2005 RPU_34945_Report on the Electric Utility Baseline Strategy for 2005 2030_June_2005

2005 RPU_34945_Report on the Electric Utility Baseline Strategy for 2005 2030_June_2005
Report on the
Electric Utility Baseline Strategy for
2005-2030 Electric Infrastructure
Prepared for
Rochester Public Utilities
Rochester, Minnesota
Project 34945
June 2005
June 15, 2005
Mr. Wally Schlink
Rochester Public Utilities
4000 E. River Rd. NE
Rochester, MN 55906-2813
RE: Baseline Electric Infrastructure Study
Rochester Public Utilities
Project 34945
Dear Mr. Schlink:
Burns & McDonnell was authorized to assist the Rochester Public Utilities (RPU) in its
assessment of future requirements for its electrical infrastructure. The RPU desired a baseline
assessment of its financial requirements over a study period to 2030. The assessment included
the review of traditional resources associated with meeting RPU’s projected demand and energy
needs to develop a traditional resource expansion plan. The impacts which demand side and
renewable options might have on the traditional plan were also included. The costs for several
futures were modeled in a detailed financial model developed by RPU. The model allowed a
detailed assessment of a variety of measures such as rates, average bills and debt requirements to
be developed. These parameters were used to identify the more attractive future for RPU to
pursue. This report provides the results of the assessment.
The assessment for RPU identified issues which need to be confronted within the time frame
between now and 2015 and from 2016 to 2030. These periods were selected to coincide with the
various options associated with the Silver Lake Plant capacity under the contract with the
Minnesota Municipal Power Agency.
Conclusions and Recommendations
The results of this study indicate that the Silver Lake Plant Unit 4 should be kept in operation
throughout the study period. The determination of the status of Units 1-3 depends on the cost of
replacement capacity at the end of the MMPA contract.
With the above assumption on Silver Lake Unit 4, the RPU is not in need of significant resource
expansion to meet its projected demand and energy requirements until approximately 2016. Prior
to that date, RPU should rely on the market for seasonal purchases to make up any deficits. Post
2016, a mixture of market, gas and coal-fired resources provide the lowest cost evaluated plan.
The above conclusion on use of market capacity is tempered by the fact that RPU will have to
correct the existing transmission limitations into the RPU service territory or add internal
generation in order to regain previous levels of power supply reliability for its customers. The
current limitations reduce the firm import of its supply from the Southern Minnesota Municipal
Power Agency when the load in the area around RPU exceeds certain levels. These levels are
being exceeded during an increasing number of hours per year. Therefore, reliance on the market
Mr. Wally Schlink
June 15, 2005
Page 2
for firm imports during the summer months is not considered prudent until the transmission
limitation is removed.
Challenges which RPU will confront over the next ten years include environmental controls and
upgrades to the Silver Lake Plant Unit 4 and potentially Units 1-3 to continue operation in
compliance with expected environmental regulations. The investments in these units will help
prolong the time when RPU will need replacement coal capacity.
RPU should pursue the aggressive demand side management reductions identified. The
achievement of the estimated reductions will postpone the need for additional base load capacity.
Synopsis of Process
Burns & McDonnell developed the traditional resource plan by first reviewing the load
projections prepared by RPU. The forecast allowed an assessment of the capacity and energy
deficiencies associated with various futures. The primary variance in the futures was due to the
assumptions used for the capacity at the Silver Lake Power Plant.
Resource expansion plans were developed which provided an assessment of the benefits of gas
and coal-fired resource options. Participation in projects being developed in the region were
considered along with resources that RPU could develop on its own. These options were
reviewed on a net present value basis to determine the lower cost options.
Risk analysis was performed on the lower cost options. Assumptions were varied to determine
their impact on the evaluation. Risk profiles of the probable net present values were determined.
The report provides a complete description of the process and the results identified.
A variety of demand side options were considered to reduce the demand and energy needs of
RPU. Benefit cost analysis was performed on the options to determine the attractiveness of the
options from the utility rate payers, participant and society perspectives. This review was aided
by input from a Citizen’s Advisory group.
The estimated reductions in demand and energy requirements were removed from the forecast.
The revised forecast was then used to assess the RPU renewable energy needs to meet the state
renewable portfolio standard.
The various futures with and without the DSM and renewable impacts were modeled in the
detailed financial forecast model. The results indicated that an aggressive DSM approach would
provide benefits to RPU in delaying base load capacity.
Summary
The results of the infrastructure plan have identified the lower cost approaches to meeting the
RPU demand and energy requirements to the year 2030 include a combination of market
purchases, gas and coal-fired resource additions, ongoing modifications to the Silver Lake Plant
and a variety of DSM programs. Renewable energy should be pursued from wind resources and
the Olmstead Waste to Energy Facility biomass facility.
Mr. Wally Schlink
June 15, 2005
Page 3
We look forward to discussing any aspect of this report with you at your convenience.
Sincerely,
BURNS & MCDONNELL
Jeff Greig
General Manager
Business & Technology Services
Kiah Harris
Project Manager
KH/pma
Table of Contents
TABLE OF CONTENTS
SUMMARY....................................................................................................................... S-1
Current Conditions.....................................................................................................................S-2
Generation Resources ................................................................................................................S-2
Transmission ............................................................................................................................S-3
Resource Options ......................................................................................................................S-4
Results .......................................................................................................................................S-6
Demand Side Management & Renewable Options...................................................................S-7
Current DSM Efforts.................................................................................................................S-8
Study Approach.........................................................................................................................S-8
Renewable Energy Options......................................................................................................S-10
DSM & Renewable Impacts on RPU Supply Needs................................................................S-11
Financial Analysis ....................................................................................................................S-13
Externalities ............................................................................................................................S-15
Results ......................................................................................................................................S-15
Resource Plan ..........................................................................................................................S-15
Rates.......................................................................................................................................S-16
Emissions ................................................................................................................................S-19
Summary ..................................................................................................................................S-19
Conclusions ..............................................................................................................................S-20
Recommendations ....................................................................................................................S-21
PART I – INTRODUCTION............................................................................................... I-1
Utility Issues.............................................................................................................................. I-2
Generation................................................................................................................................ I-2
Transmission & Distribution ...................................................................................................... I-3
Load Growth ............................................................................................................................ I-3
Financial & Administrative ........................................................................................................ I-3
Long Range Plan ....................................................................................................................... I-4
Methodology ............................................................................................................................. I-5
Study Development ................................................................................................................... I-6
Report Organization .................................................................................................................. I-6
PART II – POWER SUPPLY RESOURCES.....................................................................II-1
Load Forecast ............................................................................................................................II-1
Resource Review.......................................................................................................................II-2
Silver Lake Plant ......................................................................................................................II-5
Cascade Creek ..........................................................................................................................II-7
Zumbro River ...........................................................................................................................II-8
Southern Minnesota Municipal Power Agency ............................................................................II-8
Transmission Issues ..................................................................................................................II-8
Electrical System Reliability ......................................................................................................II-8
System Improvements ..............................................................................................................II-11
Potential Resource Options ......................................................................................................II-11
Fuel Considerations..................................................................................................................II-16
Summary ..................................................................................................................................II-18
Rochester Public Utilities
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Table of Contents
PART III – RESOURCE OPTIONS ANALYSIS............................................................... III-1
Regional Market Conditions .................................................................................................... III-1
Coal Unit Development ............................................................................................................ III-1
Market Pricing ......................................................................................................................... III-2
Resource Requirements............................................................................................................ III-3
Traditional Options .................................................................................................................. III-5
Gas-Fired Options .................................................................................................................... III-5
Coal-Fired Options................................................................................................................... III-6
Traditional Resource Portfolios ............................................................................................... III-6
Production Cost Results............................................................................................................ III-8
Summary .................................................................................................................................. III-9
PART IV – ECONOMICAL ANALYSIS OF PREFERRED OPTIONS.............................IV-1
Options for Review ........................................................................................................................IV-1
Near Term Issues......................................................................................................................IV-5
Silver Lake Power Plant ...........................................................................................................IV-7
Coal Unit Participation .............................................................................................................IV-7
Transmission Investment ..........................................................................................................IV-7
Summary ..................................................................................................................................IV-8
PART V – DEMAND SIDE MANAGEMENT & RENEWABLE OPTIONS....................... V-1
Current DSM Efforts .......................................................................................................................V-1
Study Approach ...............................................................................................................................V-2
End Use Survey ...........................................................................................................................V-2
Benefit Cost Analysis ...................................................................................................................V-2
Task Force .......................................................................................................................................V-5
Review of Conservation Potential ...................................................................................................V-5
Residential Potential.....................................................................................................................V-5
Commercial Potential ...................................................................................................................V-7
Load Shape Modification Programs ................................................................................................V-9
Load Management ......................................................................................................................V-10
Demand Response Programs ........................................................................................................V-10
RPU DSM Program........................................................................................................................V-12
Renewable Energy Options ............................................................................................................V-14
Solar ..........................................................................................................................................V-14
Wind ..........................................................................................................................................V-17
Biomass .....................................................................................................................................V-18
Fuel Cells ...................................................................................................................................V-18
Renewable Portfolio Program ......................................................................................................V-19
DSM & Renewable Impacts on RPU Supply Needs......................................................................V-22
Conclusions & Recommendations .................................................................................................V-23
PART VI – FINANCIAL FORECAST...............................................................................VI-1
Financial Model..............................................................................................................................VI-1
Input Assumptions ......................................................................................................................VI-1
Methodology ..............................................................................................................................VI-3
Externalities ...............................................................................................................................VI-3
Renewable Options .....................................................................................................................VI-4
Results ............................................................................................................................................VI-6
Resource Plan...........................................................................................................................VI-6
Rates.........................................................................................................................................VI-6
Emissions ................................................................................................................................VI-10
Conclusions ...................................................................................................................................VI-10
Recommendations .........................................................................................................................VI-11
Rochester Public Utilities
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Burns & McDonnell
Table of Contents
APPENDICES
APPENDIX I – LOAD FORECAST (WITHOUT DSM IMPACTS)
APPENDIX II – RESOURCE OPERATING INFORMATION & OTHER MODELING
ASSUMPTIONS
APPENDIX III – PRODUCTION COST ANALYSIS DETAILS
APPENDIX IV – ● END USE SURVEY & SUMMARY OF RESULTS
● END USE SURVEY QUESTIONS FORMS FOR RESIDENTIAL,
COMMERCIAL & INDUSTRIAL CUSTOMERS
● “NEXT LEVEL” TRIAD REPORT
● TASK FORCE RECOMMENDATIONS
● RESIDENTIAL & COMMERCIAL END USE INFORMATION
● STATISTICAL RELATIONSHIP PHOTOVOLTAIC GENERATION &
ELECTRIC UTILITY DEMAND IN MINNESOTA (1996 – 2002)
APPENDIX V – FINANCIAL FORECAST DETAILS
Rochester Public Utilities
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Table of Contents
LIST OF TABLES
Table No.
