bill
impacts associated with proposed rates on the majority of EPPC customers.In consideration of customer
bill impacts,proposed rates,although moving closer to the customer class COS,do not precisely match
the classification of costs for each rate customer class.The Town’s objectives for rate design,as discussed
herein,were also incorporated into the proposed rate design.
Based on our analysis of rate impacts and conversations with EPPC management and staff,it was
determined that new rates would be phased in over a three year period.The first rate changes would be
implemented in 2020,the second in 2021,and the third in 2022.This implementation reduces the overall
rate impact from the proposed changes in base rates in any one year.Additional information and analysis
for EPPC’s proposed rates are included in Section 4 of the Report.
Economics Strategy Stakeholders Sustainability
Section 2
REVENUE REQUIREMENT
As part of the Study,NewGen developed a Revenue Requirement inclusive of all of EPPC’s cash operating
and capital expenses paid for from rates.The Revenue Requirement is based on projected Test Year
operating and financial results.Development of the Revenue Requirement was based on projected cost
information provided by EPPC,the Town and Platte River.The Revenue Requirement development
process is detailed in this section.
Revenue Requirement
To remain financially sound,EPPC’s electric rates must produce sufficient revenues to recover the total
costs of providing electric service to their customers.These costs imposed on the System by customers
are commonly referred to as the utility’s revenue requirement”and consist of normal operating
expenses,debt service,capital improvements and additions,transfers to the Town,non operating
expenses,and reserve requirements.These total revenue requirements are then compared to utility
revenues to evaluate the need for rate changes.The revenue requirement acts as the foundation of a
COS study.
The following is a discussion of the core components of the Revenue Requirement and significant
differences from the 2019 Board adopted final budget and the Revenue Requirement see Table 2 1).The
Revenue Requirement was developed utilizing EPPC’s system of accounts,then allocated to each
functional element of the utility operations purchased power/transmission,distribution,and customer).
Purchased Power
Purchased power costs for EPPC consists exclusively of purchased power costs including transmission)
from Platte River.The Test Year cost for purchased power is based on a Platte River forecast.
Distribution
Distribution includes personnel expenses,professional contracting,repair and maintenance costs,and
other costs associated with utility operations of the distribution system.The Test Year cost for distribution
is based on the 2019 final budget inflated based on the nature of the cost.For example,labor related
costs are increased at 2.1%per year based on the Blue Chip Economic Indicators GDP Chained Price Index.
Customer Service
Customer service includes personnel expenses,professional contracting,and other costs associated with
meeting the customer needs of the utility.The Test Year cost for customer service related costs is based
on the 2019 final budget inflated based on the nature of the cost.
Administration and General
Administration and General includes administrative management services,residential commercial
energy efficiency expenses,franchise fees,and other costs associated with administration and general
functions of the utility.The Test Year cost for administration and general related costs is based on the
2019 final budget inflated based on the nature of the cost.
Section 2
2 2
Debt Service
EPPC has existing debt associated with its Electric System and Fiber/Communications System.The Series
2007 Bond was refinanced in 2019,and this new issue is scheduled to be fully repaid in 2039.The Test
Year debt service is based on the debt service schedule for the new Series 2019 Bond.
General Fund Transfer
The general fund transfer is approximately 10.5%of total revenue.
Change in Working Capital
Change in working capital accounts for any shortfalls between the working capital balance at the
beginning of the year and the working capital goal for that year in order to maintain EPPC’s policy of 90
days of working capital,consistent with EPPC’s bond covenants.
Capital
Capital expenses include costs associated with power line construction,fleet replacements,meter
upgrades,and other capital expenses.The Test Year capital expenses are based on an annualized capital
need assessment,with most of the annual costs increased at 2.1%per year.The Test Year value for these
expenses is projected to be approximately 1,747,792,of which approximately 319,612 is expected to
be funded by customer contributed capital.
Offsets to Revenue Requirement
Offsets to the projected Revenue Requirement include reductions associated with investment income,
miscellaneous non rate revenues,and planned under recovery as developed by the ten year financial
plan,as shown in Appendix B,Schedule 1.
The planned under recovery is reflective of the policy decision to draw down on existing financial reserves
to fully fund capital needs of the utility while allowing rates to be increased more gradually.The ten year
financial plan contemplated a drawdown of reserves but remaining above the 90 day target.
REVENUE REQUIREMENT
2 3
Table 2-1
Revenue Requirement Development
Item
2019 Board
Adopted Difference Test Year
O&M Expenses
Purchased Power $ 7,776,362 $ 364,034 $ 8,140,396
Distribution 3,748,771 594,088 4,342,859
Customer Service 442,985 35,929 478,914
Administration and General 2,304,701 167,708 2,472,409
Subtotal O&M Expense $ 14,272,819 $ 1,161,759 $ 15,434,578
Debt Service $ 449,813 $ 141,488 $ 591,300
General Fund Transfer 1,772,928 225,115 1,998,043
Change in Working Capital - 112,267 112,267
Capital Expenditures 2,292,000 (544,208) 1,747,792
Less Interest Income (78,083) 8,170 (69,913)
Less Miscellaneous Revenue (708,578) 181,732 (526,846)
Less Customer Contributions (300,000) (19,612) (319,612)
Less Planned Under-Recovery (per Financial Plan) (307,503) (227,887) (535,391)
Revenue Requirement $ 17,393,395 $ 1,038,822 $ 18,432,217
Economics Strategy Stakeholders Sustainability
Section 3
COST OF SERVICE
After determining the Revenue Requirement,a COS for each customer class is developed to determine
the specific costs to serve each customer class.Customer class revenues are compared to customer class
Revenue Requirements to evaluate the ability of the current rates to recover costs.NewGen analyzed the
cost to serve each customer class based on the Revenue Requirement developed in Section 2.
