HomeMy WebLinkAboutPACKET Public Works, Utilities and Public Safety 2011-04-14Preparation date: April 4, 2011
NOTE: The Public Safety, Utilities and Public Works Committee reserves the right to consider other
appropriate items not available at the time the agenda was prepared.
AGENDA
TOWN OF ESTES PARK
PUBLIC SAFETY, UTILITIES & PUBLIC WORKS COMMITTEE
April 14, 2011
8:00 a.m.
Board Room, Town Hall
1. PUBLIC COMMENT
2. PUBLIC SAFETY
a) RECOMMENDATIONS TO THE TOWN BOARD
i) Amending Section 9.08.080 Harassment. Commander Rose
b) REPORTS
i) Strategic Plan Update. Chief Kufeld
3. UTILITIES
a) RECOMMENDATIONS TO THE TOWN BOARD
i) Purchase Power Rider. Dir. Bergsten
b) REPORTS
i) Integrated Resource Plan Draft. John Bleem/PRPA
ii) Energy Efficiency Updates. Dir. Bergsten
iii) Marys Lake Water Treatment Plant Update. Supt. Boles
4. PUBLIC WORKS
a) RECOMMENDATIONS TO THE TOWN BOARD
i) Snow Plow Truck Replacement. Supt. Mahany
b) REPORTS
i) Introduction of Kevin Ash. Dir. Zurn
5. ADJOURN
Page 1
UTILITIES
Memo
To: Public Safety/Utilities/Public Works Committee (PUP Committee)
From: Reuben Bergsten, Interim Utilities Director
Date: 14 April 2011
RE: Purchase Power Rider
Background:
In 1991 a purchase power rider was introduced to pass through changes in wholesale
power costs.
Wholesale electric power costs from Platte River Power Authority (PRPA) can change
during a period when Estes Park electric rates have already been established. These
wholesale power costs account for approximately 50% of Estes Park Light and Power's
expenses. An increase in this expense would be too large to be absorbed. The
Purchase Power Rider ordinance stabilizes the Light and Power Budget and reduces
costs associated with rate hearings.
The wholesale Power Cost Adjustment (PCA, formerly known as Purchase Power
Rider) is an increase or decrease in electric rates, based on wholesale electric costs
from PRPA. The PCA is listed on our customer's electric bill as a separate line item.
This line item is not shown when the PCA is zero.
In 2009 staff identified the need to include wholesale renewable energy surcharges in
the PCA ordinance. In addition to adding a PCA for renewable energy, this ordinance
will change the name from the obscure term Purchase Power Rider to the industry
accepted name of Wholesale Power Cost Adjustment.
Page 2
UTILITIES
Memo
Budget: N/A
Recommendation:
I recommend the acceptance/denial of the attached Wholesale Power Cost Adjustment
Ordinance to Town Board, to be included as an action item at the April 26, 2011, Town
Board meeting.
ORDINANCE NO. ##-11___
AN ORDINANCE GRANTING THE
LIGHT AND POWER UTILITY THE AUTHORITY TO IMPLEMENT
A WHOLESALE POWER COST ADJUSTMENT RATE
WHEREAS, the Board of Trustees has determined that it is necessary to grant
limited authority to the Light and Power Department to modify 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:
Section 1: That the Light and Power Rate Schedules shall be changed as more fully
set forth on Exhibit “A”.
Section 2: These rate changes will coincide with wholesale cost changes .
PASSED AND ADOPTED BY THE BOARD OF TRUSTEES OF THE TOWN OF ESTES
PARK, COLORADO THIS DAY OF . 2007.
TOWN OF ESTES PARK
By:
Mayor
ATTEST:
Town Clerk
I hereby certify that the above Ordinance was introduced and read at a regular
meeting of the Board of Trustees on the____ day of ___________, 2011 and
published in a newspaper of general circulation in the Town of Estes Park, Colorado,
on the ________ day of , 2011, all as required by the Statutes of
the State of Colorado.
Jackie Williamson, Town Clerk
ORDINANCE NO. ##-11___
EXHIBIT A
Wholesale Power Cost Adjustment
Applicability
The Wholesale Power Cost Adjustment rate set forth in this ordinance shall be
applicable in Estes Park's service territory to all applicable electric rate schedules.
Purpose
The wholesale power cost adjustment will pass on changes in the wholesale electric
tariffs and wholesale renewable energy tariffs from our wholesale electric power
provider.
Authority
The Estes Park Town Board, as the governing body of The Town of Estes Park Light
and Power electric utility, grants authority to the Town of Estes Park Light and Power
Utility, to change electric rates based on this Wholesale Power Cost Adjustment
ordinance. The circumstance necessitating the PCA is a wholesale electric tariff change
which the Town Board does not control. Under this circumstance, the Town Board will
not require thirty days notice and a public hearing. The amount of change shall be
calculated as set forth in this ordinance. The timing of the PCA rate change must
coincide with the wholesale electric energy purchased under the new wholesale tariffs.
Method of Determining the wholesale Power Cost Adjustment (PCA) and Renewable
Energy Surcharge Power Cost Adjustment (PCAR)
1. Formula for determining the PCA:
PCA= (New wholesale costs - Current wholesale costs) / Current kWh sales
a. Current wholesale costs = The most recent twelve months' cost of
wholesale power purchased from PRPA by the Town, using the most
current twelve months of invoices, excluding renewable energy
surcharges
b. Current kWh sales = the electric kWh sales to the Town's customers for
the same twelve-month period as the current wholesale cost.
c. New wholesale costs = New wholesale tariff applied to the wholesale
power purchased for the same twelve-month period as used for the
current wholesale costs.
2. The power cost adjustment shall be calculated to the nearest one-hundredth of a
mill ($0.00001) per kWh.
ORDINANCE NO. ##-11___
3. The electric rate schedules with demand rates may as an option have the PCA
spread between the energy and the demand rates. The demand portion shall be
set as $/kW.
4. Formula for determining the renewable energy surcharge PCAR:
PCAR= New wholesale renewable energy surcharge tariff - Current wholesale
renewable energy surcharge tariff
a. Current wholesale renewable energy surcharge tariff = The most recent
wholesale renewable energy surcharge tariff.
b. New wholesale renewable energy surcharge tariff = The new wholesale
renewable energy surcharge tariff.
5. Consecutive changes in wholesale tariffs will produce a cumulative PCA and
PCAR.
6. Publication of the rate change will be given to every customer of the Town of
Estes Park Light & Power by including the PCA as separate line item on their bill.
LIGHT & POWER Report
To: PUP Committee
From: John Bleem
Division Manager, Platte River Power Authority
Date: April 14, 2011
RE: Integrated Resource Plan Draft
An initial draft of the 2012 Integrated Resource Plan (IRP) is included in the Board
packet. Proposed components of this IRP have been discussed at Platte River Board
meetings in September, October and December of 2010 and February 2011. At the
upcoming Committee meeting, a brief overview of the draft IRP will be presented.
Note that no new firm capacity resources are needed during the term of the next IRP,
since existing hydro, coal and gas resources are sufficient to meet projected firm
Municipal loads beyond the five-year term of this IRP (2012-2016). However, this draft
IRP includes an updated load forecast, a projection of the anticipated future load /
resource balance, an updated set of criteria for acquisition of new firm capacity over the
longer term, a joint plan for demand side management and a summary of renewable
energy planning. These items are important to ongoing integrated electric resource
planning and may be of interest to the public.
The draft IRP will be posted for public review during April. Presentations on the draft
IRP will also be made to other local boards during April and copies will be provided to
interested parties. A public hearing on the IRP is planned for the Board meeting on
April 28th. Approval of a final 2012 IRP by the Board of Directors is anticipated at the
May 26th meeting. After approval, the IRP will be submitted to Western Area Power
Administration, as part of the requirements of the 1992 Energy Policy Act.
Staff from Platte River will be available to answer any questions that the Committee
may have regarding the draft IRP.
INTEGRATED RESOURCE PLAN
INITIAL DRAFT
Estes Park Utilities Committee
April 14, 2011
IRP Development Timeline
Sep 2010
Initial
Review
Dec 2010
DSM
Program
Overview
New
Resource
Addition
Criteria
Mar 2011
Draft
IRP
Review
May 2011
Final IRP
Approval &
Submittal
Oct 2010
Updated
Forecast
(2011+)
April 2011
Public
Process
Public
Process
Draft
Plan
Feb 2011
Renewable
Energy
√
√
√
√
√
√
Load Forecast & Trends
Current Resources
Loads / Resource Balance:
Criteria for adding new resources
Projected timing
Renewable Energy
Demand Side Management
Draft Recommendations
Public Information Process
Draft IRP Contents
Key Points:
•No new (firm) resources needed until ~2020
•Load growth has slowed relative to historical trends:
•Key forecast variables –population, employment & weather
•Common DSM Programs included –need to integrate all programs
•Unknowns –economic factors, annexations, large loads, etc.
•Existing resources:
•High reliability, low emissions & competitive costs
•Changes to reserve capacity –more flexibility
•Some risks remain –most significant is loss of Rawhide coal unit
LOADS & RESOURCES
Municipal Peak & Energy Forecasts
400
500
600
700
800
900
20012002200320042005200620072008200920102011201220132014201520162017201820192020Peak –MWActual Base Forecast Low Forecast High Forecast
Base Peak Forecast:
2.3% annual growth
(2011 to 2020)
2,000
2,500
3,000
3,500
4,000
4,500
20012002200320042005200620072008200920102011201220132014201520162017201820192020Energy –GWhBase Energy Forecast:
1.9% annual growth
(2011 to 2020)
0
100
200
300
400
500
600
700
800
900
2012 2013 2014 2015 2016 2017 2018 2019 2020
Hydropower (LAP + CRSP)
Craig Coal Units 1&2
Rawhide Coal Unit
Rawhide Peaking
(Five separate units)
Loads & Resource Balance
Municipal Peak Loads
(with losses)
MW Risks:
•Forced Outages
•Transmission Curtailments
•Gas Supply Constraints
~16% Planning Reserve in 2020
Planning Goal = 15% or greater
0
100
200
300
400
500
600
700
800
900
2012 2013 2014 2015 2016 2017 2018 2019 2020
Hydropower (LAP + CRSP)
Craig Coal Units 1&2
Rawhide Peaking
(Five separate units)
Loads & Resource Balance –Rawhide Out
MW
Outage Assistance
(Shaft Sharing)
Western Replacement Power
Deficit
in 2020
Risks:
•Prior risks on remaining sources
+ WRP availability not guaranteed
+ Limits on Outage Assistance
New Resource Decision
Municipal Loads
(with losses)
Key Points:
•Next new source(s) needed by ~2015
•Board approved Policy provides planning guidance:
•Amount of renewable energy needed
•Sources considered qualified
•Pricing –via separate premium rate (Tariff 7)
•Key factors affecting need for new sources:
•Colorado Renewable Energy Standard (RES) requirements
•Voluntary municipal programs & policies
•Distributed generation –retail vs. wholesale
RENEWABLE ENERGY
Colorado RES vs. Total Needs
Two Policy Requirements:
•Meet Colorado RES –physical plant
•Meet Total –plant and RECs combined
Renewable Supply for Colorado RES
Deficit in
2015 +3 years
ahead
New plant size
Combined
Municipal
Requirements
Wind:~ 12-15 MW (new)
Solar:~ 24-30 MW
Biomass:~ 5-6 MW
Need to consider existing plant life
Total Renewable Supply
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000 Renewables (MWh)Total City Need
All Existing Sources
Total need –exceeds RES need
2015 2016 2017
RES Sources Needed 33,592 35,636 36,004
Other Sources Needed 6,663 11,573 14,173
Total New Sources 40,255 47,209 50,177
Intermittent vs. Firm Resources
7.3%
1.3%0.2%
45.6%
21.6%
0.0%
5.2%7.1%
12.2%15.2%
41.8%
0.0%0.8%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Wind
Output
at Time
of Peak
Key Planning Factor:
Consider peak capacity value
of next renewable resource(s)
Key Points:
•Two types of programs:
•Common Programs –operated by Platte River in all four municipalities
•Municipality Programs –unique to each municipality
•Program performance:
•Very strong customer participation –beyond available funding
•Exceeded energy savings & peak reduction goals of past IRPs
•Municipal programs expanding in the future
•Integration of DSM into load forecasting
DEMAND SIDE MANAGEMENT
Overall DSM Program Summary
RESIDENTIAL PROGRAMS
Platte River Estes Park Fort Collins Longmont Loveland
Lighting with a Twist Lighting with a Twist Efficient Lighting Lighting with a Twist Lighting with a Twist
ENERGY STAR New Homes ENERGY STAR New Homes ENERGY STAR New Homes ENERGY STAR New Homes ENERGY STAR New Homes
Select HVAC Select HVAC Select HVAC Select HVAC Select HVAC
Larimer Youth Conservation Corps Larimer Youth Conservation Corps Larimer Youth Conservation Corps Home Energy Assessments Larimer Youth Conservation Corps
Thermal energy storage
(with time-of-day rate)
Air Conditioning Load Management
& Rebates Energy Audits Partnering with Power
(AC Load Management)
Insulation & air sealing rebates Home Efficiency Audits Matching Grants Energy Audits
Holiday light exchange (LEDs)Home Efficiency Rebates Clothes Washer Rebates Refrigerator/Freezer Recycling
Free energy assessments Home Energy Reports (O-Power)Dish Washer Rebates Home Energy Reports (Opower)
Energy efficiency rebates Clothes Washer Rebates LED Holiday lamp exchange Clothes Washer Rebates
Dish Washer Rebates Appliance meter loans Education program for schools
Air Conditioner Tune Up & Rebate Energy Smart Program Web site information
Refrigerator/Freezer Recycling Neighborhood Sweeps Program
Solar PV Rebate Program
Zero-Interest Home-Improvement
Loans
Community Conservation Education
Water Conservation Rebates &
Education
COMMERCIAL PROGRAMS
Platte River Estes Park Fort Collins Longmont Loveland
LIGHTENUP LIGHTENUP LIGHTENUP LIGHTENUP LIGHTENUP
Electric Efficiency Program Electric Efficiency Program Electric Efficiency Program Electric Efficiency Program Electric Efficiency Program
Building Tune Up Building Tune Up Building Tune Up Building Tune Up Building Tune Up
Select HVAC Select HVAC Select HVAC Select HVAC Select HVAC
Efficiency express Efficiency express Efficiency express Efficiency express Efficiency express
Questline Keep Current PowerSource Questline
Thermal energy storage ElectriConnect Energy Smart Program ALPS
A/C Tuneup Energy Assessments
Integrated Design
Solar PV Rebate Program
Common
Programs
(eight)
Over 40
Municipality
Programs
Overall DSM Summary
•About 50 total programs –residential, commercial & industrial
•Results to date (preliminary estimates):
•~ 80,000 MWh/yr energy savings –2.6% reduction
•~ 30 MW peak reduction –about 5% reduction (2 years of peak growth)
•~ 76,000 metric tons of CO2 reduction potential –about 2.2% of total
•~ 1% retail rate impact for Common Programs –wholesale funding portion
•Rate impacts for Municipal Programs vary by municipality
•Other benefits:
•Reduced criteria pollutants
•Enhanced services to the municipalities’ customers
•Provision of options to help customers mitigate electric rate increases
•Better comfort and lighting quality in buildings
•Improved equipment quality and reliability
•Local economic benefits associated with energy efficiency business activity
•Public relations / enhanced corporate image of utilities
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
Actual (PR)
Past IRP Goals
Common Program Funding
Customer interest
City Funds
2007 Plan
2002 Plan
2012 Plan Platte River
Funding
DSM Budgets –2011
Platte River
(Common)
Municipalities
(Common)
Municipalities
(Other)
Total of all DSM Budgets ~ $6.8 million
27%
56%
17%
DRAFT RECOMMENDATIONS
Draft IRP Recommendations
•Continue Demand Side Management Programs:
•Common Program funding (PR) steady at $2 million annually (~1% rate impact)
•Expand program evaluation –independent review
•Integrate combined DSM savings into load forecast –Common + Municipality Programs
•Maintain ongoing Joint DSM planning team –Municipality & Platte River staff
•Implement the Renewable Energy Supply Policy:
•Potential need for new sources in 2015
•Confirm Municipality needs and obtain commitments
•Request for Proposals in late 2012 –seek firm capacity if possible
•Minor updates to the 2007 Policy and Tariff
•Update planning criteria for adding new (firm) system resources:
•Eliminate reliance on real-time purchases –currently up to 65 MW
•Seek bids for pre-arranged market purchase options
•No new resources needed until about 2020
•Multiple uncertainties
Draft IRP Recommendations
•Monitor / Study Regional Developments:
•Participation in joint generation projects
•Transmission issues and options
•Load following and regulation services
•Enhanced surplus sales –capacity and energy
•Continue Contingency Planning:
•Load forecast changes
•Distributed generation technologies
•New environmental regulations
•Fuel supply
•Market changes
IRP Development Timeline
Sep 2010
Initial
Review
Dec 2010
DSM
Program
Overview
New
Resource
Addition
Criteria
Mar 2011
Draft
IRP
Review
May 2011
Final IRP
Approval &
Submittal
•Update initial draft
•Staff coordination
•Draft IRP posting
•Other distribution
•Presentations
•Public Hearing
Oct 2010
Updated
Forecast
(2011+)
April 2011
Public
Process
Public
Process
Draft
Plan
Feb 2011
Renewable
Energy
√
√
√
√
√
√
QUESTIONS?