Page No.
SUMMARY
S-1
Range of Capacity Requirements for Various SLP Retirement Scenarios ..................S-4
S-2
Resource Portfolios......................................................................................................S-5
S-3
Summary of Energy Sources from Gas or Coal Portfolios..........................................S-5
S-4
Summary of Net Present Values for Portfolio Options................................................S-6
S-5
Estimated Additional DSM & Efficiency Impacts – To RPU Energy Forecast ..........S-9
S-6
Estimated DSM & Efficiency Improvements Impacts ................................................S-9
S-7
RPU Estimated Annual Renewable Energy Requirements (MWh)............................S-11
S-8
Total Tons of Emissions by Scenario ........................ ................................................S-19
S-9
Retail Portion of RPU Costs of Various Plans with Externalities ..............................S-19
PART II – POWER SUPPLY RESOURCES
II-1
RPU Forecast of Demand & Energy 2003-2030 .........................................................II-2
II-2
RPU Generation Capability Forecast 2004-2030 ........................................................II-4
II-3
Unit Data......................................................................................................................II-6
II-4
Range of Capacity Requirements for Various Retirements Scenarios........................II-11
PART III - RESOURCE OPTIONS ANALYSIS
III-1
Resource Portfolios..................................................................................................... III-7
III-2
Summary of Energy Resources from Gas or Coal Portfolios ..................................... III-8
III-3
Summary of Net Present Values for Portfolio Options............................................... III-9
PART IV – ECONOMICAL ANALYSIS OF PREFERRED OPTIONS
IV-1
Lowest Evaluated Cost Traditional Resource Portfolios ............................................IV-1
IV-2
Assumption Variations Used to Evaluate Lower Cost Resource Portfolios ...............IV-2
PART V – DEMAND SIDE MANAGEMENT & RENEWABLE OPTIONS
V-1
Summary of Benefit Cost Analysis Results.................................................................V-4
V-2
Estimated Maximum Potential Reductions – Residential RPU Customers .................V-7
V-3
Estimated Maximum Potential Reductions – Commercial RPU Customers ...............V-9
V-4
Estimated Additional DSM & Efficiency Impacts – To RPU Energy Forecast .........V-13
V-5
Estimated DSM & Efficiency Improvement Impacts .................................................V-14
V-6
Solar Information from a 2.6kW Fixed Plate Array - Rochester, MN........................V-15
V-7
Wind Project Statistics................................................................................................V-17
V-8
Estimated MW of Wind or Solar Required to Meet the RPU Renewable Energy
Rochester Public Utilities
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Table of Contents
Requirements Post 2015 ......................................................................................V-20
V-9
RPU Estimated Annual Renewable Energy Requirements (MWh)............................V-21
PART VI – FINANCIAL FORECAST
VI-1
Financial Model Load Forecast ................................. ................................................VI-2
VI-2
Externality Values...................................................... ................................................VI-4
VI-3
Emission Rates........................................................... ................................................VI-4
VI-4
Average Energy Costs with Externalities .................. ................................................VI-5
VI-5
Impacts of Equivalent Capacity on Energy Cost ....... ................................................VI-5
VI-6
Total Tons of Emissions by Scenario ........................ ...............................................VI-10
VI-7
Retail Portion of RPU Costs of Various Plans with Externalities .............................VI-10
Rochester Public Utilities
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Table of Contents
LIST OF FIGURES
Figure No.
Page No.
SUMMARY
S-1
RPU Balance of Loads & Resources 2004-2030.........................................................S-3
S-2
Probable Net Present Values - Lower Evaluated Cases...............................................S-7
S-3
Comparison of Base & Revised Forecasts with DSM & Renewable Impacts............S-12
S-4
Impact of DSM & Renewables on Lowest Evaluated Traditional Resource Plan
Balance of Loads & Resources.......................... ................................................S-13
S-5
Retail $/MWH-Major Customer Classes ................... ................................................S-17
S-6
Average Annual Bill-Major Customer Classes.......... ................................................S-18
PART I – INTRODUCTION
I-1
Summary Decision Tree – Traditional Power Supply Options.................................... I-7
PART II – POWER SUPPLY RESOURCES
II-1
RPU Forecasted Load & Resources.............................................................................II-3
II-2
View of the Silver Lake Power Plant...........................................................................II-6
II-3
Area Interconnections with RPU .................................................................................II-9
II-4
RPU 2005 Load Duration Curve ................................................................................II-10
II-5A
Approximate RPU Load Duration Curve 2005 ..........................................................II-12
II-5B
Approximate RPU Load Duration Curve 2010 ..........................................................II-12
II-5C
Approximate RPU Load Duration Curve 2015 ..........................................................II-13
II-6
RPU Projected Hourly Load – 2016 ...........................................................................II-14
II-7A
RPU Projected Hourly Loads Week of January 1-7 ...................................................II-15
II-7B
RPU Projected Hourly Loads Week of July 1-7 .........................................................II-15
PART III – RESOURCE OPTIONS ANALYSIS
III-1
MAPP Spot Energy Pricing 1997 – 2003 ................................................................... III-2
III-2
RPU Balance of Loads & Resources – No SLP ......................................................... III-3
III-3
RPU Balance of Loads & Resources – 45MW of SLP............................................... III-4
III-4
RPU Balance of Loads & Resources – All SLP ......................................................... III-4
PART IV – ECONOMICAL ANALYSIS OF PREFERRED OPTIONS
IV-1
Probability Distributions for the Lower Evaluated Resource Portfolios ....................IV-3
IV-2
Total Annual Costs for the 50MW Coal Case & the LMS100 Case ..........................IV-4
IV-3
Probable Net Present Values with Coal in 2020 Case ................................................IV-5
IV-4
RPU Balance of Loads & Resources 45216 LMS100-50 Coal ..................................IV-6
Rochester Public Utilities
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Table of Contents
IV-5
Approximate 2030 Energy Resources for RPU ..........................................................IV-6
PART V – DEMAND SIDE MANAGEMENT & RENEWABLE OPTIONS
V-1
Maximum RPU System Peak Day – Photovoltaic Study Data...................................V-16
V-2
Maximum Solar Array Day – Photovoltaic Study Data .............................................V-17
V-3
Comparison of Base & Revised Forecasts with DSM & Renewable Impacts............V-22
V-4
Impact of DSM & Renewables on Lowest Evaluated Traditional Resource Plan –
Balance of Loads & Resources ...........................................................................V-23
PART VI – FINANCIAL FORECAST
VI-1
Retail $/MWH-Major Customer Classes ....................................................................VI-7
VI-2
Average Annual Bill-Major Customer Classes...........................................................VI-8
VI-3
Percentage of Annual Retail Rate Increases ...............................................................VI-9
Rochester Public Utilities
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Summary
Summary
The management of Rochester Public Utilities (RPU) is interested in developing a long
range baseline infrastructure plan for the utility. The growth of the customer load will
require acquisition of additional generation resources, potential modifications of existing
resources and upgrades to the utility’s local and the region’s transmission systems. These
projects will be competing for capital from the RPU. In order to minimize the investment
in these areas, a long range plan is needed which provides a coordinated approach to
resource expansion.
The approach taken by RPU was to develop a multi-phased approach to understanding
these needs. The various phases include:
•
•
•
•
Environmental modifications necessary at the Silver Lake Plant (SLP),
Transmission upgrade studies for regional improvements,
Review of traditional resource expansion alternatives,
Review of demand side management and renewable alternatives.
This report provides information on the traditional generation resource planning
undertaken to provide a baseline for comparing the demand side management (DSM) and
renewable options and understanding how RPU intends to use the transmission system.
Being a municipal utility, RPU is responsible to the citizens of Rochester, who are the
customers it serves. In order to understand the issues of importance to its customers,
RPU has periodic customer satisfaction surveys performed. According to customer
satisfaction research conducted by Morgan Marketing in 2001, keeping the price for
electricity as low as possible and aggressively pursuing energy conservation and
renewable generation strategies were ranked in order as the highest needs among 18
performance attributes.
The development of this plan recognizes those needs. Phase I herein reviewed the needs
and traditional approaches to meeting the resource needs of RPU’s customers in a low
cost manner in accordance with reliability standards in the industry. It established a
baseline from which to measure potential impacts of renewable energy sources and
customer modifications to consumption. The Phase II effort reviewed conservation,
demand side management and renewable options to be integrated into the RPU system
which could reduce or eliminate the need for the addition of the traditional resources.
The development of the long range baseline infrastructure plan (Plan) will incorporate
aspects of an integrated resource plan and a financial plan for the utility. Issues which
the Plan will cover include, but are not limited to:
•
•
•
•
Basic generation and transmission resource expansion, including additional
internal generation and participation in regional generation;
Consideration of the renewable portfolio requirements of Minnesota;
Demand side management, customer involvement in managing loads;
Estimated costs for the utility and financial model development.
Rochester Public Utilities
S-1
Burns & McDonnell
Summary
The analysis required to support the decisions on the traditional resource options is the
subject of Parts II, III and IV in this report. The assessment of renewable and demand
side management issues is the subject of Part V. Part VI is a discussion of the detailed
financial forecast for a variety of futures. RPU retained Burns & McDonnell to assist
RPU in the development of the Plan. The first effort was to analyze the power supply
needs to the 2030 time frame in order to identify any longer term issues which could
impact shorter term decisions.
The review of these issues was divided into two major time periods. The periods were
from 2005 to 2015 and from 2016 to 2030. These time frames were developed to
coincide with the termination of the Minnesota Municipal Power Agency (MMPA) sales
contract, at which time the RPU will regain the complete output of the SLP for its own
use.