Once completed,the COS results indicate the degree to which existing rates recover the costs to serve
customers.The COS results are then used to design new electric rates.
The COS analyses relied on the following key supporting data and analysis:
Revenue Requirement and revenues based on current rates;
System and customer class demand and energy requirements;
Actual and assumed customer service characteristics;and
Information obtained from customer accounts and records.
Functionalization of Revenue Requirement
EPPC’s electric rates were unbundled into three functions:purchased power,distribution,and customer
service,as shown in Appendix B,Schedule 2.The assignment of costs by function falls into two general
categories:1)direct assignments and 2)derived allocations.Direct assignments are costs that are readily
associated with a specific utility function and are directly assigned to that function.For example,the
energy expense is clearly an expense solely related to purchased power,so it is directly assigned to that
function.
Derived allocators are allocation factors that are based on the sum,average,or weighted effect of
different underlying factors.Derived allocators can be complex and should reflect the logical answer to
the following question what underlying activities drive the cost of this item?For example,administrative
and general expenses are associated with the O&M of all utility functions.Thus,administrative and
general expenses are allocated to each utility function using a derived allocator.Each of the three utility
functions is described below.
Purchased Power Function
The production function consists of costs associated with purchased power and transmission services
from Platte River as well as an allocated portion of payment in lieu of taxes,franchise fees and a small
number of other expenses.
Distribution Function
The distribution function consists of costs associated with operating and maintaining the distribution
portion of the electric grid and making capital investments,as necessary.The distribution facilities deliver
power to retail customers after it has been transmitted.This includes low voltage distribution lines,
distribution poles,underground lines,customer service connections,meters,and lighting related assets.
Section 3
3 2
Customer Service Function
The customer service function consists of costs associated with operating and maintaining the
customer related facilities to meet customer support needs.This includes,but is not limited to,customer
service,billing and collection,and meter reading.
Revenue Requirement by Function
The Revenue Requirement determined was unbundled”into the three functional areas of the System
purchased power,distribution,and customer.The results of the functional unbundling are summarized
in Table 3 1.
Table 3-1
Revenue Requirement by Function
Item
Purchased
Power Distribution Customer Total
O&M Expenses
Purchased Power $ 8,140,396 $ - $ - $ 8,140,396
Distribution - 4,342,859 - 4,342,859
Customer - - 478,914 478,914
Administration and General 156,368 1,995,287 320,754 2,472,409
Subtotal O&M Expense $ 8,296,764 $ 6,338,146 $ 799,668 $ 15,434,578
Debt Service $ - $ 591,300 $ - $ 591,300
General Fund Transfer - 1,998,043 - 1,998,043
Change in Working Capital 2,407 97,552 12,308 112,267
Capital Expenditures - 1,370,798 376,994 1,747,792
Less Interest Income (31,360) (35,974) (2,580) (69,914)
Less Miscellaneous Revenue - (20,582) (506,264) (526,846)
Less Customer Contributions - (319,612)- (319,612)
Less Planned Under-Recovery (per Financial Plan) - (535,391)- (535,391)
Revenue Requirement $ 8,267,811 $ 9,484,280 $ 680,126 $ 18,432,217
A comparison of the relative contribution to the Revenue Requirement by function,and average
functional rate is provided in Table 3 2.The average rate was derived from the total expense divided by
total projected energy sales for the Test Year period.
COST OF SERVICE
3 3
Table 3-2
Functionalized Revenue Requirement
Function Revenue Requirement $/kWh % of Total
Purchased Power $ 9,396,018 $0.0649 45%
Distribution 8,419,310 0.0745 51%
Customer 340,877 0.0053 4%
Revenue Requirement $ 18,156,205 $0.1447 100%
The purchased power function represents approximately 45%of the Revenue Requirement.The
distribution function represents approximately 51%of the Revenue Requirement.The customer function
represents approximately 4%of the Revenue Requirement.
Classification of Costs
To provide a reasonable basis for the assignment of the total Revenue Requirement to each customer
class,costs for each function in the Electric System have been analyzed and classified into four rate making
cost classifications,as described below.
Demand Costs Capacity fixed or demand related)costs are those costs incurred to maintain a
utility system in a state of readiness to serve,enabling it to meet the total combined demands of
its customers.Capacity costs include the portion of O&M expenses,debt service,capital
expenditures,and other costs that are generally fixed and do not vary materially with the quantity
of usage or that cannot be designated specifically as a customer or variable cost.
Energy Costs Energy,or variable costs,are costs that vary directly with energy usage,including
such items as fuel,energy related purchased power,and a portion of O&M expenses.
Customer Costs Customer costs are those costs directly related to the number and type of
customers,such as customer accounting,billing,and meter related expenses.
Direct Assignment Costs Direct assignment costs are those costs that are readily identifiable and
applicable to a particular customer or customer class.
Once the costs within each function are assigned to each service category,the demand,energy,customer,
and direct assignment component of each service is calculated.The classification of costs functionalized
to Purchased Power are shown in Appendix B,Schedule 3.The classification of costs functionalized to
Distribution are shown in Appendix B,Schedule 4.The classification of costs functionalized to Customer
are shown in Appendix B,Schedule 5.
As provided in Table 3 3,three major cost categories demand,energy,and customer)cover the majority
of all functional costs.This breakdown of demand,energy,customer,and direct assignment costs is later
applied to each customer class to facilitate rate design,as provided in Section 4.