DISCUSSION?
Integrated
Resource
Plan
2012
DRAFT
V.2
4/1/2011
DRAFT
Platte River Power Authority
2012 Integrated Resource Plan
April 1, 2011
Table of Contents
I. Executive Summary .......................................................................................................... 1
II. Recent Trends in Electrical Load Growth...................................................................... 3
III. System Load Forecast ....................................................................................................... 6
IV. Current Resources .......................................................................................................... 10
V. Load/Resource Balance and Resource Needs ............................................................... 13
VI. Renewable Energy .......................................................................................................... 18
VII. Demand Side Management ............................................................................................ 23
VIII. Environmental Management ......................................................................................... 36
IX. Recommended Actions ................................................................................................... 40
X. Public Participation ........................................................................................................ 42
1 DRAFT 4/1/2011
I. Executive Summary
Platte River Power Authority (Platte River), in coordination with its owner municipalities (Estes
Park, Fort Collins, Longmont and Loveland), has prepared this draft Integrated Resource Plan
(IRP). The IRP is focused primarily on the five-year planning period from 2012 to 2016, though
it also includes consideration of longer term planning issues.
An IRP typically provides information associated with resource acquisitions to meet customers’
future electrical energy needs, including capacity and energy supply resources, renewable
energy and demand side management. It is important to note that based on the current load
forecast, reserve requirements and other factors, no new generation resources are required to
meet the municipalities’ electricity needs during the term of this IRP (through 2016). The next
firm resource may not be needed until about 2020. The intent of this document is to provide
updated information on predicted electric loads, existing capacity resources, renewable energy
planning and demand side management programs. It also provides guidelines for addition of
new capacity resources over the longer term.
Resource planning is a continuous and dynamic process, and this IRP represents a view of
conditions as they stand at a narrow window in time. Many of the issues and assumptions
presented here will change as customers’ needs and other factors evolve over time.
The electricity requirements of the municipalities continue to grow, though at a slower rate than
historical levels due to recent economic conditions, slower population growth and energy
efficiency efforts. While the municipalities’ populations grew at an average rate of 2.75%
between 1991 and 2009, growth of about 1.8% is anticipated between 2011 and 2030. Growth in
local business is also anticipated to be slower than historical levels. The combined municipal
growth in electrical energy requirements over the next five years is estimated to be
approximately 1.9% annually, with peak demand growth at about 2.5%. The most recent 10-
year system load forecast is included as part of this IRP.
Platte River’s existing resource portfolio includes a mix of hydropower (via federal contracts),
coal-fired generation (located at Rawhide and Craig stations), and natural gas turbines (five
units at the Rawhide site). Platte River also receives energy from wind turbines located at the
Medicine Bow and Silver Sage sites in Southeast Wyoming. In the unlikely event that the
Rawhide coal unit goes down unexpectedly at time of peak, Platte River has additional options
for obtaining temporary capacity on a short-term basis. A detailed loads and resource balance
projection is provided in this IRP.
Several uncertainties could change the load/resource balance within the next few years. These
include the potential for expanded use of distributed generation and ―smart grid‖ technologies,
new business facilities locating within the municipalities, uncertainty in weather trends,
expansion of end-use technologies (air conditioning, computers, home entertainment,
communications, electric vehicles, etc.), potential annexations by the municipalities, unexpected
changes in population and expansion of energy efficiency technologies and programs.
Since the late 1970s, the owner municipalities and Platte River have undertaken numerous
projects to provide efficient generation, transmission, and distribution—and have offered a
variety of programs to encourage efficient use of energy. Since 2002, a set of Common
Programs has been offered by Platte River in all the municipalities. Each municipality also
2 DRAFT 4/1/2011
operates unique programs in their individual communities. Details of existing programs, as
well as anticipated future programs are provided in this IRP.
A Board approved Renewable Energy Supply Policy is used to guide planning and acquisition
of new renewable sources to meet the needs of the municipalities. The policy provides direction
regarding the level of renewable sources to be obtained, the type of sources considered
acceptable, the anticipated effect of renewable sources on future resource planning, and the
approach to be used for pricing renewable sources for sale to the owner municipalities. By
2020, it is anticipated that approximately 220,000 MWh/yr of renewable energy will be needed
from sources other than federal hydropower. This represents about 6.5% of total predicted
energy supply to the municipalities in 2020. The combined renewable portion of supply
including hydropower is expected to be about 16% by 2020.
Platte River and the municipalities plan to implement the following items as a result of this IRP:
1. Continue operating demand side management programs. Platte River funding for Common
Programs (those offered in all municipalities) will remain at current levels while funding
from the municipalities is anticipated to increase relative to historical levels. Verifiable peak
demand and energy savings will be integrated into the overall system load forecast by 2013.
2. Continue implementation of the Renewable Energy Supply Policy, anticipating the need for
new renewable energy resources in approximately 2015. The process for seeking new
renewable supply options is expected to begin in 2012. About 40,000 MWh/yr of new
supply is anticipated—roughly 30% more than historical deliveries from existing sources.
3. Update system resource planning criteria to remove the risk of relying on real-time market
purchases to meet load obligations whenever the Rawhide coal unit is out of service. Rather
than relying on up to 65 MW in real-time market purchases, only pre-arranged purchase
options will be considered for firm capacity needs.
4. Monitor developments of new regional generation and transmission resources to ensure a
position in new options that may be of benefit to Platte River and the municipalities over the
long term.
5. Monitor other developments in municipal loads, technology development, wholesale
electricity markets and regulation/legislation—in order to support contingency planning.
Integrated Resource Plans completed in 1997, 2002 and 2007 have included several public
communications activities, including customer and community surveys, public hearings,
customer meetings, media releases, meetings with community groups and public meetings of
the Platte River Board of Directors. Through these efforts, an effective exchange of information
on the issues of electric load growth and resource planning has occurred among the municipal
utilities, local boards and councils, customers, and citizens of the owner municipalities. Similar
public information efforts will be conducted as part of the development of a final 2012 IRP. This
draft document will be shared with the public through multiple modes and presentations will
be provided to local groups in each municipality.
It is anticipated that a final 2012 IRP will be approved by resolution of the Platte River Board of
Directors in May 2011. It will also be submitted to the Western Area Power Administration
(WAPA), in accordance with the directives of the Energy Policy Act. Updates will be provided
to WAPA on an annual basis.
3 DRAFT 4/1/2011
II. Recent Trends in Electrical Load Growth
The municipalities served by Platte River have seen slower growth in business activity,
population, and demand for electricity over the past few years—relative to the prior ten years.
Figure 1 shows the overall trends in energy and peak demand on the Platte River system since
2001 and Figure 2 breaks out the energy usage, peak demand and ten-year population growth
rates by municipality.
Figure 1
Figure 2
Cities
2000 Energy
Requirements
(MWh)
2010 Energy
Requirements
(MWh)
2000-2010
Energy
Growth
2000-2010
Annual
Demand
Growth
10 Year
Population
Growth*
Estes Park 116,523 129,840 11% 12% 21%
Fort Collins 1,253,917 1,472,941 17% 27% 18%
Longmont 694,019 806,534 16% 30% 21%
Loveland 522,889 702,481 34% 50% 31%
Aggregate 2,587,348 3,111,796 20% 32% 22%
* Source: State Demography Office. Ten Year growth based on 2009 data (2010 data not yet available).
Figure 3 presents the historical and projected growth for annual energy, billable peaks, and annual
peak demand. Billable peaks represent the sum of all monthly peak demands for the year. Since
0%
5%
10%
15%
20%
25%
30%
35%
40%
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Historical Growth Trends
Population Growth Demand Growth Energy Growth
• 22% population increase
• 32% peak demand increase
• 20% energy increase
4 DRAFT 4/1/2011
1997, Platte River’s annual maximum system peak has occurred during the summer season. In the
period 2001 to 2005, municipal loads grew at a fairly steady rate. The second half of the decade
was more volatile. In 2010, the annual peak demand was 0.1% below the 2005 peak. Since the
system peak of 618 MW in 2005, annual peak demand has been as high as 635 MW in 2007, and as
low as 576 MW in 2009. Annual energy and billable peak growth rates were more consistent than
annual peak demand, but both grew less than 1% annually between 2005 and 2010.
Figure 3
In the 2002 IRP, the annual peak load for 2011 was projected to be 705 MW and in the 2007 IRP,
the 2011 peak was projected as 714 MW. Load growth slowed significantly since the financial
crisis occurred in 2008 and the peak load for 2011 is now anticipated to be about 632 MW.
Figure 4 shows the annual load duration curves from 2000 and 2010. These curves present the
municipal loads from highest to lowest within a given year. Over this period, the peak load
demands during relatively few hours on summer peak days have grown 32%, while demands
during the rest of the year have grown at a slower rate of 22%.
Figure 5 illustrates the annual peak-day load profile for 2000, 2005, and 2010. Between 2000 and
2005, annual peak loads grew 154 MW and total peak-day energy consumption increased 2,554
MWh. The peak growth slowed significantly over the next five-year period with a 12 MW
increase in 2010 compared to 2005 and a 110 MWh decrease in peak-day energy consumption.
Year Energy
(GWh)
Annual
Change
Five-Yr Avg.
Change
Billable
Peaks (MW)
Annual
Change
Five-Yr Avg.
Change
Peak
(MW)
Annual
Change
Five-Yr Avg.