Current Conditions
Generation Resources
RPU projected the demand and energy growth for the study horizon to be 2.7 percent.
This compares to an historic growth of 3.5 percent for the past 15 years. It is expected
that the RPU load factor will remain relatively constant over the study horizon.
The capacity and energy resources for RPU include:
•
•
•
•
Contract with Southern Minnesota Municipal Power Agency (SMMPA),
Combustion Turbines at Cascade Creek,
Steam units at the Silver Lake Power Plant,
Zumbro Hydro Facility.
The available capacity and load forecast are shown in Figure S-1. The figure also
includes the 15 percent reserve margin required by Mid-Continent Area Power Pool
(MAPP) on RPU load above the Contract Rate of Demands (CROD).
The SLP has two contracts for energy sales. The MMPA contract provides for electrical
sales to the MMPA when the units are available. The contract has various options for
RPU to reduce the amount of capacity offered to MMPA. These options to adjust
capacity allocated to MMPA under the contract are available in 2005 and 2010. The
above balance of loads and resources reflect the current thinking of RPU on the amount
of capacity which will be available to RPU from the contract.
Steam sales to the Franklin Heating Station were scheduled to begin in 2004. The steam
sales are not anticipated to limit the electrical output of the SLP steam generators until
after the 2010 time frame. These reductions in electric capacity have been accounted for
in the balance of loads and resources.
Rochester Public Utilities
S-2
Burns & McDonnell
Summary
Figure S-1
RPU Balance of Loads and Resources
2004-2030
600
500
400
MW
Silver Lake Plant
300
Cascade Creek Gas Turbine Capacity
200
100
SMMPA Contract
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
06
20
05
20
04
0
SMMPA
Hydro
CCreek1
CCreek2
SLP
Peak Load Forecast
Peak +15%
RPU recently completed a study on the environmental aspects of the SLP with regard to
existing and potential environmental regulations. It is expected that the RPU will need to
make investments in additional emission controls or implement other emission reduction
strategies within the next 5 years. Various options are currently under consideration by
RPU. Estimated impacts to the SLP have been considered in this study using the results
of the environmental report “Analysis of Existing and Potential Regulatory Requirements
and Emission Control Options for the Silver lake Plant”. In addition to issues at the
SLP, RPU considers the long term availability of the Cascade Creek Unit 1 to be in
question due to parts availability.
Transmission
RPU is undertaking studies with regional utilities to assess options for reducing the
constraints into the southeast Minnesota region and Rochester. Several transmission
projects are being considered which will affect the 161kV and 345kV systems in the
region.
Rochester Public Utilities
S-3
Burns & McDonnell
Summary
The development of a project to increase the transfer capacity into the RPU service
territory is important to allow RPU to rely on the firm delivery of its CROD amount.
Current transmission limitations do not allow the full CROD capacity to be delivered on a
firm basis. It is also desirable through the development of a project to have increased
transfer capacity for importation of market power or participation in regional projects,
such as for a coal or wind resource, on a firm basis.
Use of local generation is becoming more of an issue as area loads increase and the
capability of the transmission system becomes more limited. Due to must run issues
during portions of the year and contract requirements of MMPA, the SLP is required to
remain operational for the foreseeable future. The current limitations on the transmission
system being below the level required to support the RPU load from outside resources
point out the importance of generation internal to the RPU service area.
Resource Options
The capacity requirements for RPU were reviewed with various futures for the SLP. The
futures for the SLP included retirement of the entire plant, maintaining only Unit 4 and
maintaining all existing units. The analysis assumed retirement of the existing Cascade
Creek Unit 1 in 2015. The capacity needs are summarized in Table S-1.
Table S-1
Range of Capacity Requirements for Various SLP Retirement Scenarios
(MW of Capacity Deficiency)
All Units in Service
Retire CC Unit 1
Retire CC1, SLP 1-3
Retire CC1, SLP 1-4
2016
8
36
83
128
2020
56
84
131
176
2025
123
151
198
243
2030
201
229
276
321
Expansion alternatives were developed to review various scenarios to eliminate the
deficits. These scenarios included various combinations of participation in a regional
coal-fired power plant and RPU constructed resources such as combined cycle and simple
cycle generation. The scenarios considered for RPU are included in Table S-2.
Rochester Public Utilities
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Burns & McDonnell
Summary
Table S-2
Resource Portfolios
Case
None216-100Coal
None216-50Coal
None216-100CC
None216-LMS100
None216-SC
45216-50Coal_CoalFirst
45216-50Coal_SLPfirst
45216-100CC
45216-LMS100
45216-SC
45216-LMS100-50Coal
All216-50Coal_CoalFirst
All216-50Coal_SLPfirst
All216-100CC
All216-LMS100
All216-SC
Existing Capacity - MW
CROD
Other
SLP
216
51
0
51
0
216
51
0
216
216
51
0
216
51
0
216
51
45
51
45
216
51
45
216
51
45
216
51
45
216
216
51
45
216
51
92
216
51
92
216
51
92
216
51
92
216
51
92
Coal
100(15)
50(15)
50(15)
50(15)
50(20
50(15)
50(15)
Capacity Added – MW (year installed)
Combined Cycle
Twin Pac
50(15)
50(20)
100(15)
50(20)
100(15)
50(15)
50(20)
100(15)
50(15)
50(20)
150(15)
50(20)
50(15)
50(20)
50(15)
50(20)
100(15)
50(20)
100(15)
50(20)
100(15)
50(20)
100(15)
50(20)
50(20)
100(20)
50(20)
100(20)
50(20)
50(15)
50(20)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
The case titles are developed such that the None, 45 or All refers to the amount of SLP
capacity available, 216 refers to the CROD amount and the last numbers refer to the MW
of resource added. SC refers to simple cycle, CC refers to combine cycle, and LMS 100
refers to a new simple cycle unit being developed. References to CoalFirst and SLPFirst
are associated with the order of dispatch.
The simple cycle units considered in this study are based on the current Cascade Creek
Unit 2 type facility, the Pratt and Whitney Twin Pac. The combined cycle unit is based
on a purchase of a 125MW portion of an area combined cycle project. The coal
resources are assumed to be from a regional project whereby RPU would purchase the
indicated amount as an owner.
Production cost analysis was performed to determine the amount of energy that each
resource would provide over the period 2016 to 2030. Table S-3 provides a summary of
the gas and coal energy assumed in the analysis.
Table S-3
Summary of Energy Sources from Gas or Coal Portfolios
2016
Energy in GWh
2020
2025
2030
Gas
3
36
121
Coal
1,839
1,806
1,721
Gas
21
79
248
Coal
2,023
1,965
1,796
Gas
72
187
479
Coal
2,257
2,142
1,850
Gas
171
423
773
Coal
2,490
2,238
1,888
45216-Coal
45216-Gas
4
34
1,838
1,808
25
93
2,019
1,951
79
243
2,250
2,086
187
536
2,474
2,125
All216-Coal
All216-Gas
4
34
1,838
1,808
25
93
2,019
1,951
79
243
2,250
2,086
187
536
2,474
2,125
None216-100Coal
None216-50Coal
None216-Gas
Note: Above numbers do not include a negligible amount of hydro energy
Rochester Public Utilities
S-5
Burns & McDonnell
Summary
The above table reflects the energy estimated to be taken from the various generation
resources within the respective expansion portfolios. The energy in the gas columns
includes energy generated by RPU and purchased from the market. The coal energy
includes that purchased from SMMPA and generated by RPU. As seen, where the coal
energy is limited to the existing resources, significant increases in the gas energy is
necessary. It should be noted that all of the cases include additional gas-fired resources.
Results
The results of the production cost modeling for the traditional portfolios are summarized
in Table S-4. The net present values for the cases were developed for the 15 year study
horizon in 2015 dollars. The values shown reflect the incremental costs of each option
and, therefore, do not include those RPU costs which would be common among all of the
cases.
Table S-4
Summary of Net Present Values for Portfolio Options
(2015 $000)
Case
45216-LMS100-50Coal
45216-LMS100
45216-50Coal_CoalFirst
All216-50Coal_CoalFirst
45216-50Coal_SLPfirst
All216-50Coal_SLPfirst
None216-50Coal
All216-LMS100
45216-SC
All216-SC
None216-100Coal
None216-LMS100
None216-SC
All216-100CC
45216-100CC
None216-100CC
NPV
$288,674
$320,892
$325,782
$327,201
$328,750
$330,169
$342,102
$347,789
$347,544
$351,098
$353,725
$362,430
$387,146
$389,434
$396,788
$435,755
% Above Base
11.2%
12.9%
13.3%
13.9%
14.4%
18.5%
20.5%
20.4%
21.6%
22.5%
25.5%
34.1%
34.9%
37.5%
51.0%
The above portfolios all have a mixture of coal and natural gas resources used to
minimize RPU’s overall average energy costs. The results indicate that the availability of
low cost energy from the SLP Unit 4 or an additional coal plant purchase is a lower cost
scenario than relying only on natural gas for the energy needs above the CROD level.
Risk analysis of the lower evaluated cases was performed. The analysis varied certain
assumptions, such as fuel forecast, capital costs, interest rates and other factors. The
results are summarized in Figure S-2. The curves show the distribution of probable net
present values with the changes in assumptions for the various cases. A higher probability
of a net present value indicates reduced risk in that scenario.
Rochester Public Utilities
S-6
Burns & McDonnell
Summary
Figure S-2
Probable Net Present Values
Lower Evaluated Cases
Probability Distribution of Net Present Values
Rochester Public Utilities
2.5
2.0
45216-50coal_coalfirst
Mean = $327,037
45216-LMS100-50Coal
Mean = $290,082
Probability (0.01%)
All216-50coal_coalfirst
Mean = $328,581
1.5
All216-50coal_SLPfirst
Mean = $331,568
45216-50coal_SLPfirst
Mean = $330,067
1.0
None216-50coal
Mean = $342,826
0.5
All216-LMS100
Mean = $347,416
0.0
200
250
300
350
400
450
500
NPV of Costs ($Millions)
The risk analysis shown above indicates that combining the benefits of the LMS100 case
with the 50MW coal case provides a lower risk case than the all gas cases. The major
advantage is the delay of acquisition of the coal unit until its energy can be more fully
utilized. This allows RPU to capture the early benefits of the LMS100 portfolio and the
later benefits of the 50MW coal portfolios. Therefore, the sequencing of the unit
additions should be considered with the gas unit in 2016 and the coal purchase in 2020.