Section 3
3 4
Table 3-3
Classified Revenue Requirement
Classification
Revenue
Requirement $/kWh
of
Total
Purchased Power
Customer $ 509,556 $0.0040 3%
Energy 4,964,087 0.0390 27%
Demand 2,666,753 0.0209 14%
PILOT, Franchise Fees and Other 127,415 0.0010 1%
Subtotal $ 8,267,811 $0.0649 45%
Distribution
Demand $ 5,208,314 $0.0409 28%
Customer 2,420,247 0.0190 13%
General Fund Transfer 1,855,719 0.0146 10%
Subtotal $ 9,484,280 $0.0745 51%
Customer
Customer $ 680,126 $0.0053 4%
Subtotal $ 680,126 $0.0053 4%
Revenue Requirement $ 18,432,217 $0.1447 100%
In total,approximately 27%of EPPC’s total Revenue Requirement is energy related or variable costs.The
remaining 73%of the Revenue Requirement is fixed in nature and classified as demand,customer,or
directly assigned to particular customer classes.
Allocation of Costs
Once costs are functionalized and classified,they are then allocated to the various customer classes.
Customer Classes represent aggregations of customers that have similar customer usage characteristics
and use the System in a similar manner.
Customer Class Allocation Factors
Based upon actual and assumed customer service characteristics,NewGen developed various factors for
use in allocating the adjusted Revenue Requirements to individual customer classes.These allocation
factors reflect accepted ratemaking principles and were based upon embedded cost allocation
procedures.
We have developed demand related,energy related,customer related,and direct assignment allocation
factors,as described below.
Demand Allocations
Demand allocators are derived based on the demand requirements of individual customers and customer
classes.Purchased Power related demand costs are allocated to customer classes based on the customer
class’s contribution to the System peak,or coincident peak CP)allocators.This is a measure of each
COST OF SERVICE
3 5
customer classes’cost responsibility associated with the infrastructure required to meet the System peak
demand.As you move from the generator to the meter,the measure of peak demand responsibility
changes from a System perspective CP),to a customer class perspective non CP),to a customer
perspective demand at meter).Demand contributions at these various points in the System are
determined based on load research,billing data provided by EPPC,and industry research and experience.
Demand allocators can be based on the one peak month during a year,multiple months such as the four
summer months),or the 12 months of the year,depending on how the underlying costs are incurred cost
causation).
For this Study,the Platte River Summer Summer CP)and Non Summer Non Summer CP)coincident
peaks were used to allocate purchased power related summer and non summer demand costs
respectively.The summer season for Platte River occurs from June through September while the Non
Summer season occurs from October through May.For purchased power transmission demand,a
transmission with ratchet allocator Transmission)was used.The Transmission allocator was a
combination of the EPPC 12 month coincident peak 12CP)allocator and EPPC 1 month coincident peak
1CP)allocator.The 12CP allocator was used to allocate transmission costs before the ratchet,while the
1CP allocator was used to allocate the incremental transmission costs associated with the ratchet.
A Non coincident peak NCP)allocator is typically used to allocate distribution costs.This is a measure of
localized peak demands rather than the System peak demand.The distribution related demand costs
were allocated using a 9 month non coincident peak 9NCP)for substations,overhead,and underground.
For transformers,the sum of max demands SMD)allocator was used.
Table 3 4 compares the various demand allocators utilized in the Study.
Table 3-4
Demand Allocator Comparisons
Customer Class
Summer
CP
Non-Summer
CP Transmission 9NCP SMD
Residential Service 49% 54% 51% 51% 66%
Small Commercial 23% 20% 21% 21% 18%
Small Commercial Energy
Time-of-Day 0% 0%0%0% 0%
Large Commercial 25% 23% 25% 24% 13%
Large Commercial Energy
Time-of-Day 0% 0%0%0% 0%
Municipal 2% 2% 2% 2% 2%
RMNP Administrative Housing 0% 0% 0% 0% 0%
RMNP Small Administrative 0% 0% 0% 0% 0%
RMNP Large Administrative 0% 0% 0% 1% 0%
Total 100% 100% 100% 100% 100%
Note: 0% shown in table may reflect fractions of a percent
Energy Allocations
Energy allocation factors are the basis for allocating costs or expenses classified as variable or
energy related and are assumed to vary directly with kWh sales.Energy related costs classified as variable
were wholesale energy costs and renewable energy from Platte River.Net energy for load NEFL),or the
Section 3
3 6
energy necessary to supply each customer class,is used to allocate these types of costs to individual
customer classes.NEFL is also sometimes called adjusted metered load or energy at generation,as it
takes into consideration energy losses that occur on the transmission and distribution systems between
the power supplier delivery point and the customer’s meter.The energy from production utilized several
different NEFL allocators.Summer energy used a NEFL summer allocator,while non summer energy used
a NEFL non summer allocator.The summer and non summer seasons were based on Platte River’s
seasons.The renewable energy was allocated based on the NEFL allocator.
Table 3 5 lists the energy allocation factors utilized in the Study,which incorporates the losses at the
various levels of the System.
Table 3-5
Energy Allocator Comparisons
Customer Class
Net Energy
for Load
Summer
Net Energy
for Load Non-
Summer
Net Energy
for Load
Residential Service 38%49%46%
Small Commercial 25%22%23%
Small Commercial Energy
Time-of-Day 0%1%1%
Large Commercial 33%26%28%
Large Commercial Energy
Time-of-Day 0%0%0%
Municipal 3%3%3%
RMNP Administrative Housing 0% 0% 0%
RMNP Small Administrative 0% 0% 0%
RMNP Large Administrative 0% 0% 0%
Total 100%100%100%
Note: 0% shown in table may reflect fractions of a percent
Customer Allocations
Customer costs are defined as those costs related to the number of customers and the type of service
required.Included in the customer related costs are the costs associated with meter reading,customer
service,billing,collection,and other customer related activities.The customer allocation factors were
largely based on the number of customers in each customer class.These allocations included a weighting
factor depending on the nature and size of the customer served in each customer class.Weighting reflects
that servicing certain types of customers requires more effort and expenses than other types of
customers.Weighting factors were developed based on discussions with EPPC staff,as well as applying
industry knowledge and practices.Weighting factors derive relationships between the customer classes
and equipment or services needed to serve the customer class and the relative costs of those items.