Change
2001 2,670 3.2%4.6%4,994 4.4%4.8%496 7.7%7.4%
2002 2,781 4.2%4.7%5,294 6.0%5.5%533 7.4%7.5%
2003 2,846 2.3%4.4%5,415 2.3%4.8%560 5.1%6.4%
2004 2,875 1.0%3.6%5,456 0.7%4.5%576 2.9%6.0%
2005 2,986 3.9%2.9%5,712 4.7%3.6%618 7.2%6.1%
2006 3,052 2.2%2.7%5,762 0.9%2.9%591 -4.3%3.6%
2007 3,147 3.1%2.5%5,946 3.2%2.4%635 7.4%3.6%
2008 3,157 0.3%2.1%5,909 -0.6%1.8%614 -3.3%1.9%
2009 3,056 -3.2%1.2%5,763 -2.5%1.1%576 -6.1%0.0%
2010 3,115 1.9%0.9%5,871 1.9%0.6%615 6.8%-0.1%
2011 3,171 1.8%0.8%5,984 1.9%0.8%632 2.9%1.4%
2012 3,234 2.0%0.5%6,110 2.1%0.5%648 2.5%0.4%
2013 3,297 1.9%0.9%6,236 2.1%1.1%664 2.4%1.6%
2014 3,359 1.9%1.9%6,360 2.0%2.0%680 2.4%3.4%
2015 3,422 1.9%1.9%6,484 2.0%2.0%695 2.3%2.5%
2016 3,484 1.8%1.9%6,608 1.9%2.0%711 2.2%2.4%
2017 3,546 1.8%1.9%6,730 1.9%2.0%726 2.2%2.3%
2018 3,607 1.7%1.8%6,852 1.8%1.9%741 2.1%2.2%
2019 3,668 1.7%1.8%6,973 1.8%1.9%756 2.0%2.2%
2020 3,745 2.1%1.8%7,122 2.1%1.9%775 2.4%2.2%
*For 2010, January - August actuals reported, September - December reflect 2010 Offical Budget figures
PEAK DEMANDBILLABLE PEAKSANNUAL ENERGY
5 DRAFT 4/1/2011
Figure 4
Figure 5
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100
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300
400
500
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700
1 877 1753 2629 3505 4381 5257 6133 7009 7885City Load -MWHours
Annual Loads
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2010
32% Increase
22% Increase
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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24Demand -MWHour
Annual Peak Day Load Profile
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6 DRAFT 4/1/2011
III. System Load Forecast
1. Methodology
Platte River uses an econometric model to develop long-term demand and energy forecasts.
Econometric modeling uses forecasts of multiple independent variables to project the growth of
a dependent variable. The econometric model uses independent variable projections including
population, weather, and employment, to project demand and energy growth in the
municipalities. Demand and energy are forecasted separately.
Woods & Poole (W&P), an independent economic forecasting firm, provided population and
employment forecasts. W&P’s employment and population forecasts for Larimer and Boulder
counties continue to show declines relative to historical growth rates. While the owner
municipalities’ populations grew at an annual average rate of 2.75% between 1991 and 2009,
W&P projects average annual population growth of 1.8% between 2011 and 2030. Past
population data for the four municipalities, provided by the Colorado Economic and
Demographic Information System, is used for the historical population base.
To forecast the independent weather variables used in peak demand projections, average
weather conditions between 1991 and 2010 were applied. While this long-term average should
reflect ―normal‖ weather conditions, weather variables in any given year may be higher or
lower than the historical average. Weather data incorporated by the model is from Day
Weather, Inc., which provides daily meteorological data specific to the City of Fort Collins.
Weather statistics used to forecast demand include Cooling Degree Days on Peak Day (CDD)
for summer cooling season peaks, and Heating Degree Days on Peak Day (HDD) in winter
season heating months. CDD and HDD were selected as the independent weather variables
based on past recommendations by Utility Financial Solutions, a consulting firm that assisted
with the development of past Official Load Forecasts.
In 2010, Platte River continued to experience deviation from forecasted loads. The deviation
may be attributed to multiple factors: weather variations from historical trends, demand side
management programs in the municipalities and continued impacts of the recent financial crisis
among other factors. Although economic variables are used in the econometric model, they are
lagging indicators. Due to this lagging effect and the fact that the recent economic downturn
was so severe, the forecasting methodology for 2011 has been modified. To forecast 2011, the
econometric model long-term growth projections were applied to 2009 and 2010 actual loads.
In 2012 and beyond, the growth rates from the econometric model projections were used to
determine the forecast.
As demand side management (DSM) programs continue to evolve and grow, their impacts
upon the municipalities’ loads have also grown. Common Programs, those operated by Platte
River in all the municipalities, are focused on energy efficiency and do not include Direct
Control Load Management as defined by North American Electric Reliability Corporation
(NERC). To account for the resulting impacts of DSM programs on forecasts, the Official
Forecast incorporates DSM savings. DSM savings are included for Common Programs that are
measured and verified by Platte River. In the future, verifiable savings from DSM programs
operated by the municipalities will also be included.
7 DRAFT 4/1/2011
2. Ten-Year Municipal Load Forecast
The following are highlights of the 2011 Ten-Year Load Forecast:
Average annual energy growth rate is estimated as 1.9% for the 2011 to 2020 period.
The ten-year billable peaks growth is approximately 125 MW per year, with an average
annual growth rate of 1.9% between 2011 and 2020.
The ten-year annual peak demand growth is approximately 16 MW per year, with an
average annual growth rate of 2.3% between 2011 and 2020.
Figure 3 above details the most recent ten-year projected annual peak demand forecast for the
aggregate of the municipalities’ loads. The data is taken from the 2011 Official Load Forecast.
As indicated in the figure, the five-year average growth rate for annual peak demand is
projected to increase from 0.9% in 2010 to 1.9% in 2015.
Figures 6 and 7 below depict historical and forecasted demand and energy for 2001 through
2020, along with the high and low forecast intervals. The low population forecast assumes a
1.1% annual population growth rate from 2011 to 2020. The high population forecast assumes a
2.75% annual population growth rate over the same period.
Figure 6
Figure 7 depicts historical and projected annual energy from 2001 through 2020, along with the
high and low forecast intervals. Like the annual peak demand forecast, the low and high
forecasts assume 1.1% and 2.75% population growth rates respectively.
400
450
500
550
600
650
700
750
800
850
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20012002200320042005200620072008200920102011201220132014201520162017201820192020MWAnnual Peak Demand -Historical & Forecasted
Actual Base Forecast Low Forecast High Forecast
8 DRAFT 4/1/2011
Figure 7
3. Factors Affecting Load Growth
A number of factors introduce uncertainty into load projections for the Platte River system.
Several of these are discussed here.
A. Annexations and Urban Growth Boundaries
Each of the municipalities has its own policies that guide decision-making processes for
annexation and changes to urban growth boundaries. Urban growth boundaries define the
limits for a municipality’s future footprint of homes and businesses upon the landscape, which
impacts electricity consumption. New construction outside the urban growth areas will
typically fall under the county’s jurisdiction, not that of the municipality. In the future, new
developments outside of urban growth boundaries could be proposed, accompanied by
requests for annexation into the adjacent municipality. Depending upon the size and number of
such projects, growth outside the urban growth boundaries of the municipalities may have
significant impact on the municipalities' future load growth. Annexations of existing loads may
also occur and these could increase loads beyond the forecasted level. Platte River and the
municipalities will monitor this issue.
B. New Energy Intensive Loads
Advances in computing technology and the need for secure data have led to expansion of web
and data server installations, which are typically high energy users. These large installations
can increase peak loads by over 50 MW within a few years. Given the owner municipalities’
historically low and stable electric rates (and other attractive characteristics), entities with large
loads (5 MW to 50 MW) have considered locating within the members’ service areas in the past.
The assumptions supporting the current load forecast do not include new large energy
intensive loads. Platte River and the cities continue to monitor this issue.
2,000
2,500
3,000
3,500
4,000
4,500
20012002200320042005200620072008200920102011201220132014201520162017201820192020GWhAnnual Energy -Historical & Forecasted
Actual Base Forecast Low Forecast High Forecast
9 DRAFT 4/1/2011
C. Local and National Economic Conditions
The population forecast used to develop our electric energy forecasts predicts a significant
decline in population growth rates relative to historical rates. Between 1991 and 2004,
population growth averaged 3.0% for the region. For forecasting future energy and demand
requirements, Platte River used the Woods & Poole forecast, which averages 1.7% annual
population growth. The actual rate of population growth and strength of economic conditions
in the region will impact future demand and energy growth rates.
D. Restructuring/Market Trends
Events over the last several years in California and other regions have significantly diminished
the momentum behind electric industry restructuring (particularly at the retail level). The
current regulatory and legislative environment leaves the timing of restructuring in Colorado
uncertain, but it is unlikely that retail competition will be implemented for the next several
years. Changes in municipal loads that may occur due to industry restructuring are not
included in the current forecast.
E. Distributed Technology Advancements
Technologies such as fuel cells, micro-turbines, photovoltaic solar and demand response have
garnered a great deal of interest in recent years. These technologies appeal to some retail
customers since they can be installed near the point of energy use (i.e., distributed) and can
generate energy more efficiently from fossil fuels. They can also provide generation from
renewable sources (solar, biofuel, etc.). To date, the relatively high cost of these sources has
limited their widespread installation, but technology advancements and various types of
incentives have brought prices down to levels that are acceptable to some customers,
particularly those willing to pay a premium for renewable energy.
As the cost of distributed technologies continues to drop in future years, some of the load in the
municipalities may be affected. The extent of the impact depends on the rate of acceptance of
these technologies and on the degree to which the municipalities and Platte River participate in
their implementation. Participation in distributed technologies will depend on a variety of
factors, including the cost of distributed renewables compared to central generation (renewable
or otherwise), available incentives, and customer interest. Platte River and the municipalities
will continue to closely monitor ongoing developments in distributed technologies to
understand the benefits, costs, and risks of implementing these technologies as they mature.
F. Electric Vehicles
Though the short-term impact of electric vehicles on municipal loads is likely to be small, there
could be significant impacts over the long-term. Developments in electric transportation
technologies and market acceptance of these alternatives will be monitored over time.
A copy of the most recent load forecast report is available upon request.
10 DRAFT 4/1/2011
IV. Current Resources
To fulfill its mission, Platte River has developed and contracted for a diversified mix of reliable,
cost-effective, and environmentally responsible resources. An overview of each of Platte River's
current resources is provided below.
1. Rawhide Energy Station
The Rawhide Energy Station consists of Rawhide Unit 101, a 280 MW (net capacity) coal-fired
generating facility, with cooling reservoir, coal-handling facilities, emissions control equipment,
and related transmission facilities. Rawhide Unit 101 commenced commercial operation on
March 31, 1984. The station is located approximately 20 miles north of Fort Collins and is
connected to Platte River’s system by two double circuit 230 kV transmission lines. The site also
includes five gas-fired combustion turbines, Rawhide Units A, B, C, D and F (these units are
discussed in further detail below).
At inception in 1984, Rawhide Unit 101 was equipped with the best available emissions control
technology, and several emissions control upgrades have occurred over time. Further NOx
reductions are also anticipated within the next five years. Rawhide Unit 101 is one of the lowest
emitting coal plants in the U.S., as shown in Figures 11 and 12.
2. Yampa Project (Craig Units 1 and 2)
The Yampa Project consists of Craig Units 1 and 2, both of which are coal-fired—each rated at
428 MW (net capacity). Platte River owns an 18% share of Units 1 and 2, or 77 MW per unit, for
a total of 154 MW. The Yampa Project is located in northwestern Colorado, approximately four
miles southwest of Craig. The site includes the generation facilities, a coal handling facility, a
small water storage reservoir, and related transmission facilities. A $120 million Yampa
Environmental Project was completed in 2004, which reduced SO2, NOx, and particulate
emissions from the plant. Craig Units 1 and 2 have relatively low emissions relative to other
coal-fired plants throughout the U.S., as indicated in Figures 11 and 12. Further NOx
reductions are also anticipated at the Craig Units within the next five years.
Platte River also owns approximately 190 MW of transmission capacity in the path from
western to eastern Colorado, which is used to deliver Platte River’s share of the Yampa Project
output. The excess transmission capacity above what is needed by Platte River is leased on a
long-term basis to other regional utilities.
11 DRAFT 4/1/2011
Figure 11
Figure 12
0.0
1.0
2.0
3.0
4.0
5.0
6.0
Pounds per Million Btu2009 SO2 Emission Rates
All Reporting U.S. Coal-Fired Plants
RawhideYampa
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
Pounds per Million Btu2009 NOx Emission Rates
All Reporting U.S. Coal-Fired Plants
Rawhide
Yampa
Source: U.S. Environmental Protection Agency
12 DRAFT 4/1/2011
3. Western Area Power Administration Supply Contracts
Platte River receives allocations of federal hydropower under contracts from the Western Area
Power Administration’s (WAPA) Loveland Area Project (LAP) and the Colorado River Storage
Project (CRSP). These allocations vary by season.
The LAP contract was extended in March 1996 to run through September 2024. Platte River
receives monthly quantities of approximately 30 MW to 34 MW of LAP capacity throughout the
year.
Platte River’s guaranteed capacity from CRSP was reduced on March 1, 1997, as part of
Amendment No. 4 to the CRSP agreement. This reduced capacity is referred to as Sustainable
Hydropower (SHP). For long-range resource planning, Platte River uses the SHP quantity as
the capacity expected to be available from CRSP. Platte River expects to receive approximately
55 MW to 62 MW of CRSP capacity during the summer season and 75 MW to 85 MW of CRSP
capacity during the winter season.
The final element of the CRSP supply is based upon the capacity difference between contract-
rate-of-delivery and Sustainable Hydropower quantities. This difference is referred to as
Western Replacement Power (WRP) and represents capacity (and associated energy) that Platte
River may be able to schedule from WAPA, depending on availability.
4. Peaking Units
Platte River operates five natural gas fired combustion turbines (Rawhide Units A, B, C, D and
F). These units provide peaking capacity as well as backup reserve capacity in the event of an
outage at one of Platte River’s other resources. Three of these units were commercially
available for generation in 2002, the fourth was brought on line in the spring of 2004, and the
last unit came on line in 2008. The combined capacity of the units provides approximately 388
MW.