Demand Side Management and Renewable Options
RPU is active in promoting demand side programs to its customers to help conserve
electric energy, and reduce demand in its service territory. Numerous programs are
offered to assist customers in reducing their electrical requirements. The development of
the financial plan for RPU requires the assessment of the impacts that customers are
making, and could make, in the reduction of future electrical requirements; therefore,
delaying the need for additional capacity.
Rochester Public Utilities
S-7
Burns & McDonnell
Summary
Current DSM Efforts
Utilities in Minnesota are required to invest a portion of the revenues into DSM
programs. For RPU, this amounts to approximately $1,300,000 per year. RPU has
created a department to manage the budget associated with DSM programs. The
department is staffed with individuals who work with customers to promote the various
DSM programs in place, provide energy audit services, and look for new programs to
implement.
RPU is working with the cities of Owatonna and Austin, Minnesota on DSM offerings.
These utilities have formed the Triad, which allows the cities to share personnel, study
costs, and other assets in order to reduce the overheads and program costs associated with
the DSM programs.
The programs offered by RPU include:
• Conserve and $ave – a program to promote the use of Energy Star appliances and
other high-efficiency equipment in place of lower efficiency options. The
program is open to residential, commercial, and industrial customers. Rebates are
provided for a variety of appliances, equipment, and lighting options.
• Partners Load Management – a program to allow RPU to control central air
conditioner compressors and electric water heaters during times of high demand
and reduce the load on the system.
• Energy Audits – these are provided to customers upon request.
The cumulative estimated reductions due to these programs as of January 1, 2004 are:
• Energy savings of 7,860 MWh.
• Demand savings of 5,960 kW.
Using an average of $600/kW of installed capacity and $55 per MWh as an avoided
energy cost, the programs have provided approximately $3,500,000 of reduced
investment cost and $432,000 of annual energy savings.
Study Approach
A variety of tasks were undertaken to develop the expected impacts that current and
potential DSM programs could provide in reducing the RPU need for additional power
supply resources. These tasks included an end use survey of RPU’s customers, a benefit
cost analysis of RPU programs, and an estimation of the electric energy and demand
reduction potential for RPU’s customer base.
In addition to these tasks, public involvement was solicited to discuss options and
considerations from the ratepayer’s perspective. RPU developed a task force made up of
a representative from the various rate classes and other involved citizens served by RPU.
The results of these efforts are more fully described in Part V. Table S-5 provides a
summary of the estimated energy impacts due to expanded DSM programs that were
considered likely for RPU. Discussions with the RPU DSM staff and management
resulted in revisions to the forecast used to develop the traditional resource plan.
Rochester Public Utilities
S-8
Burns & McDonnell
Summary
Table S-5
Estimated Additional DSM and Efficiency Impacts
To RPU Energy Forecast
Program
Residential
Central AC
Blower Motors
CFLs
Refrigerators
Gas switched appliances
Commercial
Central Air more than 7 years old
No Compact FL
Non electronic ballast flourescent
VSD on 3 HP AC unit fans
Computers
Printers
Copiers
Gas switched appliances
Total
Cumulative Total
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
0
0
0
0
0
236
692
63
42
83
475
1,391
127
84
168
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
0
0
0
0
0
0
0
0
123
185
517
658
122
43
55
250
248
373
1,040
1,322
245
86
111
503
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
0
0
3,069
3,069
6,170
9,239
9,208
18,447
9,208
27,656
9,208
36,864
9,208
46,073
9,208
55,281
9,208
64,489
9,208
73,698
9,208
82,906
The estimated demand and energy impacts, including the Mayo cogeneration project, are
shown in Table S-6. The Original Energy Forecast was the energy projection used for
developing the resource plan described above. The Existing DSM Impacts include the
existing RPU DSM program estimated savings. The Future DSM impacts are one half of
the saving shown in Table S-5. The Revised Energy Forecast is determined by
subtracting the Future and Existing DSM Impacts from the Original Energy Forecast.
The Aggressive Energy Forecast includes the remainder of the savings estimated in Table
S-5.
Table S-6
Estimated DSM and Efficiency Improvement Impacts
Demand (MW) and Energy (MWh)
Year
Annual
Peak
Demand
Adjustments
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
277
284
292
300
308
316
325
334
343
352
362
16.6
21.8
23.1
25.1
25.3
26.9
29.2
31.8
34.9
38.4
42.8
Rochester Public Utilities
Adjusted
annual Original Energy
Peak
Forecast
260
262
269
275
283
289
296
302
308
314
319
1,377,767
1,414,967
1,453,171
1,495,732
1,532,702
1,574,085
1,616,585
1,663,932
1,705,059
1,751,096
1,798,375
S-9
Future
DSM
Impacts
Existing
DSM
Impacts
Revised
Energy
Forecast
0
1,535
4,620
9,224
13,828
18,432
23,036
27,641
32,245
36,849
41,453
8,590
56,310
64,550
72,650
80,650
88,500
96,210
103,790
111,150
118,450
125,770
1,369,177
1,357,122
1,384,001
1,413,858
1,438,224
1,467,153
1,497,339
1,532,501
1,561,664
1,595,797
1,631,152
Aggressive
Energy
Forecast
1,369,177
1,355,588
1,379,382
1,404,635
1,424,396
1,448,721
1,474,302
1,504,861
1,529,420
1,558,948
1,589,699
Burns & McDonnell
Summary
Renewable Energy Options
The state of Minnesota has implemented requirements for renewable energy under
Minnesota Statute 2003 Chapter 216B. Retail electric utilities must offer customers an
opportunity to purchase, at cost, renewable energy beginning July 1, 2002. RPU is
offering customers the opportunity to purchase this energy under its Wind Power
program in association with SMMPA.
Utilities are required to generate or procure renewable energy sufficient to ensure that by
2005, 1 percent of total retail sales are from renewable energy. This “Renewable Energy
Objective” (REO) ramps up by 1 percent each year until 2015 when a total of 10 percent
of retail sales must be from renewable energy. The REO also requires that, of the
renewable generation required, in 2005 at least 0.5 percent be from biomass energy
technology, increasing to 1.0 percent by 2010. For RPU, the retail sales energy above the
CROD from SMMPA would be subject to RPU compliance with the REO.
The integration of this energy into RPU’s resource mix will require adjustments to the
dispatch determined in the traditional resource portfolios identified above.
There are several renewable energy options in commercial use. The most often
considered include solar, wind, and biomass. In addition, the REO allows the use of
electricity generated using municipal solid waste and existing hydro-electric generation to
count towards the renewable requirement. The application of these options requires an
assessment of their energy production capabilities, resultant power costs and the benefit
to the RPU requirements. A more detailed discussion of renewable options can be found
in Part V.
The Olmstead Waste to Energy Facility (OWEF) qualifies as biomass renewable energy
under the Statute. Since utilities are to provide 1 percent of their energy from biomass, it
could satisfy the RPU biomass renewable requirements through the study period. When
combined with the Zumbro River hydro facility total renewable requirements could be
satisfied until approximately 2027. Table S-7 provides an assumed purchase scenario.
Due to the requirement in the REO of obtaining energy from biomass, the output of the
OWEF will be required beginning in 2005.
Rochester Public Utilities
S-10
Burns & McDonnell
Summary
Table S-7
RPU Estimated Annual Renewable Energy Requirements (MWh)
Available from OWEF
Year
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Renewable
Requirement (10%)
7,059
8,230
9,628
11,243
13,411
15,942
19,008
22,485
26,446
30,570
34,949
39,614
44,543
49,634
54,980
From
Biomass
71
82
96
112
134
159
190
225
264
306
349
396
445
496
550
1.9MW @
75%CF
12,483
12,483
12,483
12,483
12,483
12,483
12,483
5MW @
75%CF
32,850
32,850
32,850
32,850
32,850
32,850
32,850
32,850
From
Zumbro
River
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
Total
Hydro &
Biomass
21,483
21,483
21,483
21,483
21,483
21,483
21,483
41,850
41,850
41,850
41,850
41,850
41,850
41,850
41,850
Note: All energy values in MWh
DSM and Renewable Impacts on RPU Supply Needs
The balance of loads and resources using the DSM and renewable impacts was modified
to include the above forecasts. The resulting impacts are shown in Figure S-3.
Rochester Public Utilities
S-11
Burns & McDonnell
Summary
Figure S-3
Comparison of Base and Revised Forecasts
With DSM and Renewable Impacts
Forecast Comparisons
SMMPA
RPU Resources
Uncontrolled Demand
Phase I Forecast
DSM Impact
DSM + Renewables
600
500
400
MW
300
200
100
0
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
The impacts to the forecast indicate that the projected impacts of DSM and renewables do
not delay the year when RPU becomes capacity deficit, however, they substantially
reduce the amount of capacity needed. In addition, they delay the need for additional
capacity in the future. Figure S-4 is the balance of loads and resources of the
recommended traditional resource plan. As shown, the impact of the DSM and
renewables on the forecast allows a delay in the installation of the LMS-100 combustion
turbine by about 2 - 3 years. The impacts also allow a delay in the need for the coal unit
by a similar period.
Rochester Public Utilities
S-12
Burns & McDonnell
Summary
Figure S-4
Impact of DSM and Renewables
On Lowest Evaluated Traditional Resource Plan
Balance of Loads and Resources
700
600
500
MW
400
300
200
100
5
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
3
4
20
1
20
1
20
1
1
0
9
2
20
1
20
1
20
1
8
20
0
20
0
6
5
7
20
0
20
0
20
0
20
0
4
0
Hydro
SMMPA CROD
SLP
New Coal
LMS100 CT
Existing CT
New CT
Peak Forecast
Peak +15%
DSM+Ren
Financial Analysis
The results of the resource planning, demand side management and renewable
assessments were reviewed on an incremental cost approach to determine lower
evaluated options. In order to bring these options together to determine the
recommended RPU future, a financial forecast model was developed by RPU to
incorporate the total costs of RPU. This model allowed a complete evaluation of future
costs, the impact to average rates and other financial factors of interest to RPU.