COST OF SERVICE
3 9
Cost of Service Results Compared to Current Revenue
To evaluate the ability of current rates to adequately recover the COS,NewGen estimated revenues based
on Test Year billing determinants and current rates,then compared resulting revenues to the COS for each
customer class.The results of the comparison are shown in Table 3 7.Note that the Revenue
Requirement in Table 3 7 for RMNP only includes the cost to deliver electricity.
Table 3-7
2022 Revenue Shortfall with No Rate Increases
Customer Class
Revenue
Requirement
Projected Revenues
Under 2019
Rates ($)
Projected
Over /
Under)
Recovery ($)
Difference
Residential Service $ 9,343,420 $ 8,749,429 ($ 593,991) (6.8%)
Small Commercial 4,456,635 4,347,393 (109,242) (2.5%)
Small Commercial
Energy Time-of-Day 81,613 85,069 3,456 4.1%
Large Commercial 4,084,202 3,695,196 (389,006) (10.5%)
Large Commercial
Energy Time-of-Day 20,772 18,327 (2,445) (13.3%)
Municipal 387,246 442,979 55,733 12.6%
RMNP Administrative
Housing 3,195 1,738 (1,457) (83.9%)
RMNP Small
Administrative 25,009 21,154 (3,855) (18.2%)
RMNP Large
Administrative 30,126 39,490 9,364 23.7%
Total $ 18,432,217 $ 17,400,775 ($ 1,031,442) (5.9%)
The percentage increase decrease)shown in the table above provides guidance for future rate design
but does not reflect policy decisions that could impact recommended rates.Recommendations for new
rates are presented in Section 4.
Economics Strategy Stakeholders Sustainability
Section 4
RATE DESIGN
Rate design is the culmination of a COS study where the rates a nd charges for each customer classification
are established in such a manner that the total Revenue Requirement of the Utility will be recovered in
an equitable manner consistent,to the extent reasonable and practical,with EPPC and Town policies.
Consideration was given to the proper level of recovery of fixed costs in the customer and demand
charges,as well as phasing in the proposed rates over time.
Rate Design Offerings
EPPC currently offers a variety of rates to its customers,depending on the nature of the end use of the
electricity e.g.,residential,non residential)and the level of energy consumed.Rate riders offered by
EPPC include a renewable generation option called the Renewable Energy Purchase Program REPP).
Customers may subscribe to the REPP in 100 kWh blocks or opt to have all energy subscribed.The results
of the Study do not suggest the need to change the current renewable rate adder of 0.0275 per kWh for
the REPP.
Table 4 1 provides a summary of the rate customer classes and sub customer classes,the number of
customers in each customer class estimated for the Test Year),the total estimated revenue generated by
each customer class sub customer class for the Test Year unde r proposed rates,and comments regarding
the applicability of each customer class sub customer class see EPPC rate tariffs for specific tariff
applicability rules and regulations).For all seasonal rate applications,EPPC’s summer season includes
billings based on meter reading in the months of May,June,July,and August.The Non summer period
consists of the remaining eight month period.These seasons are different from Platte River.
Section 4
4 2
Table 4-1
Retail Rate – Customer Class / Sub-Customer Class
Customer Class Code
Estimated
Number of
Customers
Test Year)
Estimated
Test Year
Revenues
000)Comments
Residential Energy R 7,631 $ 8,027 Standard residential service
Residential Demand RD 212 569 Optional rate, > 15,000 kWh/year,
closed to new customers
Residential Energy Time-of-Day RE 282 707 Optional rate, only energy storage
for heating
Residential Basic Energy Time-of-Day RB 27 49 Optional rate, open to all residential
customers
Total Residential 8,152 $ 9,352
Small Commercial C 2,357 $ 4,441 Non-Residential use, <= 35 kW
Small Commercial Energy Time-of-Day CE 29 85 Non-Residential use, <= 35 kW,
energy storage for heating
Large Commercial CL 113 4,029 Non-Residential use, > 35 kW in
two consecutive months
Large Commercial Time-of-Day CT 1 20 Non-Residential use, > 35 kW in
two consecutive months
Total Commercial 2,500 $ 8,575
RMNP Administrative Housing AH 4 $ 2 Alternate power source, housing
RMNP Small Administrative AS 22 21 Alternate power source, <= 35 kW
RMNP Large Administrative AL 6 39 Alternate power source, > 35 kW in
two consecutive months
Total RMNP 32 $ 62
Municipal M 74 $ 443 Includes municipal street, park
lighting, and municipal buildings
Total (1)10,758 $ 18,432
1) Excludes outdoor lighting, revenue from which was treated as an offset to the Revenue Requirement
Rate Design Objectives
In general,proposed rate structures for this Study should meet the following objectives and best practices:
Rates should be equitable among customer classes and individuals within customer classes,taking
into consideration the costs incurred to serve each customer class.
Rates may take into consideration other important factors,such as competitive concerns,policies,
or the public interest.
Rates should be simple and understandable.
The foundation of rate design is COS results tempered with policy considerations important to the
community.Specific rate design goals for EPPC include:
RATE DESIGN
4 3
Based on COS results
Improved fixed cost recovery
Phase in rate changes to reduce undue rate impacts to customer classes i.e.,rate shock)
Move towards COS results by customer class to decrease intra class subsidization
Update seasonal price differentiations based on Platte River costs
One of the key rate design policy objectives was related to customer classes that were projected to be
over recovering the COS.These customer classes were eventually going to need rate increases,according
to the ten year financial plan.Thus,the decision was made to set rates for these customers to maintain
the current level of revenue for the customer class.Thus,these customers would move towards COS
gradually over time.This also lessened the need for more drastic rate adjustments for customer classes
that were projected to be under recovering the COS,as illustrated in Appendix B,Schedule 7.