A 15-mile natural gas pipeline was constructed to supply fuel to the units. The pipeline has
capacity to supply additional gas-fired resources and/or to operate the existing units in
combined cycle mode. Any consideration of new gas resources or operational changes for
existing gas resources would require a detailed study of natural gas supply to the Rawhide site.
5. Forced Outage Assistance Agreement
An agreement has been executed with Tri-State Generation and Transmission Association,
whereby 100 MW of capacity is provided to Platte River in the event of an outage at Rawhide
Unit 101. In exchange for this capacity provision, Platte River provides 100 MW of capacity to
Tri-State in the event of an outage at Craig Unit 3.
6. Wind Generation
Platte River also has about 20 MW of wind generation from two sources in Wyoming. These are
described in the Renewable Energy section below.
13 DRAFT 4/1/2011
V. Load/Resource Balance and Resource Needs
In this section, we summarize the predicted balance between Platte River system loads and
existing resources—and discuss the potential need for new resources in the future. The decision
to add a new resource is based on ensuring an adequate balance between loads and resources at
all times—particularly under the scenario that the largest resource (Rawhide Unit 101) goes off
line unexpectedly at time of summer system peak.
1. Resource Addition Criteria
In the last Integrated Resource Plan (2007), the following criteria were used for determining the
timing of new firm generation resources:
Ensure that loads do not exceed firm resources by more than 65 MW in the event of an
unplanned outage of Rawhide Unit 101 (coal unit)
Maintain a minimum planning reserve margin of 15%
Ensure loss of load probability (LOLP) of less than 5% at the peak hour
Ensure loss of load expectation (LOLE) of less than 1 day in 10 years
The first criterion assumes that firm capacity can be purchased from the wholesale market on
short-term (real time) notice—at any time during the year. The most critical period for such
purchase would be at the time of summer system peak with the Rawhide coal unit out of
service. This was a reasonable assumption in the past, but experience during the last few
summer seasons has shown decreased availability of wholesale power on a real-time basis
during peak periods.
The second criteria of maintaining a planning reserve margin of 15% with all generation units
operating represents typical practice for electric utilities in the region. In the future, standards
may be set by Western Electricity Coordinating Council (WECC), North American Electric
Reliability Corporation (NERC) or Federal Energy Regulatory Commission (FERC), which
could require higher levels of planning reserve. Platte River will continue to monitor such
developments over time, but for now, a 15% planning reserve will be used.
The LOLP and LOLE criteria are more appropriate to support statistical analysis for entities
with a large number of generation resources. These criteria may continue to be used in the
future to help guide planning, but have limited applicability for Platte River’s relatively small
system and associated resources.
Beginning in 2012, it is recommended that the following criteria be used for future resource
planning:
Carry reserves or have access to firm capacity that is sufficient to meet load obligations
whenever the Rawhide coal unit is out of service
Maintain a minimum planning reserve margin of 15%
14 DRAFT 4/1/2011
These new criteria mitigate the risk that resources are insufficient to meet loads if capacity is
unavailable for purchase at time of system peak. The past criteria allowed up to 65 MW of
market purchase risk on a real time basis; the new criteria remove this risk and enhance
reliability of service to the municipalities.
Platte River will continue to consider market purchases as a resource supply option, but on a
longer-term, more firm basis. Platte River will collect competitive bids for capacity that could
be used to meet loads in the event that Rawhide is out of service. Bids would be for capacity to
be delivered approximately five years into the future and these bids would be collected each
year going forward. The intent of this ongoing effort is to monitor availability and price for
firm capacity that could be delivered to the Platte River system. The level of capacity requested
will be up to approximately 65 MW, which is equal to the summer output of the smallest
peaking units at the Rawhide site. Data regarding availability and price of purchased capacity
will be used along with other information to compare possible market purchases with other
supply options such as building new generation resources.
2. Projected Balance of Peak Loads and Firm Resources
This section describes the projected balance of peak loads and firm resources under various
scenarios of resource availability.
Currently available firm resources include Rawhide Unit 101 (coal), Platte River’s share of Craig
Units 1 and 2 (coal), the Rawhide peaking units A, B, C, D and F (natural gas-fired) and the
CRSP and LAP hydroelectric contracts with Western Area Power Administration (WAPA). An
additional purchase option may also be available from WAPA—called WAPA Replacement
Power (WRP) and, in the event that Rawhide is out of service, capacity may be available
through an outage assistance agreement with Tri-State Generation & Transmission Association,
co-owner and operator of the Craig station. Platte River’s wind generation, discussed in later
sections, is not a firm resource. Each of the firm resources has some risk of availability, as
outlined below:
Rawhide coal unit – Historical operations indicate a forced outage rate for this unit at
approximately 2%. Unexpected outages have typically been caused by failure in plant
equipment (tube leaks and other malfunctions). Curtailments in output have also been
caused by transmission limitations, though these have been rare.
Craig coal units – Similar to the Rawhide coal unit, unforeseen outages may occur due to
failure of critical plant equipment. The historical average forced outage rate for the two
Craig units is approximately 5%. Transmission curtailments could also reduce or eliminate
capacity from the Craig units (a rare situation historically).
Rawhide gas peaking units – Unexpected outages may also occur for these units due to
equipment failure. These units are only operated at peak times or when another resource is
unavailable, so the forced outage rate is not a consistent unit of comparison. Historically,
the average availability has been over 93%. As with the Rawhide coal unit, capacity
reductions may also be required due to transmission limitations. Availability of fuel
(natural gas) is also a risk that must continue to be managed for these units.
15 DRAFT 4/1/2011
CRSP and LAP hydropower purchases – These deliveries are made on a monthly basis,
according to contracts with WAPA. Deliveries have been very reliable in the past, though
transmission constraints could impact available capacity on rare occasions.
WRP hydropower purchases – Replacement power purchases may be made from WAPA,
but only if excess capacity is available on the WAPA system at the time of the request.
WAPA requires that such purchases be scheduled in advance. Once requested, WAPA uses
their transmission system to deliver market purchases to Platte River. WAPA’s
transmission system can reach some markets that are not within the direct reach of Platte
River’s transmission. The prices of such purchases are not known in advance, so though
reliability can be enhanced, there is some price risk associated with this option.
Forced Outage Assistance Agreement with Tri-State – The agreement only applies for a time
period of up to one week per occurrence, so any unplanned outage beyond one week would
require additional capacity. Also, this agreement may be terminated with two-year notice.
Platte River plans to evaluate options for ensuring the agreement remains in place for
several years into the future.
Figure 13 shows the summer peak-month loads and resources balance in table form for years
2012 through 2021, assuming all firm resources are available. Electric supply resources include
those described above. Obligations include the aggregated municipality loads, transmission
system losses and reserves (required to meet unanticipated demand or to counteract the
sudden, unforeseen loss of a major resource). Base municipal loads also reflect the effects of
Common DSM programs.
Figure 13
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Loads
Foundation Forecast 654 672 691 709 728 747 766 785 804 823
DSM (1)(5) (8) (11) (14) (17) (21) (25) (28) (29) (30)
Municipal Loads (Base)648 664 680 695 711 726 741 756 775 793
Required Reserves (2)3 - - - - - - - - -
Losses 12 12 12 13 13 13 14 14 14 15
Total Loads 663 676 692 708 724 739 755 771 789 808
Resources
Rawhide 278 278 278 278 278 278 278 278 278 278
Craig 156 158 158 158 158 158 158 158 158 158
CRSP 60 60 60 60 60 60 60 60 60 60
LAP 30 30 30 30 30 30 30 30 30 30
Peaking 388 388 388 388 388 388 388 388 388 388
Total Resources 912 914 914 914 914 914 914 914 914 914
Surplus (Deficit)249 238 222 206 190 175 159 143 125 106
Reserve Margin (2)38.2%35.2%32.1%29.1%26.3%23.6%21.0%18.6%15.8%13.1%
(1) DSM based on programs measured and verified by Platte River.
(2) Assumes Platte River is no longer a member of the Rocky Mountain Reserve Group beyond 2012.
(3) Reserve margin calculation excludes firm surplus sales and required reserves.
PEAK MONTH FORECAST - (MW)
16 DRAFT 4/1/2011
As indicated in Figure 13, the reserve margin remains above the 15% reliability criteria limit
through 2020 during the annual peak—projected to occur in July.
Due to the size of the Rawhide coal resource relative to loads, the loss of this unit could
seriously impact the reliability of the Platte River system, depending on the timing and duration
of an outage. The recommended resource planning criteria requires that Platte River carry
reserves or maintain access to firm resource capacity that is sufficient to meet load obligations
even if this largest generating unit is out of service. Deficits may be met through operation of
the Rawhide combustion turbine units (A through F), pre-arranged market purchases, WRP
market purchases, and the Forced Outage Assistance Agreement with Tri-State.
Assuming full utilization of the Forced Outage Assistance Agreement (100 MW) and WAPA
Replacement Power purchases (46 MW) during an outage of Rawhide Unit 101—and assuming
all other resources are available—the deficits remaining are shown for the ten-year forecasting
horizon as the last line in Figure 14. As indicated in Figure 14, resources are sufficient to meet
summer obligations until 2020. No deficits are anticipated during the winter season well
beyond 2020.
Figure 14
DSM projections included in Figures 13 and 14 are for Common Programs, which do not
include Direct Control Load Management as defined by NERC.
The level of reserve capacity that Platte River is required to hold on its own resources has been
reduced since the last IRP (2007). In the future, it is anticipated that reserves will be purchased
from Public Service Company of Colorado, under the appropriate tariff for reserve service. This
allows Platte River resources to be used for serving municipal loads and for providing
additional surplus sales to other wholesale entities.
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Loads
Foundation Forecast 654 672 691 709 728 747 766 785 804 823
DSM (1)(5) (8) (11) (14) (17) (21) (25) (28) (29) (30)
Municipal Loads (Base)648 664 680 695 711 726 741 756 775 793
Required Reserves 3 - - - - - - - - -
Losses 12 12 12 13 13 13 14 14 14 15
Total Loads 663 676 692 708 724 739 755 771 789 808
Resources
Rawhide - - - - - - - - - -
Shaft Sharing 100 100 100 100 100 100 100 100 100 100
Craig 156 158 158 158 158 158 158 158 158 158
CRSP 60 60 60 60 60 60 60 60 60 60
LAP 30 30 30 30 30 30 30 30 30 30
Peaking 388 388 388 388 388 388 388 388 388 388
WRP 46 46 46 46 46 46 46 46 46 46
Total Resources 780 782 782 782 782 782 782 782 782 782
Surplus (Deficit)117 106 90 74 58 43 27 11 (7) (26)
(1) DSM based on programs measured and verified by Platte River.
RAWHIDE OUT OF SERVICE - PEAK MONTH FORECAST (MW)
17 DRAFT 4/1/2011
3. Timing and Type of Future Firm Capacity Resources
Both of the recommended resource reliability criteria indicate that a new firm capacity resource
may not be required until about 2020. However, as indicated earlier in this document, several
uncertainties could change the load/resource balance during the term of this IRP. These
include the potential for expanded DSM, expanded use of distributed generation, large new
facilities locating within the municipalities, uncertainty in weather trends, expansion of certain
end-use technologies (air conditioning, computer and entertainment technology, electric
vehicles, etc.), potential annexations by the municipalities and changes in population.
Given the characteristics of municipal loads and anticipated growth, the next resource is likely
to be needed only at time of system peak. However, this assumes future load growth patterns
will be similar to that which has occurred during the last several years. This also assumes that
all existing resources will continue to operate as they do currently. Potential environmental
legislation or regulation or other factors may require changes to generation operations. For
example, if coal generation is reduced to meet greenhouse gas emission requirements, new gas
generation may be required to operate more often than what is appropriate for a peaking unit.
Therefore, both the timing and the type of resource that may be needed in the future are
somewhat uncertain.
The time frame required for permitting and constructing new generation resources is likely to
be longer than occurred for past resource additions. This is primarily because new transmission
will be required for new generation at the Rawhide site. Considering new permitting
requirements, lead times for transmission equipment and coordination of transmission
operations with regional utilities, additional new transmission from Rawhide could take up to
five years to permit and construct. It is anticipated that detailed planning and permitting for
new transmission could begin as early as 2015, assuming a new generation unit is needed at the
Rawhide site by 2020.
Going forward, Platte River will continue to monitor municipal loads and other factors that
affect resource timing and type.
18 DRAFT 4/1/2011
VI. Renewable Energy
1. Renewable Energy Supply Policy
The Platte River Board of Directors has approved a Renewable Energy Supply Policy that
guides planning and acquisition of new renewable sources to meet the needs of the
municipalities. The policy provides guidance on the following planning issues.
Amount of renewable resources needed – This is driven by three factors: (1) Colorado
Revised Statute 40-2-124, which implements a renewable energy standard (RES) for retail
utilities in Colorado, (2) voluntary requests from customers participating in the
municipalities’ premium-priced renewable energy programs, and (3) individual
municipalities’ renewable policies. The amount of wholesale renewable sources acquired by
Platte River may also be affected by the level of renewable sources that are located within
the municipalities’ retail system – as distributed renewable resources could reduce the level
of wholesale supply needed from Platte River.
Types of renewable resources – Renewable energy resources considered qualified include
those identified in the Colorado RES—solar (photovoltaic or thermal electric systems), wind
turbines, geothermal, biomass and small hydroelectric generation systems. Renewable
Energy Certificates (RECs) from any of these sources may also be used—as outlined in the
RES.
Impact on resource planning – As indicated in Figure 15, wind generation has not provided
firm capacity at the time of system peak. Transmission constraints may also limit the
delivery of wind generation. Therefore, existing wind generation resources are assigned no
firm peak capacity value. These resources do not reduce the need for firm resources to meet
system peak demand. Some peak capacity value may be assigned to new renewable
resources, depending on the technology considered.