The financial model was used to analyze the following futures:
• The recommended traditional resource expansion plan from Part IV with the
forecast unaffected by demand side management,
• The recommended plan adjusted by using the normal demand side management
forecast with SLP operating on coal and adjustments to the new resources,
Rochester Public Utilities
S-13
Burns & McDonnell
Summary
•
•
•
The recommended plan adjusted by using the normal demand side management
forecast with SLP operating on natural gas and the coal unit replaced with gasfired capacity,
The recommended plan adjusted by using the aggressive demand side
management results with SLP operating on coal and adjustments to the new
resources,
The recommended plan adjusted by using the aggressive demand side
management results with SLP operating on natural gas and the coal unit replaced
with gas-fired capacity.
A complete discussion of assumptions and methodology can be found in Part VI.
A variety of assumptions were made to the financial model. The main driver for the
model is the energy and demand forecast. The load forecast was used to derive estimates
for a variety of other assumptions, such as:
•
•
•
•
•
•
Energy dispatch from RPU sources, including market sources, above the SMMPA
supplied energy,
Generation fuel expense,
Purchased power expense for energy, capacity, and transmission,
Administrative and general costs,
Distribution and substation additions,
Retail revenue forecasts.
Forecasts for investment in other projects, such as for transmission upgrades, capital
investments in plant, and other improvements were provided by the respective operating
divisions of RPU. The Silver Lake Plant was assumed to have the recommended
environmental modifications from the Utility Engineering report “Rochester Public
Utilities Emissions Control Feasibility Study, Silver Lake Plant,” Dec 2004 in the futures
with coal. The budgets for the demand side management and marketing programs were
included based on the level of DSM considered in the forecast.
The list of input assumptions is included in Appendix V.
The financial model uses the energy forecast and estimated energy price from the
resources available to determine the amount of energy derived from each source. If the
load level is at or below the 216MW level of the SMMPA contract, then the energy is
assumed to come from SMMPA. If the load is above the 216MW level, then the lowest
cost resource is dispatched to provide the energy with the exception that small load
increments were dispatched first from peaking units until the point where the increment
was high enough to feasibly dispatch baseload generation.
The economic impacts of resource additions were determined based on the estimated
capital, fixed and variable operating and maintenance costs. The targeted financial goals
for debt service coverage ratios, average cash balances and other targets based on capital
Rochester Public Utilities
S-14
Burns & McDonnell
Summary
investments were included. In-service years and the amount of capacity added were
adjusted in the futures with demand side management included to reflect the benefits to
delays in and amounts of capital investment.
Estimates of purchases from the market were made using a forecast market demand and
energy price. For certain years, market capacity was purchased on a seasonal basis to
provide the necessary capacity shortfall rather than install a new resource. Also, when
market energy was estimated to be lower cost than an RPU resource’s energy cost, the
market was used to provide the energy.
The operation of the SLP to meet wholesale energy and steam production contract
obligations was modeled. The operations included estimated energy and steam
production based on current discussions with counter parties to the contracts.
The operation and capital budgets of each RPU division were incorporated to provide a
complete financial picture of the utility. The revenue requirements were then used to
determine the amount of adjustment to rates necessary to meet those requirements.
Average impact to retail rates and customer average bills were also estimated. The model
covers a thirty year time period from 2005 to 2034.
Externalities
The values of externalities were included in this analysis. The 2003 values of
externalities used by the Minnesota Public Utilities Commission (Rural) for utilities to
evaluate externalities were adjusted for the gross domestic price inflator (4.4%) for 2004.
A midpoint range for the adjusted values was selected for use in the analysis.
The emissions from the resources considered in the financial model were placed on a
dollar per MWh basis for use with the expected dispatch MWh determined from the
financial model. Externalities on contract and market purchases were also included to
reflect one half of the purchases from new coal units and one half from combined cycle
gas units.
Renewable energy from the Zumbro River facility was included in the financial model as
the primary renewable resource, wind energy under the SMMPA program included at its
historical average, and with OWEF assumed to be the biomass resource.
Results
Resource Plan
The reduction in the demand and energy forecast with the DSM impacts provides an
opportunity to delay the gas resource considered for 2016 and the in service year and
amount of capacity for the coal resource considered in 2020. In the financial model, the
combustion turbine considered for installation in 2016 was delayed two years and the
coal unit was reduced to 25MW and its in service date delayed to 2025.
Rochester Public Utilities
S-15
Burns & McDonnell
Summary
Rates
Figures S-5 and S-6 provide the results based on average retail rate impacts and average
customer bills. As seen, there are significant advantages in the demand side management
impacts on both rates and average bills. When considering the cost impacts due to the
futures with and without coal, it is seen that the coal case provides economic benefits.
The rate impacts determined from the analyses indicate that RPU, in any of the futures, is
expected to need rate increases of from 1 to 3 percent in almost each year of the
assessment. The differences in the expected and aggressive demand side management
scenarios were not significant. The more detailed results of the financial model analyses
are included in Part VI and Appendix V.
Rochester Public Utilities
S-16
Burns & McDonnell
Figure S-5
Retail $/MWH-Major Customer Classes
$140
$120
Coal/Gas Mix
All Gas
No DSM
$100
$80
$/MWH
$60
$40
$20
$0
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033
Year
S-17
Figure S-6
Average Annual Bill-Major Customer Classes
$6,000
$5,000
Coal/Gas Mix
All Gas
No DSM
$4,000
Dollars
$3,000
$2,000
$1,000
$0
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033
Year
S-18
Summary
Emissions
The emissions from each of the futures were considered from both absolute tons per
externality and the cost aspect using the Minnesota value for externalities. Table S-8
provides the summary of tons emitted by externality based on the energy dispatch used for
the RPU retail resource future over the thirty years of the analysis. As shown, there is a
substantial advantage to the demand side reductions. The costs of the externalities and the
total costs of the specific future are included in Table S-9.
Table S-8
Total Tons of Emissions by Scenario
Scenario
Original Forecast
Normal DSM Coal & Gas
Normal DSM All Gas
Aggressive DSM Coal & Gas
Aggressive DSM All Gas
SO2
7,808
5,228
379
4,931
343
Nox
4,587
3,105
5,086
2,886
4,714
PM10
770
485
296
448
272
Pb
1.25
0.79
0.10
0.73
0.09
CO
9,811
7,048
8,341
6,504
7,644
CO2
10,472,370
6,263,420
3,784,419
5,720,385
3,474,437
Table S-9
Retail Portion of RPU Costs of Various Plans with Externalities
(2004$ 000’s)
Scenario
Original Forecast
Normal DSM Coal & Gas
Normal DSM All Gas
Aggressive DSM Coal & Gas
Aggressive DSM All Gas
Retail Revenue
$ 5,649,613
$ 5,134,851
$ 5,672,269
$ 5,104,864
$ 5,569,761
Externalities
$22,308
$13,390
$ 8,325
$12,236
$ 7,646
$
$
$
$
$
Total
5,671,921
5,148,241
5,680,594
5,117,100
5,577,408
Summary
Overall, RPU is in relatively good condition to meet its load requirements for several years
without any additions to its resource mix. Challenges to RPU in the area of transmission
reliability and understanding what future market operation impacts will bring are typical of
the environment in which utilities operate today and will be a primary focus of RPU. The
transmission issues confronting RPU may require additional internal generation to maintain
reliability within the RPU service territory prior to when units would be needed to serve
load growth. Plant related issues will include the investment necessary to bring the SLP
into compliance with environmental regulations currently taking affect. Based on the
analysis performed for RPU in this effort, Burns & McDonnell offers the following
conclusions and recommendations.
Rochester Public Utilities
S-19
Burns & McDonnell
Summary
Conclusions
Based on the analysis performed for this study, Burns & McDonnell has developed the
following conclusions:
1. The uncertainty surrounding the conversion of the electricity wholesale market in
the RPU region from its traditional operation to its new operation under MISO and
the existing transmission limitations for importing power into the RPU area makes
it necessary for RPU to continue to have capacity available within its service area
for reliability and economic purposes.
2. The use of traditional resources to meet the RPU capacity obligations is lower cost
than the use of wind or solar equivalent capacity. Energy costs from certain
renewable options can be attractive when compared to the energy costs from coal,
gas, or market resources.
3. The impacts of demand side management allow RPU to delay and reduce the
amount of capacity required when compared to the forecast without significant
demand side management effects included.
4. The future evaluated with coal and gas energy and aggressive demand side
management was the only future that provided both lower average rates and lower
average total bills when compared to the other futures. This ranking is not changed
with the inclusion of externalities.
5. The emissions from the aggressive demand side management future with coal and
gas are approximately one-half of the emissions from the traditional resource future.
6. Considering the load forecast, RPU has several years before it is in a capacity
deficit condition due to load needs. Estimates of DSM and renewable impacts to
the forecast provide the opportunity for RPU to delay the installation of resources
by two to three years, depending on the successful acceptance of the DSM
programs by the RPU customers.
7. The development of the MISO Day 2 market will make day ahead pricing more
predictable and potentially provide RPU with the opportunity to engage customers
in demand adjustments based on the cost of energy. The current Partners program
could see a decrease in the number of MW under control due to more efficient air
conditioners being installed on the system and potential fuel switching of water
heaters. These two developments are an indication that RPU should consider
realigning its approach to demand reductions on the customer side of the meter.
Because of this need, RPU should prepare a pilot program for implementation of
demand response type programs across the residential, commercial and industrial
classes in order to gain experience and begin shifting away from the direct control
programs to market based programs.
8. RPU’s renewable obligations under the Minnesota Statute Chapter 216B can be met
for several years through purchase of energy from the OWEF and the Zumbro River
hydro facility. If the OWEF facility is expanded, as is being considered, RPU
renewable energy requirements could be satisfied until approximately 2027 with
these two resources.
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Burns & McDonnell
Summary
9. Discussions with the OWEF should proceed to determine if additional output is
available. If it is not, then wind energy should be pursued as the next renewable
option to satisfy energy obligations under the REO. Based on the cost and output of
photovoltaic units, solar photovoltaic is the most expensive renewable option for
the RPU to pursue.
10. Based on information from RPU, the SMMPA is in discussions on acquisition of
additional resources which could affect the cost of capacity and energy under the
CROD. At the current time, there is insufficient information to be able to determine
how DSM programs could reduce the impact of these potential costs. If SMMPA
moves ahead with resource acquisitions based on RPU impacts to the SMMPA
resource mix, RPU should discuss with SMMPA the ability of DSM options to
reduce the resource need impacts to SMMPA.