Electric Rate Structure
The proposed base electric rates include a customer charge,an energy charge,and demand charge,where
applicable.Generally,the customer charge should be designed to recover customer related costs;the
energy charge should be designed to recover all applicable power production costs;and the demand
charge should be designed to recover demand related costs.The customer,energy,and demand charges
are commonly referred to as base rates”,as they exclude the rate riders,such as the renewable rate
adder or increases in the purchase power costs passed through to customers via the wholesale power
cost adjustment.
Customer and demand charges generally collect revenues that cover EPPC’s fixed costs.Energy charges
may collect revenues to recover both fixed and variable costs.For customer classes that do not have
demand charges,a large portion of fixed costs may be collected through the energy charge.
Rate Design Results
Appendix B,Schedule 8 includes a summary of all proposed rates by customer class.The proposed rates
are summarized for each customer class below.A histogram of customer monthly billing impacts and
effective rates by load factor or consumption is included to illustrate and compare current rates,proposed
2022 rates,and COS results.Histograms of bill impacts are based on customer usage patterns from
January 2018 to December 2018,as provided by EPPC.
Residential Service (R)
The Residential Service customer class is available to all residential customers.It is composed of
residential customers served on a retail basis and includes a customer charge and an energy charge.Table
4 2 compares the COS rates,current rates,and proposed rates for the Residential Service customer class.
Section 4
4 4
Table 4-2
Residential Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 25.06 22.70 23.47 24.23 25.00
Energy Charge $/kWh 0.1188 0.1095 0.1119 0.1144 0.1168
Wholesale Power Cost
Adjustment Charge (2) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
2) Proposed Wholesale Power Cost Adjustment Charges are estimates
The COS analysis indicates that the customer charge and energy charge are currently lower than the COS.
The proposed customer and energy charges are increased annually from 2020 to 2022 in approximately
equal increments to move the customer class gradually towards COS and improve fixed cost recovery.
The wholesale power cost adjustment is zero for proposed 2020 rates and increases annually to reflect
the estimated increases in the cost of purchased power from Platte River.
Figure 4 1 shows the relationship between customer usage and COS.Low energy users have a higher
average COS per kWh than high energy users.This relationship exists because each customer has a similar
fixed cost associated with infrastructure required to connect the customer to the System and meet their
peak demand requirements.High users are able to spread these fixed costs over more energy resulting
in a lower average rate.Increasing the Residential Service customer charge improves fixed cost recovery
and reduces subsidies between customers within the Residential Service customer class.
2021 2022 2023
2021 2022 2023
2021 2022 2023
RATE DESIGN
4 5
Figure 4-1. Residential Service Rate Comparison
Bill Impacts
Customer bill impacts,on a percentage basis,for all residential customers is shown in Figure 4 2 reflecting
the change from 2019 to 2022 rates).
Section 4
4 6
Figure 4-2. Residential Service Billing Impacts: Percent Change in Bills from 2019 to 2022
Customer bill impacts,on a dollar basis,for all residential customers is shown in Figure 4 3 reflecting the
change from 2019 to 2022 rates).
RATE DESIGN
4 7
Figure 4-3. Residential Service Billing Impacts: Dollar Change in Bills from 2019 to 2022
Residential Demand Service (RD)
The Residential Demand Service customer class is an optional rate for customers that use electricity as a
primary source of heat,as well as use greater than 15,000 kWh over 12 months.The demand charge is
only assessed in the winter season September through April)and the energy charge switches to the
Residential Service energy charge during the summer May through August).This rate tariff is closed to
new customers.Table 4 3 compares the COS rates,current rates,and proposed rates.
Table 4-3
Residential Demand Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 27.46 26.10 26.90 27.70 28.50
Energy Charge Summer (1) $/kWh 0.1126 0.1095 0.1119 0.1144 0.1168
Energy Charge Winter $/kWh 0.0365 0.0654 0.0645 0.0636 0.0627
Demand Charge $/kW 12.53 13.60 13.60 13.60 13.60
Wholesale Power Cost
Adjustment Charge (2) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) Equal to the Residential Service customer class energy charge
2) Proposed Wholesale Power Cost Adjustment Charges are estimates
2021 2022 2023
Section 4
4 8
The histograms and cost curves for the Residential Demand Service customer class can be found in
Appendix A.
Residential Energy Time-of-Day Service (RE)
The Residential Energy Time of Day Service customer class is an optional rate available to all residential
customers who use energy storage equipment for space heating.Table 4 4 compares the COS rates,
current rates,and proposed rates.
Table 4-4
Residential Energy Time-of-Day Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 27.76 26.10 26.90 27.70 28.50
Energy Charge On-Peak $/kWh 0.1689 0.1520 0.1566 0.1612 0.1658
Energy Charge Off-Peak $/kWh 0.0928 0.0760 0.0806 0.0852 0.0898
Wholesale Power Cost
Adjustment Charge (2) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
2) Proposed Wholesale Power Cost Adjustment Charges are estimates
The histograms and cost curves for the Residential Energy Time of Day Service customer class can be
found in Appendix A.
Residential Energy Basic Time-of-Day Service (RB)
The Residential Energy Basic Time of Day Service customer class is an optional rate available to all
residential customers.The energy charge for this customer class is only assessed during the winter season
September through April).During the summer season May through August)the standard Residential
Service energy charge is assessed.Table 4 5 compares the COS rates,current rates,and proposed rates.