Pricing – Tariff Schedule 7: Renewable Energy Service (Tariff 7) provides terms and
conditions for renewable energy service to the municipalities and associated pricing. Tariff
7 sets a single premium price for all renewable resources combined based on cost of service
for the pool of renewable sources.
Copies of the Renewable Energy Supply Policy and the current version of Tariff 7 are available
upon request.
2. Existing Renewable Supply
In 1998, Platte River completed the development and commercial startup of two 600 kW
commercial wind turbines at its Medicine Bow Wind Project site (MBWP). Together with the
City of Fort Collins, Platte River was the first utility in Colorado to provide wind energy to its
customers. All the municipalities offered renewable energy to their customers by 1999. Five
more 660 kW turbines were added in 1999, followed by another two units in 2000. In 2005, a
prototype 2.5 MW wind turbine (Clipper Liberty) began operations, making a total of ten
turbines with a capacity of 8.3 MW at Platte River’s Medicine Bow site. In October 2009, Platte
River began receiving energy from 12 MW of new wind generation at the Silver Sage Wind
Project site near Cheyenne, Wyoming. Deliveries from this facility are made under a Purchase
19 DRAFT 4/1/2011
Power Agreement with the developer. The total maximum rating of generation output for
existing turbines is 20.3 MW.
Figure 15 below shows production from the Vestas turbines owned by Platte River at the
Medicine Bow wind site. On average the turbines produced almost exactly the predicted
output during the last 10 years (101% of estimated).
Figure 15
The performance of the Clipper turbine at the Medicine Bow site for the last five years is shown
in Figure 16. The first full year of operation was 2006. Through 2010, the turbine has produced
about 89% of the predicted output.
Figure 16
-
5,000
10,000
15,000
20,000
25,000
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010Production (MWh)-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2006 2007 2008 2009 2010Production (MWh)
20 DRAFT 4/1/2011
In 2010, the Silver Sage wind project completed its first year of operation. A summary of
performance is provided in Figure 17. This project has delivered about 90% of expected energy.
The reduced production is thought to be the result of relatively low wind speed during 2010.
Figure 17
The oldest Vestas turbines have operated since 1998 so are expected to begin to reach their
predicted useful life of 20 years in 2017. All Vestas units will be 20 years old by 2020. The
Clipper turbine energy purchases are currently anticipated to end in 2015 and Silver Sage
purchases are expected to continue to 2029.
About 56% of the total wholesale renewable supply in 2010 was from RECs, purchased from
renewable generation facilities in Colorado, Nebraska, Oklahoma, Kansas, and Idaho. Over
time, it is anticipated that the amount of RECs in the supply mix will decrease. By 2015, about
one-third of the total supply is expected to come from RECs and by 2020, this level is expected
to drop to about 20%.
3. Need and Timing for Additional Renewable Energy Sources
The table below summarizes the anticipated levels of renewable supply required by each
municipality, existing sources and projected need for new sources in the future. As indicated in
the table, existing qualified renewable sources are sufficient to meet the needs of the
municipalities until about 2015 (assuming no retirements). At that time, the need for new
sources will be about 40,000 MWh/yr (roughly 30% more than historical deliveries from
existing sources).
The specific amount and timing of new renewable sources acquired by Platte River will depend
on formal requests from the municipalities in the future. Wholesale renewable sources to be
acquired may be affected by the level of distributed renewable sources – those located within
the municipalities’ retail system.
0
1,000
2,000
3,000
4,000
5,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecProduction(MWh)Estimated
Actual
21 DRAFT 4/1/2011
The amount of renewable sources to be added will also depend on whether certain credits that
are provided for in the Colorado RES are applied. For example, every 1.0 MWh of generation
from solar facilities built before July 1, 2015 may count as 3.0 MWh toward the RES – for the life
of the generator.
Projected Renewable Supply Requirements
2012 2013 2014 2015 2016 2017 2018 2019 2020
Supply:
Existing RES Sources 58,415 58,415 58,415 57,086 55,411 55,411 55,411 55,411 55,411
Other Existing Sources 75,847 70,101 64,256 58,310 52,500 50,000 50,000 50,000 50,000
Total Sources (no retirements) 134,262 128,517 122,671 115,396 107,911 105,411 105,411 105,411 105,411
Needs:
Estes Park 2,461 2,461 2,461 2,461 2,461 2,461 2,461 2,461 2,461
Fort Collins 82,000 82,000 82,000 117,190 117,558 117,927 118,295 118,664 180,712
Longmont 33,000 32,500 30,000 29,000 28,000 28,000 28,000 28,000 28,000
Loveland 6,700 6,800 6,900 7,000 7,100 7,200 7,300 7,400 7,500
Total Forecasted Need 124,161 123,761 121,361 155,651 155,119 155,588 156,056 156,525 218,673
RES Requirements
Estes Park 0 0 0 0 0 0 0 0 0
Fort Collins 44,786 44,971 45,155 90,678 91,046 91,415 91,783 92,152 154,200
Longmont 0 0 0 0 0 0 0 9,366 9,507
Loveland 0 0 0 0 0 0 0 0 0
New RES Sources Needed 0 0 0 33,592 35,636 36,004 36,373 36,741 98,790
Other Sources Needed 0 0 0 6,663 11,573 14,173 14,273 14,373 14,473
Total New Sources Required 0 0 0 40,255 47,209 50,177 50,646 51,114 113,263
It is anticipated that future wholesale renewable requirements of the municipalities will be
formalized during early 2012. A Request for Proposal (RFP) for new wholesale renewable
sources may then be developed during late 2012, with the expectation that the next wholesale
renewable resource options will be identified by 2013.
Though non-hydro renewable resources are currently 100% wind sources, it is anticipated that
new renewable sources may come from other technologies. A range of options will be
considered, including wind, biogas, biomass, solar and small hydropower. The RFP process
will seek to identify renewable resources that can provide firm capacity at the time of system
peak, as well as deliver the most cost effective renewable energy. The decision to add any new
renewable generation will be made by the Platte River Board – likely sometime during 2013.
As indicated earlier, wind generation has not provided firm capacity at time of system peak.
Figure 18 shows generation from the wind project at Medicine Bow during the system peak
hour since operations began. Thirteen years of actual operating data are presented in the graph.
About two-thirds of the time, the generation level at time of system peak has been less than 10%
of rated output and over one-third of the time, generation was very near zero output.
22 DRAFT 4/1/2011
Figure 18 – Wind Generation at Time of System Peak
7.3%
1.3%0.2%
45.6%
21.6%
0.0%
5.2%7.1%
12.2%15.2%
41.8%
0.0%0.8%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
23 DRAFT 4/1/2011
VII. Demand Side Management
1. Introduction
Demand-Side Management (DSM) programs include ―Common Programs‖—those offered to
customers in all the municipalities (with coordination and some or all of the funding provided
by Platte River), and (2) ―Municipality Programs‖—those offered by each municipality. The
municipalities have offered energy efficiency information and services to their customers since
the 1970s and Platte River has provided energy services to the municipalities and their retail
customers since 1991. Details of DSM program activities over the last ten years are summarized
in the 2002 and 2007 IRPs. This IRP addresses current DSM programs and provides guidelines
for the period 2012 to 2016.
2. Current DSM Programs
A summary of current activity for Common Programs and Municipality Programs is provided
in this section—through early 2011. Plans for DSM operations beyond 2011 are provided in
section 3.
2.1 Common Programs
A brief description of the Common Programs that are currently offered is provided below.
LIGHTENUP – provides information, guidance, and rebates to support energy-efficient lighting
retrofits in commercial and industrial buildings.
Electric Efficiency Program (EEP) – encourages energy and peak demand savings through
custom and prescriptive rebates. Unique energy-efficiency projects can earn custom rebates
based on lifetime energy and demand savings. Prescriptive rebates are available for more
common efficiency upgrades, such as ENERGY STAR® reflective roofs or energy-efficient fan
motors and controls for commercial refrigeration.
Building Tune Up Program – provides retro-commissioning services to customers. Retro-
commissioning can be thought of as a tune up for a building, to help reduce energy usage and
peak demand.
Efficiency Express Program – with joint funding from Platte River, the municipalities, and a
grant from the Colorado Governor’s Energy Office, the program helps small commercial
customers identify and implement energy efficiency improvements. Improvements may consist
of efficiency retrofits that may be eligible for rebates from other programs or a building tune up.
Lighting with a Twist – this program provides rebates to retailers selling compact fluorescent
lamps (CFLs), to enable them to sell CFLs for agreed-upon discounted prices. The discounts
encourage residential and small commercial customers to purchase CFLs for their homes and
businesses.
Northern Colorado ENERGY STAR New Homes – initiated by a coalition of regional utilities
and local governments, the Northern Colorado ENERGY STAR Homes program actively
promotes major improvements in the energy efficiency of new homes being built in Northern
Colorado.
24 DRAFT 4/1/2011
SELECT HVAC Contractor Program – a regional effort and partnership that provides training,
recognition, and marketing support to contractors willing to follow industry-accepted quality
methods of installing and commissioning heating, ventilation, and air conditioning (HVAC)
systems for residential and commercial buildings.
Common programs have been operated since 2002. Between 2002 and 2010, approximately $10
million has been invested in these programs, including approximately $1.5 million of funding
provided by the municipalities. The estimated rate impact of Platte River spending is estimated
at about one percent of retail rates on average (about 1.3% wholesale). Benefits of these
Common Programs include the following:
Annual energy savings of approximately 71,000 MWh
o A 17 percent reduction in the energy-consumption growth rate, from an estimated
2.3 percent annual growth without DSM to 1.9 percent with DSM
o About 76,000 tons of greenhouse gas reduction potential
o Lower emissions of criteria pollutants
o Reduced fuel consumption and associated fuel price risk
Peak demand reduction of about 14 MW
o Approximately a one-year delay in the need for the next firm resource
Enhanced services to the municipalities’ retail customers
About 1,000 businesses and an estimated 20,000 residential customers have participated,
representing six percent of businesses and 17 percent of homes
Provision of options to help customers mitigate electric rate increases
Better comfort and lighting quality in buildings
Improved equipment quality and reliability
Expanded local investment in energy-efficient products and services
Local economic benefits associated with energy efficiency business activity
Figures 19, 20 and 21 provide graphical representations of program results since 2002. Note
that during the last several years, performance of the Common Programs has exceeded the
goals set in the 2002 and 2007 IRPs. Energy savings are 75 percent higher than initially planned
and DSM funding has been more than originally projected. Municipal utility funding of DSM
programs has increased significantly since 2002.
25 DRAFT 4/1/2011
Figure 19 – Common DSM Program Spending
Figure 20 – Common DSM Program Energy Savings
Figure 21 – Common DSM Program Peak Demand Reduction
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
2002 2003 2004 2005 2006 2007 2008 2009 2010
Actual (Muni)
Actual (PRPA)
IRP
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
2002 2003 2004 2005 2006 2007 2008 2009 2010New Energy Savings (MWh/yr)Actual
IRP
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
2002 2003 2004 2005 2006 2007 2008 2009 2010New Demand Reduction (MW)Actual
IRP
26 DRAFT 4/1/2011
2.2 Municipality Programs
In addition to supporting the Common Programs, the municipalities each offer their own
individual DSM programs based on goals and policies developed by municipal utility
management and municipal government entities. Following are descriptions of these programs
(provided by the municipalities).
2.2.1 Estes Park Light and Power
Estes Park Light & Power offers the following DSM programs to complement the programs
offered through Platte River:
Annual Holiday Bulb Exchange: for each strand of incandescent holiday lights, the
customer receives a coupon worth $3 off an LED light strand (limit: 3 exchanges per person).
Free Residential Energy Assessments with CFL Bulb Exchanges. Up to 15 CFLs can be
exchanged (upon assessor’s recommendation) with every free energy assessment. All
customers of Estes Park Light & Power are eligible.
Energy Efficiency Rebates – Residential. Customers who use electricity for heating are
eligible. Rebates cover 50% of costs, up to $600 for energy efficiency improvements, as
defined by the energy assessor.
Electric Thermal Storage Heater Lease-to-Own program and Time of Day Rate:
Commercial and Residential customers can finance 90% of the installed cost up to $5,000 for
a term up to 36 months. The loan is paid off through their utility bills; interest is nominal,
usually between 1-2%.
2.2.2 Fort Collins Utilities
The following table summarizes residential and commercial energy efficiency programs and
services offered by Fort Collins Utilities as of 2010. Many of the programs are designed to
address energy efficiency, water efficiency and behavioral savings with a coordinated approach.
Note that some of the programs described here are collaborations with Platte River and may
also be described in that section of the IRP.
In addition to the items in the table, Fort Collins Utilities operates Load Management and
Demand Response programs, including direct load control for residential and commercial
customers and demand response for commercial customers.
The Load Management Program for Residential Customers has over 1,000 customers with Air
Conditioner Digital Control Units and over 1,750 customers with Water Heater Digital Control
Units. This represents a total load under control of 2.2 MW with a breakdown of 1,000 kW and
1,200 kW in air conditioning and water heating respectively (yearly load averages).
27 DRAFT 4/1/2011
Fort Collins 2010 Energy Efficiency Programs and Services
Program Description
Business Efficiency The Business Efficiency Program includes:
Commercial Efficiency Assessments
Rebates
New Construction Design and Performance Rebates
Education and Outreach
See fcgov.com/utilities/business
Consumer Products The Consumer Products Program provides rebates for
ENERGY STAR qualified products at local retailers for:
Clothes Washers
Dishwashers
Compact Fluorescent Light Bulbs
Special Promotions
The Consumer Products Program also includes the
Refrigerator and Freezer Recycling Program.