Recommendations
Based on the analysis performed for RPU in this effort, Burns & McDonnell is of the
opinion that RPU should:
Over the next few months:
1. Minimize its involvement in reviewing participation in regional coal projects.
RPU is not in need of additional coal capacity with the current 216MW CROD
level and load forecast until approximately 2020. Therefore, participation in any
coal plant currently being developed does not appear to be advantageous.
2. Pursue firming up the transmission system to allow firm delivery of the CROD
amount of 216MW.
3. Improved transmission import capability should be reviewed with area utilities to
allow increased access to market capacity. Although the resource plans
presented in this study anticipate future resource additions, there is also
continued reliance on market purchases to meet future load growth.
4. Consider taking options on approximately 100 acres of land within the RPU
service territory near a high pressure gas line and transmission facilities under
RPU control for installation of future combustion turbine capacity.
5. Develop a parallel path project to accelerate installation of combustion turbine
capacity required in the long term plan to maintain system reliability should the
selected transmission upgrade project be delayed.
6. Develop the upgrade plan and timing for SLP Units 1-4 for the addition of
emission controls and other life extension modifications.
7. RPU should monitor the operations of the MISO Day 2 market to determine how
to participate in the market over the next few months.
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Burns & McDonnell
Summary
Between 2005 and 2015:
1. RPU should continue to design and market DSM programs to achieve the levels
of forecast reductions for demand and energy. Periodic comparison of actual
results to those forecasts should be made to determine if adjustments in the
forecast results are necessary.
2. RPU should take advantage of renewable energy from the Zumbro River
resource to the full extent of its output. The renewable energy from the OWEF
should be considered to provide the RPU biomass energy requirements.
Purchases above the requirements should be compared to the cost of other
energy available.
3. Complete the transmission upgrade or the installation of additional combustion
turbines to maintain system reliability.
4. If the transmission upgrade is completed, compare the market conditions at the
time to the installation of additional generation resources within the service
territory.
5. Review the then current generation technology, fuel options and RPU needs
against the long range plan developed herein to determine if new technologies or
reduced RPU needs have usurped the analysis and recommendations associated
with current options.
6. Complete the modifications to the SLP Unit 4. Initiate the emission controls to
be applied to Units 1-3 in light of their expected operation.
7. Around 2014, assuming that new generation is required in accordance with the
long range plan and that generation has not been installed in connection with the
transmission issue, begin the process for installation of approximately 50 to
100MW of natural gas-fired generation for an in service date of 2018. The
generation should be low capital cost with as low an operating cost as is
consistent with expected operating capacity factors.
Between 2015 and 2030:
1. Install generation as necessary and prudent using the long range plan prepared
above as a guide and comparing the assumptions used herein to the existing
market conditions and resultant DSM impacts to the RPU needs. The generation
additions should follow the in service schedule identified in portfolio 45216LMS100-50Coal as modified by DSM results.
2. Around 2015, depending on the status of the RPU system needs, the regional
market for base load projects being developed, and other technology
considerations for resource options, RPU should consider taking an option on
approximately 1500 acres to support the development of a coal-fired generation
plant within the RPU service territory. The site should have access to rail,
electric transmission and water infrastructure to support several hundred
megawatts of generation.
Rochester Public Utilities
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Burns & McDonnell
Summary
3. If development of a local coal unit appears likely, purchase the necessary land
and begin the development process around 2017 for an in service date of 2025.
*****
Rochester Public Utilities
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Burns & McDonnell
Part I
Introduction
Part I
Introduction
The management of Rochester Public Utilities (RPU) is interested in developing a
long range baseline infrastructure plan for the utility. The growth of the customer
load will require acquisition of additional generation resources and upgrades in the
utility’s local and the region’s transmission systems. These projects will be
competing for capital from the RPU. In order to minimize the investment in these
areas, a long range plan is needed which provides a coordinated approach to resource
expansion.
The RPU is confronted with numerous decisions associated with its power supply
resources. Several of these decisions will need to be made in the next several
months. The outcome of these decisions could have a significant impact on the
financial requirements of the RPU over the next several years. In order to develop
information about the various futures available to RPU and what the financing
requirements might be for the futures, RPU decided to study how various long term
decisions could impact the near term financing requirements.
The approach taken by RPU was to develop a multi-phased approach to
understanding these needs. The various phases include:
•
•
•
•
Environmental modifications necessary at the Silver Lake Plant
Transmission upgrade studies for regional improvements
Review of traditional resource expansion alternatives
Review of demand side management and renewable alternatives
This report provides information on the traditional generation resource planning
undertaken to provide a baseline for comparing the DSM and renewable options and
understanding how RPU intends to use the transmission system.
Being a municipal utility, RPU is responsible to the citizens of Rochester, who are the
customers it serves. In order to understand the issues of importance to its customers,
RPU has periodic customer satisfaction surveys performed. According to customer
satisfaction research conducted by Morgan Marketing in 2001, keeping the price for
electricity as low as possible and aggressively pursuing energy conservation and
renewable generation strategies were ranked in order as the highest needs among 18
performance attributes. The research included telephone, mail-in and personal
interviewing of residential, commercial and industrial customers.
The development of this plan recognizes those needs. Phase I herein reviewed the
needs and traditional approaches to meeting the resource needs of RPU’s customers
in a low cost manner in accordance with reliability standards in the industry. It
Rochester Public Utilities
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Burns & McDonnell
Part I
Introduction
established a baseline from which to measure potential impacts of renewable energy
sources and customer modifications to consumption. The Phase II effort reviewed
conservation, demand side management and renewable options to be integrated into
the RPU system which could reduce or eliminate the need for the addition of the
traditional resources.
Utility Issues
The utility industry in general and RPU specifically are operating amidst changing
local, regional and national issues which affect utility operations. On the local level,
many of the issues require decisions by local officials who regulate RPU and will
determine the local course of the utility. Regional and national issues are typically
beyond the influence of these officials. These issues are closely watched by RPU and
others and RPU is a participant in the national debates. However, the decision on
what policies to implement on a state, regional or national level is beyond the RPU
control.
The issues which RPU is confronting on the local, regional and national levels
include:
Generation
Local
-
Silver Lake Plant Emissions
Status of local generation in future system needs
Must Run issues required of local generation and emission impacts
System operation changes based on Midwest Independent Transmission
System Operator (MISO) development
Reserves available
Regional and National
-
Status of regional generation
Cost and availability of natural gas as a utility fuel
Availability and value of regional joint generation projects
Implementation of MISO Market Operations
Technology advancements
New emission/operation regulations
The use of local generation is becoming more of an issue as load increases and the
capability of the transmission system becomes more limited. Due to regional
reliability issues during portions of the year and contract requirements of RPU, the
Silver Lake Plant (SLP) may be required to remain operational. The useful life of the
facility and improvements necessary to keep the plant compliant with operating
permits is a concern. A study on the emission improvements recommended for the
plant is being prepared.
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Burns & McDonnell
Part I
Introduction
Transmission and Distribution
Local
- Transmission for firm delivery of Southern Minnesota Municipal Power
Agency (SMMPA) contract rate of delivery
o Maximum import of the transmission system
o Ability to build new transmission facilities outside of Rochester
- Distribution reliability
o New substation and lines will be continually needed as the load grows
o Capital requirements
o Rights of way
- Reserves available
Regional and National
-
Status of regional transmission improvements
Implementation of MISO operations
Technology advancements
New Regulations
The transmission import capacity into RPU is constrained during certain hours of the
year. Capacity has degraded to the point that the firm delivery of the SMMPA
Contract Rate of Delivery (CROD) is being affected.
Load Growth
- Annexation, expansion of RPU service territory impacts capital needs
- Growth rates affect RPU investments
o Local economy
o Mayo Clinic
- Risks of economic development expansion (ie Genomics)
o Overbuild
o Underbuild
- Matching the investment to meet changes in load
The RPU load growth is closely linked to the growth of the Mayo Clinic and other
major employers in the area. Average system growth is projected by the RPU
forecasting group to be approximately 2.7% per year between 2004 and 2030.
Financial and Administrative
Local
- Impact of requirements on the rates
- Impact of Homeland Security regulations and capital needed to meet the needs
- Training and attraction of qualified staff
- RPU productivity due to the time it takes to report and comply with the new
regulations
- Knowledge and communication of the capital dollars needed to:
o Internal stakeholders
o External stakeholders
Rochester Public Utilities
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Burns & McDonnell
Part I
Introduction
Regional and National
- Cost of Borrowing
- Availability of staff versus the need
Long Range Plan
The development of the long range baseline infrastructure plan (Plan) will incorporate
aspects of an integrated resource plan and a financial plan for the utility. Issues
which the Plan will cover include, but are not limited to:
•
•
•
•
Basic generation and transmission resource expansion including addition of
internal resources and participation in regional projects.
Consideration of the renewable portfolio requirements of Minnesota
Demand side management, customer involvement in managing loads
Estimated costs for the utility and financial model development
The RPU is not required to file the Plan with a regulatory agency at the state or
federal level. However, the Plan is organized and includes the basic requirements of
these types of studies performed by state regulated entities.
The analysis required to support these decisions is the subject of this report. RPU
retained Burns & McDonnell to assist the RPU in the development of the Plan. The
first effort was to analyze the power supply needs to the 2030 time frame in order to
identify any longer term issues which could impact shorter term decisions. The major
power supply resource issues which confront RPU include:
•
•
•
•
•
The benefit of the Silver Lake power plant as a long term resource
The investment in the Silver Lake power plant for emission controls
The upgrade of the transmission capability into Rochester to allow firm use of
the purchased capacity and energy
The development of renewable resources to meet Minnesota requirements
The participation in regional coal plants
The review of these issues was divided into two major time periods. The periods
were from 2005 to 2015 and from 2016 to 2030. These time frames were developed
to coincide with the termination of the Minnesota Municipal Power Agency (MMPA)
contract, at which time the RPU will regain the complete output of the SLP for its
own use.
The first period reviewed was from 2016 to 2030. This period allowed a review of
the load growth of RPU compared to the available resources. Various generation
expansion plans were evaluated which included futures with differing amounts of the
SLP available.