Table 4-5
Residential Energy Basic Time-of-Day Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 28.08 26.10 26.90 27.70 28.50
Energy Charge Summer (2) $/kWh 0.1166 0.1095 0.1119 0.1144 0.1168
Energy Charge Winter On-Peak $/kWh 0.1689 0.1345 0.1470 0.1595 0.1719
Energy Charge Winter Off-Peak $/kWh 0.0928 0.1077 0.1038 0.0998 0.0959
Wholesale Power Cost
Adjustment Charge (3) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
2) Equal to the Residential Service customer class energy charge
3) Proposed Wholesale Power Cost Adjustment Charges are estimates
2021 2022 2023
2021 2022 2023
RATE DESIGN
4 9
The histograms and cost curves for the Residential Energy Basic Time of Day Service customer class can
be found in Appendix A.
Small Commercial Service (C)
The Small Commercial Service customer class is composed of commercial users served at primary and
secondary voltages with maximum monthly usage that does not exceed 35 kW.Table 4 6 compares the
COS rates,current rates,and proposed rates.
Table 4-6
Small Commercial Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 25.22 33.37 33.25 33.12 33.00
Energy Charge $/kWh 0.1266 0.1140 0.1154 0.1169 0.1183
Wholesale Power Cost
Adjustment Charge (2) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
2) Proposed Wholesale Power Cost Adjustment Charges are estimates
Figure 4 4 shows the relationship between customer usage and COS for the Small Commercial Service
customer class.
Figure 4-4. Small Commercial Energy Service Rate Comparison
2021 2022 2023
Section 4
4 10
Bill Impacts
Customer bill impacts for customers in this customer class are provided in Figure 4 5 and Figure 4 6.
Figure 4-5. Small Commercial Energy Service Billing Impacts: Percent Change in Bills from 2019 to 2022
RATE DESIGN
4 11
Figure 4-6. Small Commercial Energy Service Billing Impacts: Dollar Change in Bills from 2019 to 2022
Small Commercial Energy Time-of-Day Service (CE)
The Small Commercial Energy Time of Day Service customer class is an optional rate available to all small
commercial customers who use energy storage equipment for space heating with on peak demands that
do not exceed 35 kW.Table 4 7 compares the COS rates,current rates,and proposed rates.
Table 4-7
Small Commercial Energy Time-of-Day Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 25.22 36.77 36.51 36.26 36.00
Energy Charge On-Peak $/kWh 0.1353 0.1615 0.1526 0.1438 0.1349
Energy Charge Off-Peak $/kWh 0.0876 0.0708 0.0763 0.0818 0.0872
Wholesale Power Cost
Adjustment Charge (2) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
2) Proposed Wholesale Power Cost Adjustment Charges are estimates
The histograms and cost curves for the Small Commercial Energy Time of Day Service customer class can
be found in Appendix A.
2021 2022 2023
Section 4
4 12
Large Commercial Service (CL)
The Large Commercial Service customer class is available for commercial customers with demands more
than 35 kW for two consecutive months.Table 4 8 compares the COS,current rates,and proposed rates.
Table 4-8
Large Commercial Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 252.23 45.23 45.49 45.74 46.00
Energy Charge $/kWh 0.0547 0.0625 0.0633 0.0640 0.0648
Demand Charge $/kW 19.55 14.80 15.87 16.93 18.00
Wholesale Power Cost
Adjustment Charge (1) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) Proposed Wholesale Power Cost Adjustment Charges are estimates
Figure 4 7 shows the relationship between customer usage and average COS.There is a wide range of
load factors with a significant number of customers clustered between 20%and 50%.Load factor is a
measure of efficiency and is the relationship between monthly demand and monthly energy usage.Higher
load factor reflects a more efficient use of the System.The average monthly demand was approximately
61 kW.Note:the load factor percentages reflected in the figure represent the high end of the 10%range
i.e.,the count of customers shown at 100%load factor represents the customers with load factor
between 90%and 100%).
Figure 4-7. Large Commercial Service Rate Comparison
2021 2022 2023
RATE DESIGN
4 13
Bill Impacts
Customer bill impacts for customers in this customer class are provided in Figure 4 8 and Figure 4 9.
Figure 4-8. Large Commercial Service Billing Impacts: Percent Change in Bills from 2019 to 2022
Section 4
4 14
Figure 4-9. Large Commercial Service Billing Impacts: Dollar Change in Bills from 2019 to 2022
Large Commercial Time-of-Day Service (CT)
The Large Commercial Time of Day Service customer class is available for commercial customers with
demands more than 35 kW for two consecutive months.Table 4 9 compares the COS rates,current rates,
and proposed rates.
Table 4-9
Large Commercial Time-of-Day Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 252.23 53.18 53.79 54.39 55.00
Energy Charge On-Peak $/kWh 0.0774 0.0820 0.0848 0.0876 0.0904
Energy Charge Off-Peak $/kWh 0.0365 0.0445 0.0461 0.0478 0.0495
Demand Charge $/kW 19.49 17.45 18.30 19.15 20.00
Wholesale Power Cost
Adjustment Charge (1) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) Proposed Wholesale Power Cost Adjustment Charges are estimates
Municipal Service (M)
The Municipal Service customer class is available for municipal street,park lighting,and municipal
buildings.Table 4 10 compares the COS rates,current rates,and proposed rates.
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%($
500)($464)($429)($393)($357)($
321)($286)($250)($
RATE DESIGN
4 15
Table 4-10
Municipal Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 75.67 0.00 9.00 18.00 27.00
Energy Charge $/kWh 0.0929 0.1171 0.1149 0.1128 0.1106
Wholesale Power Cost
Adjustment Charge (2) $/kWh 0.0028 0.0035 0.0000 0.0014 0.0028
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
2) Proposed Wholesale Power Cost Adjustment Charges are estimates
The Municipal Service rate structure changes significantly with the introduction of a customer charge.
This aligns the Municipal Service customer class with the other retail customers.The histograms and cost
curves for the Municipal Service customer class can be found in Appendix A.