See fcgov.com/utilities/residential
Home Efficiency The Home Efficiency Program provides:
Low-cost energy/water audits
Participating Contractors
Rebates for 23 categories of home upgrades, such as
insulation, air sealing, furnaces and air conditioners.
See fcgov.com/utilities/residential
Home Energy Reports The Home Energy Reports program started in late 2009. It
provides customized reports for 25,000 customers which put
their electric use in the context of similar homes.
See fcu.opower.com
The Load Management Program for C&I Customers include 25 unique customers, although some of
the customers have control equipment in several premises through the service territory. An
estimated total capacity of 7.4 MW is available among the C&I segment.
Combined (Residential and C&I) about 9.6 MW of peak clipping programs exist within the
service territory.
2.2.3 Longmont Power & Communications
Longmont Power & Communications (LPC) has been providing energy services and Demand
Side Management (DSM) services to its customers for nearly 15 years. During this period the
range of resources has evolved to assist customers with energy-efficiency and renewable energy
options. Customers can obtain information through correspondence with Customer Services
staff at public events, by phone, or by email as well as through their own initiative via LPC’s
website. Website resources include information on existing services and links to other
government and non-profit agency websites on energy conservation. Customers can register to
receive monthly electronic newsletters. PowerOutlet and PowerSource are designed to help
28 DRAFT 4/1/2011
customers be self sufficient in changing energy efficiency behavior and are tailored to
residential and commercial customers respectively. LPC also provides free energy assessment
services to customers.
In addition to supporting the Common DSM Programs, Longmont Power & Communications
(LPC) has also developed and budgeted for its own DSM services and financial incentives to
suit customer needs as well as the recommendations of city councils. The list of local services
has evolved over the years and has included a variety of energy efficiency as well as renewable
energy incentives. The current services include:
Residential—
ENERGY STAR appliance rebates- customers can receive a $50 rebate for the purchase or
ENERGY STAR clothes washer or dishwasher machines
Home energy assessments- various assessment levels from a free of charge (LPC staff) to
$140 professional assessments (including blower door test)
Matching grant program- LPC matches customer investment up to $500 on qualified home
energy equipment retrofits
LED holiday lighting- customer discounts on LED holiday light purchases for retired
incandescent holiday lights
Appliance meter loan program- free kilowatt-meter loan program for self assessment of 110
V service appliances
EnergySmart Program (in partnership with the City and County of Boulder)- assessment,
implementation assistance and financial incentives for energy efficient retrofits
Neighborhood Sweeps program focuses on an all day, weekend event that goes door-to-
door in a pre-selected neighborhood providing direct install measures such as CFLs, dryer
racks and power strips to low-income families
Commercial—
Energy assessments- various levels (from free to fee) of customer assistance to assess
potential facility retrofit opportunities
EnergySmart Program (in partnership with the City and County of Boulder)- assessment,
implementation assistance and financial incentives for energy efficient retrofits
2.2.4 Loveland Water and Power
Loveland Water and Power’s current DSM programs are focused primarily on summertime
peak demand reduction. The Partnering with Power (PWP) program is a residential and
commercial direct load control program that is aimed at achieving summertime peak demand
reduction by cycling the air conditioning systems of over 3,300 participating customers.
Loveland Water and Power also provides residential customers with information on energy
conservation via its web page. Commercial customers are provided with similar online
information as well as via a monthly e-newsletter called the Loveland Business Solution Center.
Loveland is in the process of developing and implementing several new residential DSM
programs (see section 3).
29 DRAFT 4/1/2011
3. Future DSM Programs
For the period 2012 to 2016, it is anticipated that both Common Programs and Municipality
Programs will continue to be offered to residential, commercial and industrial customers in the
four municipalities. There has been strong customer interest for these programs and significant
energy and peak demand savings have been achieved. A summary of plans for the Common
Programs is provided below, followed by DSM plans in each of the municipalities.
3.1 Key Guidelines for Common Programs
Program Evaluation – Common Programs have been operated for nearly ten years with review
of program performance provided primarily by Platte River and municipality staff. However,
beginning in 2012, it is recommended that more detailed evaluation be conducted for selected
Common Programs. A small portion of each year’s budget will be set aside to provide for
independent evaluation of one or two programs per year during the period 2012 to 2016.
Programs will be prioritized for evaluation based on the likelihood that the evaluation will
provide actionable information that can be used to improve the program’s results and cost
effectiveness. Energy and peak demand savings for Common Programs must be measurable
and verifiable, with an expectation that such savings will be integrated into future system load
forecasts and the associated need for new resources. These evaluations will help confirm the
accuracy of program savings estimates. In addition, evaluations can look at program
implementation approaches and processes, to help identify possible enhancements to program
efficiency and cost effectiveness.
Level of Investment – Funding of Common Programs by Platte River is anticipated to continue
at approximately the same level in 2012 through 2016 as in the 2011 budget. Currently,
Common Programs funded by Platte River lead to slightly higher wholesale and retail rates.
For future planning purposes, it is anticipated that the funding for Common Programs would
require a rate impact of no more than one percent at the retail level, on average, as determined
from Platte River’s financial model. For 2012 forward, funding for Common Programs is
estimated to be approximately $2 million annually. This represents a significant increase from
the 2007 IRP, which called for funding to grow from $0.79 million in 2007 to $1.55 million per
year by 2011.
This funding estimate is for planning purposes. The actual amount of funding for Common
Programs will be determined by Platte River’s Board of Directors on an annual basis, through
the regular budget process. Costs and benefits of Common Programs, rate impacts, status of
greenhouse gas legislation/regulation and other factors will be considered as annual funding
levels are established. For example, Platte River’s 2009 Climate Action Plan consultant (KEMA,
Inc.) estimated that greenhouse gas costs might have an impact as early as 2013, which would
have resulted in greater cost effectiveness for DSM programs. It currently appears that any
such costs would not occur until later (beyond 2013), though they may occur during the term of
this IRP (by 2016).
Cost Effectiveness – Funding of Common Programs will be prioritized based on cost
effectiveness, with the most cost effective programs given priority. Customer interest in
Common Programs has exceeded budget for the last few years, so this prioritization will help
30 DRAFT 4/1/2011
make future program funding decisions and help meet budgets. Cost/benefit analysis for the
Common Programs will be performed each year using financial models to determine results
from a wholesale perspective. Other perspectives include the municipal utility, program
participants, non-participants, and all ratepayers. A summary of existing costs and benefits
from multiple perspectives is provided in the following table. Costs and benefits listed are
readily quantifiable; as indicated above, other benefits exist that are difficult to quantify.
DSM Program Cost and Benefits – Multiple Perspectives
Perspective Costs Benefits
Wholesale Supplier Program operations
Lost municipal revenues
Increased surplus sales
Reduced fuel cost
Reduced purchases
Delayed capital costs
Municipal Utility Program operations
Lost retail revenues
Reduced wholesale purchases
Program Participants Program cost sharing
Increased electric rates
Utility bill reductions
Other (non-quantifiable)
Non-Participants Increased Electric Rates Other (non-quantifiable)
Since the last IRP significant changes have occurred, which have influenced DSM program cost
effectiveness (and planning in general). These include decreasing prices for surplus sales,
natural gas and purchased power, as well as increasing electric rates and more difficult
economic conditions overall (relative to 2007). In the future, there may be benefits associated
with reduced greenhouse gas emissions (due to reduced electricity consumption) and/or other
changes. Uncertainty exists regarding many of the cost/benefit variables and updated
estimates will be developed to improve the accuracy of rate impact analysis over time. Cost
effectiveness will need to be considered from multiple perspectives in a coordinated manner to
help define the best overall mix of future DSM programs.
Funding Equity – The portion of Common Program funding provided by Platte River to each of
the municipalities will be approximately equal to the municipalities’ equity ownership share in
Platte River. Approximate equity values for 2010 were as follows: Estes Park—5 percent, Fort
Collins—48 percent, Longmont—26 percent and Loveland—21 percent. In order to allow
flexibility in program operations, equity will be approximately maintained over a rolling three-
year averaging period. When appropriate, and when a municipality is unlikely to receive its
equity share of DSM funding, Platte River may provide other energy services (beyond the
Common Programs) to balance equity (if requested). Platte River and municipality staff will
work together to ensure that the tactics used to maintain funding equity are supportive of each
of the municipalities’ DSM program goals.
Anticipated Energy and Demand Savings – During the period 2012 to 2016, it is anticipated that
Common Programs will increase overall annual energy savings from the current level of 71,000
MWh to about 126,000 MWh. This assumes funding at the current 2011 budget level of
approximately $2 million from Platte River. Additional funding from the municipal utilities
may result in greater energy savings. On an annual basis, Common Programs will save about
0.32 percent of energy sold to the municipalities, so that after five years, sales will be 1.6 percent
31 DRAFT 4/1/2011
lower than without the programs. Peak demand reductions are expected to increase from the
current 14 MW to about 25 MW by 2016. This level of peak demand reduction would delay the
next system generation resource by about 20 months.
Greenhouse Gas Reduction Potential – Potential reductions in greenhouse gas (GHG) emissions
(particularly CO2) will be estimated each year for the DSM programs. As indicated in Platte
River’s 2009 Climate Action Plan, energy efficiency programs are among the lowest cost means
of reducing GHG emissions. Various DSM programs provide significantly different GHG
reduction potential. For example, programs that target only peak demand do not typically
reduce GHG emissions. The Common Programs will be focused on energy reduction. Some
Municipality Programs focus on peak demand.
Municipality / Platte River Staff Coordination – A team of DSM professionals from each of the
municipalities and Platte River will continue meeting on a periodic basis to plan and coordinate
the planning, delivery, and evaluation of Common Programs.
Common Program Roles and Responsibilities – Selecting, designing, marketing, and
administering DSM programs is a multifaceted endeavor, requiring close coordination of
various utility staff, customers, and trade allies (i.e., potential providers of energy-efficient
products or services). For Common DSM Programs the overall effort is shared among Platte
River and the municipalities, with fundamental roles anticipated to be delineated as indicated
in the following table. The division of responsibilities varies slightly among the municipalities
depending on available DSM resources.
DSM Program Tasks – Common Programs Platte River Municipality
Program evaluation & selection joint role joint role
Program design & upkeep (establishing efficiency
requirements and rebate levels, establishing program
procedures, developing application materials, identifying
market channels, branding)
joint role joint role
Trade ally management (coordination, promotion,
outreach, and support) lead role supporting role
Customer promotion and outreach supporting role lead role
Program administration (application review, application
approval, rebate request processing, project-level
measurement & verification, payment processing)
lead role supporting role
Overall program evaluation, measurement and verification lead role supporting role
Load forecast integration lead role supporting role
In addition to the formal provision of Common Programs, Platte River staff will continue to
provide technical support and other energy services to the municipalities, within the limits of
staff resources and expertise. Areas of support include energy auditing/assessment,
distributed generation evaluation and assistance in providing services to key account
customers.
32 DRAFT 4/1/2011
3.2 Future Plans for Municipality Programs
3.2.1 Estes Park Light and Power
Estes Park Light & Power plans to continue the programs described in section 2.2.1.
3.2.2 Fort Collins Utilities
The primary goals of Fort Collins’ Energy Policy are to sustain high-system reliability and to
contribute to the community’s climate protection goals and economic health. The purpose of
the policy is to provide strategic planning guidance for Fort Collins Utilities (Utilities). The
Energy Policy 2050 vision is to ensure highly reliable, competitive, carbon neutral electricity
supplies, managed in a sustainable, innovative, responsible and efficient manner for the Fort
Collins community. The Energy Policy and the most recent Annual Update are available at
http://www.fcgov.com/utilities/what-we-do.
The Energy Policy Annual Update reviews progress made to date in the primary goal areas of
the policy: reliability, climate protection, economic health and the City’s collaboration with
Platte River.
The policy includes the following specific targets and goals related to energy efficiency and load
management.
Achieve annual energy efficiency and conservation program savings of at least 1.5
percent of annual energy use
Increase the power managed by load management, smart grid and distributed
generation to at least 5 percent of 2005 system peak demand by 2015 and at least 10
percent by 2020
The City expects the following outcomes and benefits stemming from implementation of the
Energy Policy.
Continued high electric system reliability
Modernization of electric metering system
Long-term asset management of electric distribution system
Reduction of greenhouse gas emissions from efficiency, conservation and renewable
energy
Affordable electric bills, through competitive rates, efficiency and conservation
Local economic benefits resulting from a healthy municipal utility, high electric system
reliability, competitive electric rates and investments in efficiency and renewable
energy
Funding for implementation of efficiency programs related to the policy come from rate
revenue. As of January 2011, 4.6 percent of electricity revenues are directed towards efficiency
and load management programs.
33 DRAFT 4/1/2011
The energy efficiency goals of the Energy Policy translate to achieving program savings of
22,000 MWh per year. Over the IRP period of analysis, Fort Collins will achieve cumulative
energy savings of approximately 100,000 MWh annually and over 15 MW by the end of the five
years.
In the fall of 2009, Utilities received notice of a $15.4 million matching funds grant award from
the Department of Energy as part of the American Recovery and Reinvestment Act. The
funding will accelerate plans to implement Smart Grid technologies throughout the electric
distribution system that serves the community.
The Smart Meter Fort Collins project will link energy usage and home area networks, automate
and optimize grid operations to improve reliability and efficiency, enable customers to control
energy usage, improve the environment and stimulate economic growth by creating jobs and
business opportunities.