The second period reviewed was from 2005 to 2015. This period was reviewed after
the later period to determine what shorter term actions needed to be taken in order to
efficiently invest capital to support RPU’s longer term power supply plan.
Rochester Public Utilities
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Burns & McDonnell
Part I
Introduction
Methodology
The initial effort in the review was for RPU to determine what the major decisions
and future options available to meet its power supply requirements might be. The use
of a decision tree process resulted in identification of the decisions, assumptions and
sequencing of the issues. The development of the analysis required review of the
following issues:
•
•
•
•
•
•
RPU’s projected demand and energy requirements
Status of RPU resources
Sources of energy
Transmission capabilities
Renewable resource requirements in Minnesota
Regional coal-fired generation projects
The review of the power supply alternatives for RPU was performed using a load
forecast prepared by RPU over the study horizon. The forecast was applied to the
hourly load profile of RPU which resulted in an hourly forecast for the entire study
period.
A review of the load growth of RPU and the energy needs of the utility indicated that
the energy available from the SMMPA would approach its maximum utilization in
the 2010 to 2015 time frame. Resource planning is needed to determine the future
requirements of the utility considering various scenarios for the MMPA contract, the
contract for steam sales to the Mayo clinic, improvement of the transmission system
and the future of the SLP.
Burns & McDonnell reviewed the projected demand and energy needs of RPU.
These needs were compared to the existing sources, which allowed the resource needs
of RPU to be identified. The development of these items allowed expansion plans to
be created. These plans were reviewed using an hourly costing model which allowed
each expansion alternative to be evaluated for fixed and variable costs. Assumptions
for the analysis were developed by Burns & McDonnell with input by RPU.
In order to assist in developing the various futures for power supply which RPU could
pursue, decision tree analysis was used to organize the options. Meetings were held
with RPU to construct the decision tree used to organize the analysis. Risk
assessment was performed on the various futures to identify the variability of the
outcome with changes in the assumptions. A summary decision tree from the more
extensive one developed with RPU is shown in Figure I-1 at the end of this section.
This decision tree is for the period 2016 to 2030.
Burns & McDonnell used an hourly and monthly spreadsheet production cost model
to review the costs of the various futures considered. The use of this model allowed
application of ranges of probable values for certain assumptions to determine the risk
of various futures. Estimates and projections prepared by Burns & McDonnell
relating to interest rates and other financial analysis parameters, construction costs
Rochester Public Utilities
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Burns & McDonnell
Part I
Introduction
and schedules, operation and maintenance costs, equipment characteristics and
performance, and operating results are based on our experience, qualifications and
judgment as a professional consultant. Since Burns & McDonnell has no control over
the numerous factors affecting the basis for the estimates and projections, Burns &
McDonnell does not guarantee that the actual future costs will not vary from those
used by Burns & McDonnell in the preparation of this study.
Study Development
The power supply study is the initial effort for the overall development of the RPU
Plan. RPU desired the review of supply side expansion plans first to allow study of
effective, economical demand side management, other customer related options and
renewable energy resources to reduce or eliminate the need for development of
additional traditional supply side resources.
Report Organization
Part II provides the review of the existing RPU resources and of the supply side
resources considered to meet RPU’s future demand and energy needs. Part III
discusses the portfolio analysis of the various approaches and provides conclusions
and recommendations on the attractive alternatives and other issues associated with
the supply side needs. Part IV provides the projected resource requirements of RPU
over the study period which allows the estimated timing and needs for additional
funds. The demand side and renewable analyses are included in Part V of this study.
Part VI includes detailed financial forecasts for a variety of futures.
Rochester Public Utilities
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Burns & McDonnell
Part I
Introduction
50MW Coal
100MW Coal
Sell SLP
Twin Pac
100MW CC
None
50MW Coal
100MW Coal
Gas based service
0
Twin Pac
100MW CC
SLP in 2016
SLP Futures
2016-2030
50MW Coal
100MW Coal
Unit 4
Twin Pac
100MW CC
50MW Coal
100MW Coal
All
Twin Pac
100MW CC
Figure I-1
Summary Decision Tree
Traditional Power Supply Options
*****
Rochester Public Utilities
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Burns & McDonnell
Part II
Power Supply Resources
Part II
Power Supply Resources
Rochester Public Utilities (RPU) is responsible to meet the electrical energy needs of
the citizens of Rochester, Minnesota and certain areas surrounding Rochester. The
loads include general residential and commercial loads as is typical of large metro
areas. Larger customers served by RPU include the various hospitals within
Rochester, such as the Mayo Clinic, and a large IBM facility. RPU owns and
operates generation resources to meet its demand and energy needs. RPU is also a
member of the Southern Minnesota Municipal Power Agency (SMMPA) which
provides RPU with a major portion of its energy requirements.
This part of the report discusses:
•
•
•
RPU’s projection of its demand and energy needs
The existing RPU supply side resources
Options for meeting demand and energy needs
Load Forecast
RPU continually reviews its demand and energy requirements. The development of
the forecast considers the historical load growth, effects of economic development,
weather, the impacts of ongoing demand side management programs and various
other factors. RPU develops the forecast and applies it to a typical yearly hourly load
profile. This provides an hourly load forecast for the study horizon to 2030. The
forecast provided by RPU is summarized on an annual basis on Table II-1. The
monthly and hourly load forecasts are included in Appendix I.
The RPU load growth is closely linked to the growth of the Mayo Clinic and other
major employers in the area. Average system growth is projected by the RPU
forecasting group to be approximately 2.7% per year between 2004 and 2030. This
compares to an average compound growth of 3.5% over the past 15 years.
There are considerations of large employment opportunities in the RPU area, such as
the Genomics facility. Also, Rochester is discussing annexation of various areas
around the current city limits. These issues could have substantial impacts to the
system resource requirements.
Rochester Public Utilities
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Burns & McDonnell
Part II
Power Supply Resources
Table II-1
RPU Forecast of Demand and Energy
2003-2030
Year
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Annual Peak Total Annual Energy
Demand
Requirements
(MW)
(MWh)
261
1,306,276
268
1,344,534
276
1,377,767
283
1,414,967
291
1,453,171
299
1,495,732
307
1,532,702
315
1,574,085
323
1,616,585
332
1,663,932
341
1,705,059
350
1,751,096
360
1,798,375
370
1,851,046
379
1,896,798
390
1,948,012
400
2,000,608
411
2,059,202
422
2,110,100
434
2,167,072
445
2,225,583
457
2,290,766
470
2,347,559
482
2,410,943
495
2,476,038
509
2,548,370
522
2,611,549
537
2,682,061
Resource Review
RPU has a number of resources to meet its demand and energy requirements. These
include a diverse mix of coal, gas and hydro-electric generating units. The RPU also
has a significant amount of energy provided under its contract with the SMMPA. The
units owned and operated by RPU are located at the following sites:
•
•
•
Silver Lake Power Plant
Cascade Creek Substation
Zumbro Hydro Plant
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Burns & McDonnell
Part II
Power Supply Resources
To efficiently manage its resources, RPU has entered into contracts for electric sales to
the Minnesota Municipal Power Agency and for steam sales to the Franklin Heating
Station (Mayo Clinic). These contracts are furnished from the Silver Lake resources.
Based on a forecast of expected resource allocations for these sales, the resources that
RPU will have available to meet its obligations are summarized in Table II-2 and shown
graphically in Figure II-1.
Figure II-1
RPU Forecasted Load and Resources
600
500
400
MW
Silver Lake Plant
300
Cascade Creek Gas Turbine Capacity
200
100
SMMPA Contract
SMMPA
Rochester Public Utilities
Hydro
CCreek1
CCreek2
II-3
SLP
Peak Load Forecast
20
30
20
29
20
28
20
27
20
26
20
25
20
24
20
23
20
22
20
20
20
21
20
19
20
18
20
17
20
16
20
15
20
14
20
12
20
13
20
11
20
10
20
09
20
08
20
07
20
06
20
05
20
04
0
Peak +15%
Burns & McDonnell
Table II-2
RPU GENERATION CAPABILITY FORECAST 2004 - 2030
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Peak Load Forecast
270
277
284
292
300
308
316
325
334
343
352
362
371
381
392
402
413
424
436
447
460
472
485
498
511
525
539
Peak Load w15% Reserves
278
286
295
304
313
322
332
341
351
362
372
383
395
406
418
430
443
455
469
482
496
510
525
540
555
571
588
Generation Capability
SMMPA w15% Reserves
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
216
SLP Capacity Available w/
Mayo project
2
2
52
52
42
42
42
67
67
67
67
67
92
92
92
92
92
92
92
92
92
92
92
92
92
92
92
Hydro
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Gas Turbine 1
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
28
Gas Turbine 2
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
49
Available RPU Capability
81
81
131
131
121
121
121
146
146
146
146
146
171
171
171
171
171
171
171
171
171
171
171
171
171
171
171
Total Generation Capability
297
297
347
347
337
337
337
362
362
362
362
362
387
387
387
387
387
387
387
387
387
387
387
387
387
387
387
Excess Capability
19
11
52
43
24
15
5
21
11
0
-10
-21
-8
-19
-31
-43
-56
-68
-82
-95
-109
-123
-138
-153
-168
-184
-201
II-4
Part II
Power Supply Resources
As shown in the above table and graph, RPU becomes resource deficit in 2013. The
following paragraphs provide a description of the above resources and issues associated
with continued production from the generating units over the study period. Detailed
assumptions about the units and their operating parameters can be found in Appendix II.
Silver Lake Plant
The Silver Lake Power Plant was conceived by the RPU during World War II. The first
unit rated 7500kW was in full service in December, 1949. The annual growth of
Rochester electrical load in the late 1940s was approximately 15 percent. This growth
prompted planning for a second unit that was brought on line in 1953. This unit was
sized to 11,500kW.
Continual planning due to load growth and attraction of customers such as IBM indicated
that a third unit at the plant was needed. The unit was sized at 22,000kW. Construction
began in mid-1961 and the unit went into commercial operation in November, 1962.
This unit was cooled with a cooling tower and also with cooling water from Silver Lake.
The resulting warm water allowed portions of Silver Lake to be ice free in the winter,
leading to the attraction of the Canadian Geese to winter on the lake.