Rocky Mountain National Park Administrative Housing (AH)
The Rocky Mountain National Park Administrative Housing Service customer class is available for Rocky
Mountain National Park service administrative single housing accounts.There are no rate changes
proposed for this customer class.Table 4 11 compares the COS rates,current rates,and proposed rates.
Note that this customer class has no wholesale power cost adjustment charge since the power from Platte
River is paid for directly by the U.S.Bureau of Reclamation.
Table 4-11
Rocky Mountain National Park Administrative Housing Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 21.65 22.70 22.70 22.70 22.70
Energy Charge $/kWh 0.2323 0.0690 0.0690 0.0690 0.0690
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
Rocky Mountain National Park Small Administrative Service (AS)
The Rocky Mountain National Park Small Administrative Service customer class is available for Rocky
Mountain National Park service administrative accounts with maximum demand equal to or less than 35
kW.There are no rate changes proposed for this customer class.Table 4 12 compares the COS rates,
current rates,and proposed rates.Note that this customer class has no wholesale power cost adjustment
charge since the power from Platte River is paid for directly by the U.S.Bureau of Reclamation.
2021 2022 2023
2021 2022 2023
Section 4
4 16
Table 4-12
Rocky Mountain National Park Small Administrative Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS (1)
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 21.65 33.37 33.37 33.37 33.37
Energy Charge $/kWh 0.0715 0.0456 0.0456 0.0456 0.0456
1) The fixed demand-related costs are shown in the energy COS because this customer class does not have a demand charge
Rocky Mountain National Park Large Administrative Service (AL)
The Rocky Mountain National Park Large Administrative Service customer class is available for Rocky
Mountain National Park service administrative accounts with maximum demand greater than 35 kW.
There are no rate changes proposed for this customer class.Table 4 13 compares the COS rates,current
rates,and proposed rates.Note that this customer class has no wholesale power cost adjustment charge
since the power from Platte River is paid for directly by the U.S.Bureau of Reclamation.
Table 4-13
Rocky Mountain National Park Large Administrative Service
Cost of Service, Current, and Proposed Rates
Item Unit
COS
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 21.65 45.23 45.23 45.23 45.23
Energy Charge $/kWh 0.0000 0.0185 0.0185 0.0185 0.0185
Demand Charge $/kW 15.33 12.50 12.50 12.50 12.50
Renewable Energy Charge
The renewable energy charge is an optional charge added to all otherwise applicable energy charges,
including the wholesale power cost adjustment charge,for customers that would like to support
renewable generation.It is available to all customer classes and customers may subscribe in 100 kWh
blocks or opt to have all energy subscribed.Currently residential,residential energy time of day,small
commercial,and municipal customer classes contain renewable energy subscribers.There are no rate
changes proposed for this rate.Table 4 14 compares the current rates,the COS rates,and the proposed
rates.
Table 4-14
Renewable Energy Charge
Cost of Service, Current, and Proposed Rates
Item Unit
COS
2022
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Subscribed Customers $/kWh 0.0254 0.0275 0.0275 0.0275 0.0275
2021 2022 2023
2021 2022 2023
2021 2022 2023
RATE DESIGN
4 17
Outdoor Area Lighting
The Outdoor Area Lighting customer class is available for outdoor private lighting and is a flat monthly
rate per fixture.In this analysis,outdoor lighting revenue was treated as an offset to the Revenue
Requirement and the expenses for outdoor lighting were not segregated from other expenses.There are
no rate changes proposed for this rate.Table 4 15 compares the current rates,the COS rates,and the
proposed rates.
Table 4-15
Outdoor Area Lighting
Cost of Service, Current, and Proposed Rates
Item Unit
Current
2019
Proposed
2020
Proposed
2021
Proposed
2022
Customer Charge $/Month 36.49 36.49 36.49 36.49
Revenue Adequacy of Proposed Electric Rates
The rates presented in this section have been designed to recover revenues equal to the Revenue
Requirement in the final year of the rate plan and to incorporate the rate strategies enclosed herein.
Rates were designed based on forecasted billing information provided and utilizing information from the
2018 billing data.To the extent actual billing determinants vary from projections,actual revenues may
vary from the expected revenues as presented herein.Table 4 16 shows the projected Revenue
Requirement and the projected revenue from proposed 2022 rates.
Table 4-16
Revenue Requirement and Projected Rate Revenue from Proposed Rates
Customer Class
Revenue
Requirement
2022
Projected
Revenue
Over/(Under)
Recovery
Residential Service $ 9,343,420 $ 9,351,732 $ 8,312
Small Commercial 4,456,635 4,441,023 (15,612)
Small Commercial Energy Time-of-Day 81,613 85,069 3,456
Large Commercial 4,084,202 4,028,609 (55,592)
Large Commercial Energy Time-of-Day 20,772 20,423 (349)
Municipal 387,246 442,979 55,733
RMNP Administrative Housing 3,195 1,738 (1,457)
RMNP Small Administrative 25,009 21,154 (3,855)
RMNP Large Administrative 30,126 39,490 9,364
Total System $ 18,432,217 $ 18,432,217 $ 0
2021 2022 2023
Economics Strategy Stakeholders Sustainability
Section 5
CONCLUSIONS AND RECOMMENDATIONS
In reliance upon the data received by EPPC,the Town,and Platte River,and the analyses described herein,
we conclude and recommend the following.
Conclusions
Revenue Requirement
Based on our development of the Revenue Requirement,current and projected costs exceed
current rates.On a System wide basis,current rate revenues require a 5.9%increase.
Cost of Service
The rates for several customer classes are below their COS,while some are currently above
their COS.However,the customer classes that are currently above their COS are projected to
eventually need rate increases according to the ten year financial plan.
Rate Design
EPPC’s rates require modification to better align with the COS and policy objectives of the
Town.