Smart Meter Fort Collins integrates the electric power distribution system with high-speed
broadband communications, connecting the customer’s delivery point with a fully integrated
power delivery system. Smart Meter Fort Collins encompasses a number of technologies
intended to enhance the quality, reliability, and value of service provided to Fort Collins
customers. The long-term improvements in the electric delivery grid include:
Advanced Metering Infrastructure
Demand Response (in-home displays, in-home thermostats and air conditioning (AC)
and water heater control switches) to enable customer response during peak periods and
help manage loads
Grid Automation to enhance transmission and distribution automation, increase
reliability and provide remote operations
Security Enhancements
3.2.3 Longmont Power & Communications
The City of Longmont has developed an Integrated Sustainability Plan (ISP) that includes
energy efficiency and savings goals. The ISP is currently being evaluated for adoption by City
Council and could potentially be integrated with standard City operating procedures. LPC will
monitor the ISP adoption process and inform Platte River accordingly.
Generally speaking during the next IRP period LPC will continue to facilitate and encourage
customers to participate in existing Common Programs and evolve the local DSM services as
needed. Apportionment of LPC’s city-share funding and potential budget funding for common
services as well as budget funding for local services shall be assessed at least annually. To
facilitate the assessment process, LPC plans to develop a variety of DSM metrics. Using the
metrics will allow LPC to consistently measure all DSM service effectiveness and make sound
recommendations to City Management and City Council in the budget process. Future DSM
services or modifications to existing services shall be based on the DSM metrics.
34 DRAFT 4/1/2011
3.2.4 Loveland Water and Power
LWP future energy efficiency and DSM goals are as follows:
1. Improve customer satisfaction by providing them with information, ideas, and solutions
to reduce their energy consumption.
2. Reduce energy consumption to delay the need for additional generation and additional
distribution system capacity
3. Participate in regional efforts to increase utility collaboration and support Platte River
goals.
4. Continue to provide high levels of electric system reliability by operating the system as
efficiently as possible.
5. Reduce peak power demand by 3 percent a year.
6. Provide customers the maximum energy-efficiency benefit at the lowest possible cost.
The primary strategy for lowering peak demand will continue to be an air conditioning direct
load control program called Partnering with Power, peak messaging and customer education.
LWP will be providing eight additional residential energy efficiency pilot programs in 2011.
The eight additional residential programs approved by City Council in July 2010 will be funded
in part by the utility and by a one percent rate increase to residential customers. The programs
are as follows:
Larimer County Youth Corps – LWP is partnering with the Larimer County Youth Corps
to offer basic audits and direct installs of water and energy items in low income homes.
Home Energy Reports - The largest and most targeted program will be the launch of the
Home Energy Reports program to 15,000 residents. LWP is using informative billing to
educate our customers on how much energy is being used, how it is being used and
where energy can be saved while hoping to save customers money on their utility bills.
Northern Colorado ENERGY STAR Homes - LWP partners with Northern Colorado
ENERGY STAR Homes to support ENERGY STAR qualified new homes.
Details on the five remaining programs are still in development, but the focus will be on rebates
for ENERGY STAR clothes washers, a tune up program for air conditioning, a refrigerator and
freezer recycling program, a three-tier home energy audit, and outreach and education in
Loveland’s schools.
LWP will focus on collaborating with other utilities, successfully marketing each program to
LWP’s residential customers and providing customers with ways to help them reduce their
utility bills.
3.3 Coordinated Integration of DSM into the System Load Forecast
A key goal during the term of this IRP is to integrate measurable DSM into future system load
forecasts, so that the effects of DSM are included in the next supply-side resource decision.
Currently, the estimated savings from Common Programs are included in the wholesale load
35 DRAFT 4/1/2011
forecast and each municipality individually treats DSM in its own forecasting process. The goal
is to include verifiable savings from both Common Programs and Municipality Programs in the
wholesale system forecast. The following general approach will be considered for developing a
combined DSM forecast:
Establish general measurement and verification standards
Evaluate each DSM program based on agreed to standards
Include a determination of how long the program savings persist (the current
assumption is ten years—average for all programs)
Aggregate estimated energy and peak demand savings
Integrate aggregated savings into system load forecast
It is anticipated that an initial estimate of overall (combined) DSM savings can be developed
during 2012, for inclusion in the 2013 system forecast. The estimates are anticipated to improve
over time as program evaluation and other experience expands. The system level estimates will
focus on savings over the next ten years, consistent with the ten-year system forecast.
36 DRAFT 4/1/2011
VIII. Environmental Management
1. Introduction
The Platte River Board has adopted an Environmental Policy and a set of Environmental
Principles to guide management and staff in planning and day-to-day operations and to clearly
communicate a set of priorities to everyone in the organization. This policy is outlined below.
2. Environmental Management System
PLATTE RIVER POWER AUTHORITY
Environmental Policy and Principles
Platte River provides reliable, low-cost electricity in an environmentally responsible manner to its
owner communities of Estes Park, Fort Collins, Longmont and Loveland. Depending on water
storage conditions, about one-fifth of the municipalities’ electrical energy requirements are served
from renewable resources including hydropower and wind. Platte River’s other energy resources are
fueled with coal and natural gas.
Platte River uses state-of-the-art air quality control systems at its power generation stations and meets
or exceeds all applicable environmental laws and regulations. As new legislation and regulations are
proposed, Platte River participates in public processes and supports additional control requirements
where costs are commensurate with measurable environmental benefits. In addition, as technology
improves and opportunities arise, Platte River will be proactive in evaluating and implementing
improvements in its power operations that balance environmental and other socio-economic concerns.
Platte River Power Authority…
considers environmental factors an integral part of all planning, design, construction, and
operating decisions.
reinforces environmental compliance through program reviews, training, and by communicating
environmental values throughout the organization.
encourages public participation in planning for the location of major facilities as a means of
avoiding and resolving conflicts and to achieve a balance between the need for an economic
electric supply and environmental quality.
conserves natural resources such as water, soils, grasslands, and wetland areas through efficient
use and careful planning. Where needed, Platte River restores land disturbed by its operations.
encourages employees to bring environmental issues forward to assure Platte River’s compliance
with applicable laws, rules, regulations, and permits.
strives to reduce environmental health and safety risks to its employees and the communities in
which it operates by (i) maintaining safe and healthful working conditions, (ii) responsible design
and operation of its facilities, and (iii) being prepared for emergencies.
works with its customers to support cost-effective programs to conserve energy.
coordinates its generation and transmission planning with neighboring utilities to minimize over -
building or under-utilization.
considers environmentally progressive technologies such as wind and solar power in addition to
other renewable technologies to meet its future generation needs.
37 DRAFT 4/1/2011
The ―environmentally responsible‖ aspect of Platte River’s mission is carried out through the
operation of its Environmental Management System (EMS), described graphically in Figure 22.
The EMS enables staff and management to coordinate efforts to continuously evaluate
environmental performance.
Figure 22
Since no new generating resources are planned during the period of this IRP, no environmental
assessment of possible generation technologies is provided in this document. These analyses
will be conducted in the future to determine the best fit for Platte River’s long-term resource
needs.
3. Climate Action Plan
In 2007, the Governor of the State of Colorado issued the Colorado Climate Action Plan, which
included a goal of reducing statewide greenhouse gas emissions to 20 percent below 2005 levels
by 2020 and 80 percent below 2005 levels by 2050. To meet the 2020 goal, Platte River would
need to reduce carbon dioxide emissions by approximately 700,000 metric tons. The Governor’s
Energy Office asked the state’s electric generation utilities to voluntarily develop plans to meet
these non-binding targets using approaches specific to each utility’s unique circumstances.
Platte River developed its own unique Climate Action Plan (CAP) in 2009. The plan is not
prescriptive, but rather outlines a set of options that Platte River can adopt to meet the 2020
reduction target and prepare for emerging federal or regional regulations. Platte River’s Board
of Directors will make policy and budget decisions associated with any future implementation
of options for reducing greenhouse gas emissions.
38 DRAFT 4/1/2011
To meet the 20% by 2020 target, an analysis was performed to determine the amount of carbon
dioxide emissions that could be saved by each of several options identified. Figure 23 shows
the emissions reduction potential for each analyzed measure:
Figure 23
The chart demonstrates that Platte River can achieve the 2020 emissions target with a
combination of the evaluated measures. Achieving the 2050 target will involve additional
measures. Carbon dioxide mitigation potential and costs for each measure were estimated
compared to a business-as-usual scenario to determine the relative cost-effectiveness for each
measure. Costs reflect Platte River’s costs (for example, new technology capital costs,
operations and maintenance costs, program costs, lost revenues) and benefits (reduced fuel
costs). There may be costs or benefits to other parties that fall outside this analysis. For
example, participants in energy efficiency and distributed photovoltaic programs will have both
costs and savings related to the measures installed.
The most cost-effective measures include reduction of surplus reserve energy sales, aggressive
demand side management (accounting for up to a one percent reduction of energy demand per
year or about 10% by 2020), and increasing wind generation.
Additional carbon dioxide reduction strategies could be pursued, but at higher costs. Such
strategies could include transition to more natural gas generation and expanded renewable
generation, including concentrated central station solar generation or distributed solar
photovoltaic generation. It is unclear at this time how Platte River could meet the 2050 target of
an 80 percent reduction below 2005 levels. New technologies would likely be needed, along
with expansion of the more expensive existing technologies.
39 DRAFT 4/1/2011
The evaluation conducted for the Climate Action Plan shows that Platte River can achieve the
2020 target. Meeting the 20% reduction was estimated to raise wholesale rates about 16% by
2020 in the 2009 analysis. Rate impacts may be different using more updated assumptions.
A copy of the 2009 Climate Action Plan is available upon request.
4. Coal to Gas Conversion Studies
In an effort to consider more significant greenhouse gas emission reductions than the 20% by
2020 goal in the Governor’s plan, Platte River staff considered the hypothetical option of
replacing coal generation with natural gas-fired generation sources. Two options were
considered: (1) replacing generation from the Craig coal units with combined cycle gas units
(located at the Rawhide site), and (2) conversion of the Rawhide coal unit to be fueled with
natural gas.
Based on very preliminary estimates, Platte River’s wholesale rate would increase about 140%
over the current rate by 2020 if Platte River were to convert all existing coal resources to natural
gas. Retail cost increases were estimated at 120% on average. Reductions in total CO2
emissions may reach approximately 57%.
40 DRAFT 4/1/2011
IX. Recommended Actions
Recommendations of this IRP are summarized below.
1. Continue to operate Demand Side Management Programs
It is recommended that Common Programs continue at approximately the same level in 2012
through 2016 as in the 2011 budget—approximately $2 million annually. This represents a
significant increase from the 2007 IRP, which called for funding to grow from $0.79 million in
2007 to $1.55 million per year by 2011. Retail rates are expected to be no more than 1% higher
with Common Programs than without the programs.
Individual Municipality Programs are also anticipated to continue, as guided by each
individual municipality’s policies and plans. A key goal during the term of this IRP is to
integrate measurable DSM load reductions into future system load forecasts, so that the effects
of DSM are included in the next resource decision. It is anticipated that an initial estimate of
overall (combined) DSM savings can be developed during 2012, for inclusion in the 2013 system
forecast, with refinements made in future years. The estimate will focus on savings over the
next ten years, consistent with the ten-year system forecast.
2. Continue Implementation of the Renewable Energy Supply Policy
Existing qualified renewable sources are sufficient to meet the needs of the municipalities until
about 2015. At that time, the need for new sources will be about 40,000 MWh/yr, which
represents about 30% more renewable supply than historical deliveries from existing sources. It
is recommended that future wholesale needs of the municipalities be confirmed and that a
Request for Proposals (RFP) for new renewable sources be developed during 2012, with options
for the next renewable resource identified by 2013. Though non-hydro renewable resources are
currently 100% wind sources, it is anticipated that new renewable sources may come from other
technologies. The RFP process will seek to identify renewable resources that can provide firm
capacity at the time of system peak, as well as deliver the most cost effective renewable energy.
Any decision to add new wholesale renewable sources would be made by the Platte River
Board of Directors.
3. Update Resource Planning Criteria
Beginning in 2012, it is recommended that the following criteria be used for future resource
planning:
Carry reserves or have access to firm capacity that is sufficient to meet load obligations
whenever the Rawhide coal unit is out of service
Maintain a minimum planning reserve margin of 15%
These new criteria mitigate the risk that resources are insufficient to meet loads if power is
unavailable for purchase at time of system peak. The past criteria allowed up to 65 MW of
41 DRAFT 4/1/2011
market purchase risk on a real time basis; the new criteria remove this risk and enhance
reliability of service to the municipalities.
4. Monitor Development of Regional Generation and Transmission Resources
Xcel Energy, Tri-State, WAPA or other utilities in the region may consider development of joint
projects in the future. Platte River will continue to maintain relationships with these entities to
ensure participation options in any new resource that may be beneficial.
Equally vital to the reliable supply of electricity is coordinated transmission planning. Platte
River works with the Front Range Planning Group and the Colorado Coordinated Planning
Group to review issues associated with transmission constraints and the need for new projects
in the region.
Platte River will continue to monitor future generation and transmission studies as they
develop. The outcomes of such integrated needs assessments are critical to resource planning
efforts not only because favorable opportunities for joint participation in resource development
projects may arise, but also because the actions taken by other entities may directly affect the
availability and pricing of electric energy, capacity, fuel, transmission, and ancillary services, all
of which have implications for the economics of future Platte River projects.
5. Monitor Load Forecasts and Evaluate Contingencies
The need for new resources and the timing of planning, permitting, and public information
processes is strongly dependent on actual load growth. Platte River staff will continue to
update load forecasts annually and will continue to seek opportunities to enhance forecasting
and resource planning techniques.
Staff will also actively pursue contingency options in the event that forecasts or other market
factors change significantly over time. These include seeking expanded market purchase
options, evaluation of new transmission paths for power delivery and monitoring of distributed
generation technologies.