Although not reflected in the proposed rates in Section 4,the Town could also consider
eliminating the Residential Demand Service customer class,which is currently closed to new
customers.If these roughly 200 customers were moved to the regular Residential Service
customer class,the Town is projected to collect approximately the same revenue annually
from these customers.Eliminating the Residential Demand Service customer class would
simplify the overall rate tariff as well as residential rate options and ease the administrative
burden on EPPC.
Rate Recommendations
Based on our conclusions,and supporting analyses,NewGen recommends the following:
The Town should adopt rates that reduce subsidization among customer classes.The majority of
EPPC’s rate structure should be modified to improve fixed cost recovery in a gradual manner.
The Town should adopt the rate plan as proposed in this Report.
EPPC should continue to perform a comprehensive COS study every two to three years,or when
aligned with a major change,such as significant changes in projected price for purchased power,a
new large industrial customer,or significant change in System operations.
If EPPC is going to allow customers to opt out of an AMI capable meter a one time enrollment fee
of 75 and a monthly fee of 20 should be charged to defray the costs of accommodating these
customers as discussed below).
Section 5
5 2
Avoided Cost for Net Meter Customers
Customers with on site renewable generation e.g.,solar panels)may qualify to be paid for energy
generated,in excess of what the customer uses,annually at what is referred to as the avoided cost.The
avoided cost is determined by the blended cost per kWh for energy supplied by Platte River,less 0.01
per kWh for administrative costs.The costs for EPPC administering this program are likely more than
0.01 per kWh,but only subtracting 0.01 per kWh allows for a generous interpretation of the avoided
cost.
AMI Opt-Out Fees
As automated metering infrastructure AMI)or advanced meters become more commonplace with
utilities,many customers are becoming more comfortable and aware of the technology.However,utilities
still face customers who wish to opt out of having an advanced meter on their home.EPPC should
consider fees for customers who choose to opt out of the advanced meter and AMI system,thus
requesting a digital meter without radio transmitting capability that requires manual meter reading and
related customer billing support.
Several utilities have implemented an initial cost to install the non AMI capable meter,or an enrollment
fee”,related to potential increased cost for the non AMI meter.Additional monthly fees are typically
assessed related to a meter reader’s time,transportation to read the meter,and the cost to upload the
meter read to the customer billing system.Secondary research summarized in Table 5 1 shows one time
enrollment fees as well as monthly charges to recover the ongoing costs of manual meter reading and
customer data.Secondary research also suggests less than 0.5%of customers will opt out of an advanced
meter.
Table 5-1
AMI Opt-out Enrollment and Monthly Fees
Utility / Jurisdiction
Enrollment
Fee (One-time) Monthly Fee
Austin Energy (Texas) $75 $10
AEP Texas Central $105 - $214 (1) $19
AEP Texas North $105 - $257 (1) $36
CenterPoint $204 (2) $33
Oncor $191 - $564 (1) $27
California $75 $10
Maryland $75 $11 - $17
Keys Energy (Florida) $90 $15
Lafayette Utilities System (Louisiana) Unknown $12.20
United Power None $19.83
1) Fees based on existing meter remaining, new analog meter installed, and AMI with disabled
communications.
2) CenterPoint charges a minimum of $204, plus the incremental difference in the cost between
a standard meter and the advanced meter functionality.
CONCLUSIONS AND RECOMMENDATIONS
5 3
Based on this secondary research,NewGen recommends that,if the Town is going to allow customers to
opt out of an AMI capable meter,a one time enrollment fee of 75 and a monthly fee of 20 should be
charged to defray the costs of accommodating these customers.
Other Work Performed
For other work performed by EPPC,such as meter replacements or line extensions,the developer or
customer must pay for work performed as required to meet their needs and EPPC’s standards.Payment
must be made before the work is scheduled.The amount of payment will be estimated based on the cost
of labor,materials,equipment,and overhead.
Economics Strategy Stakeholders Sustainability
Appendix A
HISTOGRAMS AND COST CURVES
Economics Strategy Stakeholders Sustainability
Appendix A
HISTOGRAMS AND COST CURVES
Figure A-1. Residential Demand Rate Comparison
Appendix A
A 2
Figure A-2. Residential Demand Billing Impacts: Percent Change in Bills from 2019 to 2022
Figure A-3. Residential Demand Billing Impacts: Dollar Change in Bills from 2019 to 2022
HISTOGRAMS AND COST CURVES
A 3
Figure A-4. Residential Energy Time-of-Day Rate Comparison
Figure A-5. Residential Energy Time-of-Day Billing Impacts: Percent Change in Bills from 2019 to 2022
Appendix A
A 4
Figure A-6. Residential Energy Time-of-Day Billing Impacts: Dollar Change in Bills from 2019 to 2022
Figure A-7. Residential Basic Energy Time-of-Day Rate Comparison
HISTOGRAMS AND COST CURVES
A 5
Figure A-8. Residential Basic Energy Time-of-Day Billing Impacts: Percent Change in Bills from 2019 to 2022
Figure A-9. Residential Basic Energy Time-of-Day Billing Impacts: Dollar Change in Bills from 2019 to 2022
Appendix A
A 6
Figure A-10. Small Commercial Energy Time-of-Day Rate Comparison
Figure A-11. Small Commercial Energy Time-of-Day Impacts: Percent Change in Bills from 2019 to 2022
HISTOGRAMS AND COST CURVES
A 7
Figure A-12. Small Commercial Energy Time-of-Day Billing Impacts: Dollar Change in Bills from 2019 to 2022
Figure A-13. Municipal Rate Comparison
Appendix A
A 8
Figure A-14. Municipal Billing Impacts: Percent Change in Bills from 2019 to 2022
Figure A-15. Municipal Billing Impacts: Dollar Change in Bills from 2019 to 2022
Economics Strategy Stakeholders Sustainability
Appendix B
SCHEDULES