42 DRAFT 4/1/2011
X. Public Participation
Several public communications processes of recent years have influenced the content of this
(and prior) IRP documents. Frequent interactions between Platte River, the member utilities,
municipal boards and councils, and the citizens of member communities have facilitated an
effective exchange of information on the public issues of electric load growth, resource supply,
and environmental stewardship. These exchanges include:
Surveys of customers by Platte River and the municipal utilities, soliciting citizens’ views on
the importance of renewable resources, DSM activities, and environmental concerns, as well
as system reliability, cost, and customer service.
Community surveys assessing attitudes and levels of interest in adding renewable resources
to Platte River’s resource portfolio.
Public hearings and permitting proceedings for the gas-peaking units at the Rawhide
Energy Station and for new transmission and substation installations.
Periodic presentations to customer groups regarding resource planning issues, electric
industry trends, rates, renewable energy and DSM.
Frequent interactions with residential and commercial/industrial customers in each
member community—as part of implementing DSM programs.
News releases and advertisements relating to renewable energy, DSM program offerings,
generation unit performance, greenhouse gas reporting, construction of new generation and
transmission facilities.
Public hearings for IRPs in 1997, 2002 and 2007.
Meetings with the Fort Collins Electric Board, the Loveland Utilities Commission, the Estes
Park Board of Trustees Utilities Committee and Longmont City Council to discuss electric
energy supply policy, electric system reliability, DSM activity and renewable energy
programs.
Additional meetings are planned to specifically review this draft IRP with the Estes Park
Board of Trustees Utilities Committee, the Fort Collins Electric Board, the Longmont City
Council and the Loveland Utilities Commission.
This draft IRP will be provided to Platte River Board members, managers/administrators of
each municipality, municipal utility staff, Platte River staff and interested members of the
public.
Copies of the draft IRP will be made available at the public libraries in each municipality
and at Platte River’s offices. It will also be available on Platte River’s web site.
Public notice of the draft IRP availability and notice of the planned public hearing (see
below) will be made in each of the municipalities’ major newspapers.
On April 28, 2011, the Platte River Board plans to hold a public hearing, where a summary of
the draft IRP will be presented. Time will be provided for public comment at that meeting.
The final 2012 IRP is expected to be approved by the Platte River Board (via resolution) after the
public information process is completed. The document will then be submitted to Western
Area Power Administration, in accordance with their Energy Planning and Management
Program (initiated by the 1992 Energy Policy Act).
LIGHT & POWER Report
To: PUP Committee
From: Reuben Bergsten, Interim Utilities Director
Barbara Boyer Buck, Office Manager
Date: April 14, 2011
RE: Energy Efficiency Updates
A variety of residential and commercial energy efficiency programs are being conducted
through Estes Park Light and Power (EPL&P) in 2011. A couple of programs are being
funded entirely by EPL&P; most are in partnership with Platte River Power Authority.
Funding from Platte River has increased in 2011 because we received a Main Street
Grant (our equity share, $20,839) to conduct Efficiency Express for commercial
customers.
The attached matrix details the programs currently offered, programs for which funds
have already been exhausted for the year, and those which will launch later in the year.
This spreadsheet also details the funds allocated to each program and the basic
parameters for each program.
The partnership with Platte River Power Authority on energy efficiency funding more
than doubles our energy efficiency budget, including the man hours and services
provided by Platte River’s Certified Energy Manager, Mike Rubala. Mike began
providing energy services for EPL&P customers at the beginning of 2010; by that
summer, his services had evolved into providing customized energy assessments for
EPL&P residential customers. To date, nearly 40 residential assessments have been
conducted by Mike; in addition, he has provided numerous consultations via phone or
personal meetings. Each assessment he conducts – at no charge to the EPL&P
residential customer –has a value of up to $350; furthermore, Mike has been gaining
valuable field insight to better help us customize our in-house energy efficiency
programs. Mike spends each Thursday in Estes Park, conducting energy assessments
and has recently partnered with EPL&P on a brand new incentive program, Residential
Energy Efficiency Plus (REAP).
REAP combines the free energy assessments with free direct-install CFL upgrades, and
for those with electric heat, energy efficiency rebates on specific measures identified in
the assessment process. Many of these improvements – installation of batt insulation,
new doors, weatherstripping, etc. – can be do-it-yourself. After the improvement(s) are
complete, Mike will conduct a follow-up visit to determine the installation(s) were
completed correctly. If so, the customer is eligible for a rebate of 50% of the cost of the
improvement(s) (based on invoices or receipts) up to $600.
Another beneficial partnership was created with REAP; the Estes Park Housing
Authority (EPHA) has created applications for income-qualified participants. Those
whose incomes are 80% or less of the Larimer County average will qualify for 100% of
the cost up to $600. EPHA will conduct the income qualification for those interested in
this option.
REAP is a result of the field insights and customer feedback on past programs EPL&P
has offered. It was determined that the best use of our residential funds for energy
efficiency would be through a program specific to our unique demographics.
“This is a grass-roots program, customized to the individual customer,” said Mike. “Each
analysis and supported remedy is site-specific.” Mike cited very unique attributes of the
EPL&P service area including available fuel sources, age of the building stock, weather
patterns and regional temperatures.
“There is a high propensity of electric heat and propane which is not predominant in any
of the other Platte River Municipalities,” Mike said. In addition, with the high percentage
of retired residents, there are many customers on fixed incomes, he noted.
REAP was “soft-launched” on March 28; the program will run for a few weeks for those
who have already signed up for assessments. In late April, public outreach will begin
with advertising and press releases. Based on the results achieved with REAP this
year, EPL&P will evaluate whether to continue this program in 2012.
In addition to the programs listed on the attached matrix, EPL&P will provide up to
$35,000 for energy efficiency upgrades for the Senior Center.
Staff will bring forward status reports of all of our energy efficiency programs and
projects throughout 2011.
Budget
502-6501-560.26-25 Energy Efficiency 2011 $100,000
Platte River Equity Funding for Estes Park, 2011 $111,613
Total funding for 2011 EPL&P Energy Efficiency in 2011 $211,613
2011 Demand Side Management ProgramsName of ProgramDescription ParametersCustomers ServedLaunch DateEnd Date Funded by Primary Contact# of possible program participantsEFFICIENCY EXPRESSEnergy assessments Building must be less Commerical only 3/25/2011 12/31/2011 EPL&P: $5,300 Barbara Boyer Buck 9Building tune ups than 50,000 square feet Platte River: $20,839Logos: Upgrade assistance Must be a customer of (through a grant from EPL&P and Platte River EPL&P the GEO)Either own the buildingor have permission fromthe owner.RESIDENTIAL ENERGYFree energy 50% of the cost up to Residential only 3/28/2011 12/31/2011 EPL&P: $20,000 Barbara Boyer Buck 30 rebatesASSESSMENTS PLUSassessments $600 (soft) Platte River: $6,000 up to 70 assess-(REAP)" PLUS" free CFL bulbs Income qualified = 100% ads start (LWAT funding) mentsRebates for those with of the cost up to $600 4/15/2011 1200 CFL bulbsLogos: electric heat Rebates for electric EPL&P heat homes onlyEveryone eligible for freeassessments & CFLsEPL&P customers onlyLIGHTEN UP!Commerical Lighting Commerical customers Commerical only 1/1/2011 3/15/2011 EPL&P - $23,750 Adam Perry/Platte 16 projectsRebates only (funding Platte River - $44,601 RiverLogos: Rebates are caculated by exhaustedEPL&P and Platte River Platte River, based on for efficiency achieved 2011)Applies to lighitng efficiencyonlyPrequalification required onprojects over $1,000Lighting With a TwistIn-store promotion with Bring in an incandescent Residential and 11-Oct 11/30/2011 EPL&P - $0 Barbara Boyer Buck Approximately (CFL Bulb Round Up) True Value bulb and exchange it for a Commerical Platte River - $1,000 100 coupons with coupon worth $2 off a recycling.specialty CFL bulbHoliday Bulb ExchangeHoliday light strings $3 coupon given for Resident and Nov-11 12/31/2011 EPL&P - $1,000 Barbara Boyer Buck Approximately exhcanged for coupons for each strand of incandescent Commercial300 couponsLogos: LED holiday light strings bulbs turned inEPL&P limit - 3 per customerPlatte River Contribution is Our Share of Equity Split for DSM FundsPage 1 of 2
2011 Demand Side Management ProgramsName of ProgramDescription ParametersCustomers ServedLaunch DateEnd Date Funded by Primary Contact# of possible program participantsEnergy Efficiency RebatesCommerical Energy Commerical customers Commerical only 1/1/2011 funding EPL&P - $0 Adam Perry/Platte Up to 9 Efficiency Rebates only reserved for Platte River - $23,048 River projectsLogos: Rebates are calcuated by Efficiency EPL&P and Platte River Platte River, based on Express efficiency achieved rebatesLarge Building Tune UpsCommerical Building Commerical customers Commerical only 1/1/2011 funding EPL&P - $4,750 Adam Perry/Platte This funding hastune ups only transferred Platte River - $5,250 been used to helpLogos: Existing equipment "tuned- to LU complete the 16n/a up" to be more efficientprojects in LUThis is currently beingaddressed under EfficiencyExpress so this funding has been transferred to "LightenUp"Energy Star New HomesIncentive to build New construction only Residential only 1/1/2011 12/31/2011 EPL&P - $0 Adam Perry/Platte membership feeEnergy Star certified Residential only Platte River - $625 & used forLogos: new homes Must adhere to Energymarketing EPL&P and Platte RiverStar standardsGeneral DSMmarketing and 1/1/2011 12/31/2011 EPL&P - $0 consulting feesmaterial funds for DSMPlatte River - $7,750 marketingLogos: programsfor DSM EPL&P and Platte RiverprogramsSelect HVACTraining for 1/1/2011 12/31/2011 EPL&P - $0 13 HVAC HVAC installersPlatte River - $2,500 installers inLogos: to create recommendedNorthern Colo. Platte River installer listare currentlycertified.Platte River Contribution is Our Share of Equity Split for DSM FundsPage 2 of 2
Page 1
WATER DEPARTMENT Memo
To: Public Safety/Public Works/Utilities Committee
From: Jeff Boles, Water Superintendent
Date: April 14, 2011
RE: Marys Lake WTP Expansion Upgrade
Our requirement for additional operational testing to confirm software programming
changes made by GE/Zenon was completed on January 12, 2011. The plant has
remained in operation since that time and there are just a few outstanding items
remaining to complete this project.
These outstanding items are:
1. The final O&M Manual and an up-to-date Control Logic Summary Chart
(CLSC) must be provided to the Town.
2. Sign and return all outstanding change orders. The following table
summarizes all the change orders that were discussed and agreed upon with
previous project managers at GE. Copies of Change Orders 6 and 7, which
still require GE signatures, were sent by email on October 15, 2010.
3. GE is required to provide as-built drawings for all GE drawings.
Summary of GE/Zenon Change Orders for Town of Estes Park Marys Lake
Treatment Plant
Description
Zenon
CO #
Agreed Cost w/
Zenon Comments
Turbidimeter - Combined
Permeate 7 $ (1,500.00)
Agreed on 3/20/09
Level Element - Waste
Holding Tank No. 1 7 $ (2,200.00)
Agreed on 3/20/09
CIP Skid BFV's, CIPS
BFV's, and CIPR BFV's 7 $ (12,000.00)
Agreed on 3/20/09
First Stage Process Pumps
Flexible Connections 7 $ (4,500.00)
Agreed on 3/20/09
Compressor Power Failure-
Fault 6 $ (1,172.00)
Change order issued but
not signed by GE Zenon
as of 12/1/09
Page 2
WATER DEPARTMENT Memo
On March 15, 2011 we received an email from GE/Zenon that there would be a delay
involving the screen captures and their incorporation in the final O&M documents.
The anticipated schedule for delivery of the O&M’s to HDR Engineering for review is
April 8, 2011.
The water plant was transferred within GE/Zenon out of the commissioning group to
their Lifecycle group as of April 1, 2010. This group assists plants with 24/7 technical
telephone support during normal operation. In lieu of the ZenoTrac monitoring option as
budgeted in 2011 I’ve requested to keep the 24/7 telephone technical support and
requested an additional 3-day site visit by the programmer to make a couple of
operational changes that have come up during normal operations.
Memo
To: PUP Committee
From: Dave Mahany, Public Works Superintendent
Date: April 14, 2011
RE: Snow Plow Truck Replacement
Background:
The 2011 Vehicle Replacement budget includes $185,000 (635-700-435.34-42, page
170) for the replacement of the Street Department’s 2000 Freightliner FL80 4x4
Snowplow Dump Truck.
This truck is 10 years old; it is within the Vehicle Replacement Policy parameters,
(Replacement Type 6 / Monitor Costs at 10 – 15 years).
• Alternative fuel option: “No option available” for this type of equipment.
This equipment is become very undependable and the cost to operate is approximately
three time higher than other like equipment.
This equipment is under State Bid Contract so the following pricing is Colorado State Bid.
McCandless International, Aurora, CO
2011 International 7500 4x4 Dump Truck and Snowplow…………...……$200,548.00
Trade-in: 2000 4x4 Freightliner Dump Truck Snowplow ……………..$ 15,000.00
Bid Price $185,548.00
Budget:
$185,000.00 Vehicle Replacement Fund 635-7000-435.34-42 /p-170
$185,548.00 Cost
Recommendation:
I recommend trading the 2000 Freightliner 4x4 Snowplow Truck and purchasing the
budgeted 2011 International 7500 4x4 Snowplow Truck for $185,548.00 from
McCandless International Trucks of Aurora, Co. for the State Bid Price of $185,548.00 to
the Town Board, to be included on the Consent Agenda at the April 26, 2011 Town
Board.
PUBLIC WORKS -
STREETS