Average energy consumption per customer essentially doubled between the mid-1950s
and late 1960s. In addition, the population of Rochester continued to expand. The fourth
unit added at SLP was part of a larger overall power supply expansion plan. This unit
was rated at 58,000kW. This unit was constructed with an electrostatic precipitator to
remove particles from the unit’s emissions. The construction of the unit was completed in
1969.
Fuel for the plant was provided by natural gas and coal. The utility conformed to
Pollution Control Agency guidelines and installed precipitators on each of the three
remaining units in the 1970s. The plant has been operating steadily since its units went
commercial. Reduced utilization of the plant occurred in 1988 due to RPU’s
participation in SMMPA. The Sherburne County Unit 3 went commercial in 1988 and all
of the requirements of the RPU could be met with SMMPA resources. When SMMPA
provided all of the energy requirements of the RPU, the excess capacity and energy of the
SLP was contracted to the Minnesota Municipal Power Agency. Current usage of the
plant to meet steam and electricity contract sales maintains its viability and usefulness.
The RPU capped its purchases from the SMMPA in 2000 and is providing the capacity
and energy above a base amount of 216MW.
Plant Basics
The SLP consists of four boilers which produce steam to operate steam turbine-electric
generator combinations that are dedicated to each boiler. Figure II-2 shows the SLP with
Unit 1 on the left. The units in the plant can be fired on coal or natural gas.
Rochester Public Utilities
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Part II
Power Supply Resources
Figure II-2
View of the Silver
Lake Power Plant
The SLP is required to operate within the guidelines of the Mid-Continent Area Power
Pool (MAPP). The MAPP requirements include regular testing of the units in the power
plant to make sure they can deliver the power that the RPU records for their capacity.
These tests have shown that the plant has the capabilities shown in Table II-3:
Table II-3
Unit Data
Unit
Installed Date
1
2
3
4
1949
1953
1961
1969
Total
Tested kW
(2002)
9,360
14,520
24,000
61,945
109,825
Environmental
The SLP is operated to minimize environmental impacts to the Rochester area and in
compliance with federal and state environmental regulations. The units are equipped
with particulate controls. RPU purchases low bituminous sulfur coal for the plant to
minimize the release of sulfur dioxide and comply with emission limits contained in the
operating permit.
There are a variety of recently enacted and newly proposed regulations which will affect
electric generating plants. The regulations will affect all generating units at the SLP.
These regulations may require additional emission control equipment be added at the
plant or changes to the fuel used for energy production.
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RPU recently completed a study on the environmental aspects of the SLP with regard to
existing and potential environmental regulations. It is expected that the RPU will need to
make investments in additional emission controls or implement other emission reduction
strategies within the next 5 years. Various options are currently under consideration by
RPU. Estimated impacts to the SLP have been considered in this study using the results
of the environmental report “Analysis of Existing and Potential Regulatory Requirements
and Emission Control Options for the Silver lake Plant”.
Due to the permit restrictions contained in the current air permit SLP, Unit 4 is limited to
a 60-70% annual capacity factor. This will be significantly reduced if the recently
proposed Interstate Air Quality Rule is promulgated and no modifications are made to the
SLP.
Sales
The SLP has two contracts for energy sales. The MMPA contract provides for electrical
sales to the MMPA when the units are available. The contract has various options for
RPU to reduce the amount of capacity offered to MMPA. These options to adjust
capacity allocated to MMPA under the contract are available in 2005 and 2010. The
above balance of loads and resources reflect the current thinking of RPU on the amount
of capacity which will be available to RPU from the contract.
The steam sales to the Franklin Heating Station are going to begin 2004. The steam sales
are not anticipated to limit the electrical output of the steam generators until after the
2010 time frame. These reductions in electric capacity have been accounted for in the
balance of loads and resources.
Retirement
Units 1-3 at the SLP will be attaining almost 65 years of service in 2015. Unit 4 will be
reaching 45 years of operation. The investment in maintaining the units in operable
condition has been estimated and included in the analysis. One of the major investments
to be considered is the environmental controls required to keep the units in compliance
with expected future environmental regulations. A recent study prepared for RPU by
R.W. Beck and Associates has provided several options and their associated costs for the
units with regard to compliance with anticipated future environmental regulations.
Although the components of the units can be repaired or rebuilt to keep the units in
serviceable condition using after market providers and salvage operations from similar
retired units, the efficiency of the units is below current technology being developed for
coal fired power plants. Due to the age, size and efficiency of units 1-3, these units, if
maintained, will most likely be used only for regulatory reserve service with minimal
operating time.
Cascade Creek
The RPU has two units in the Cascade Creek substation. Cascade Creek Unit 1 was
installed in 1975. The unit is a Westinghouse 251 machine and has a capacity rating of
28MW. Modifications to the unit in 2002 allow the unit to be operated on fuel oil or
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natural gas. The unit is reaching a point where replacement parts are becoming difficult
to obtain. Aftermarket manufacturers can support the unit for some time. However, RPU
plans on retiring the unit after 2015. The retirement of this unit will increase the deficit
after 2015 by 28MW.
Cascade Creek 2 is a Pratt and Whitney FT8 Twin Pac, which became commercial in
2002. The unit is rated at 49MW. The unit consists of a single electric generator with
dual engines based on aircraft engine technology. The dual engine approach allows the
unit to be operated at half load with high efficiency. This flexibility minimizes operating
costs when RPU needs resources to follow load more closely. This unit is assumed to be
operational throughout the study period.
Zumbro River
The Zumbro River hydro-electric plant is a run of river unit located on the Zumbro River.
The plant is located 10 miles to the north of the city. The unit was installed in 1919 and
has a maximum capacity of 2MW. The unit has a typical annual capacity factor of 50
percent. Although the unit is over 80 years old, significant investment has been made in
the facility and it is assumed to remain available throughout the study period.
Southern Minnesota Municipal Power Agency (SMMPA)
RPU began taking power supply from the SMMPA in 1982. The SMMPA provided all
requirements service to RPU until 2000 when RPU accepted an offer to limit its
purchases from the SMMPA. The contract rate of delivery (CROD) was set at 216MW.
RPU is required to take all energy from the SMMPA when the demand is at or below the
CROD level. The SMMPA will provide the CROD throughout the study period.
Transmission Issues
Electrical System Reliability
To operate reliably and in compliance with NERC and MAPP standards, RPU and other
electric utilities developed their systems to operate with no noticeable degradation of
service in the event of a loss of a system facility. In many cases, this is true even when
an outage of a major system element coincides with the outage of another element for
maintenance.
Changes in the electric industry over the past several years have caused the reliability of
the system for delivery of firm energy to degrade. Increased use of the system for market
transactions has increased loading of the system to the point that when outages occur, the
remaining system is left with a reduced capability to transfer power over
interconnections. Recent uncertainty in the ownership, operation and regulation of the
transmission system has left the responsibility to correct system deficiencies in question.
RPU imports a significant amount of energy under its contract with the SMMPA. The
transmission system which interconnects RPU to the regional transmission network is
configured as indicated in Figure II-3. The strongest source to the interconnected
network is through the Byron substation and is the primary path for the SMMPA energy.
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With all of the lines in service, the system was designed to allow firm importation of the
SMMPA energy whenever RPU called for it.
Recent changes in the usage of the system by others have led to curtailments of energy
imports with the regional interconnections intact. An example of the transmission
limitations that exist occurred on August 12, 2003 from 20:00 hours to 22:00 hours. RPU
was required to generate because SMMPA was not able to secure transmission to deliver
the energy required by RPU to meet loads. This condition is interesting because RPU’s
load was below the CROD level of 216 MW, for which RPU pays firm delivery. This
condition is expected to escalate both in magnitude and frequency. Under current plans,
no relief of the transmission situation in Southeast Minnesota is expected before 2010.
Rochester System
Figure II-3
Area Interconnections
with RPU
Dairyland Power
Cooperative
161 kV System
Byron 345kV
Sub
Alma
Byron
161kV
Sub
Maple
Leaf
Chester/DPC
Rochester
Adams
With the Byron/Maple Leaf 161 kV line out of service, voltage and other considerations
on the Dairyland Power Cooperative system limit the ability to import energy from the
interconnected system to about 160 MW. Figure II-4 shows a load duration curve
projection for 2005 for the RPU load. This curve shows the magnitude of the load in
each of the 8760 hours of the year in order from highest to lowest. As shown, the RPU
load alone is projected to be above the 160 MW level of import approximately 50 percent
of the time. The use of generation internal to the area, such as the SLP is required to
mitigate the risk of blackout during this condition.
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Figure II-4
RPU 2005 Load Duration Curve
350
300
Peak Demand = 276 MW
Total Energy = 1,378 GWh
Load Factor = 57.0%
Energy provided by Market
and RPU Generation
Load (MW)
250
200
150
100
Energy Provided by SMMPA Contract
50
0
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Hour
Another situation also requires the use of RPU generation to assist the area
interconnected network. The rating on the Byron/Maple Leaf 161 kV line is a limiting
factor in setting the transfer limit on the Byron 345 kV lines. The rating of these lines is
a contributor to the calculation of the capability to import and export power from
Minnesota to Wisconsin and points south and east. RPU, as a part of the interconnected
system and with generation accredited in MAPP, is obligated to operate generation to
assist these transfers during certain system outages. Running RPU generation is a partial
mitigation for certain outages. While the RPU does not specifically benefit from this
operation, it is an obligation that may be incurred from time to time.
The above discussion provides a description of the area interconnection limitations to
which the community of Rochester is exposed. RPU faces several impacts due to these
limitations. The SLP and Cascade Creek generating units assist in reducing the impacts
and thus the costs to RPU and the community of Rochester. The increased reliability for
Rochester is increased in numerous ways by the generation located within the service
area of RPU.
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The electrical wholesale market is moving towards a new market operation being
promoted by the Federal Energy Regulatory Commission (FERC). The new operation is
based on the concept of locational marginal pricing (LMP). The concept behind LMP is
that the energy from generation required to alleviate a transmission constraint will be
higher cost than the energy that could be imported if there were no constraint. Since
Rochester is in a constrained load pocket, it could be subjected to substantial costs if the
SLP or Cascade Creek generation was not available. The generation located in the RPU
service area will reduce the exposure to market pricing and high LMP costs.
System Improvements
RPU is undertaking studies with regional utilities to assess options for reducing the
constraints into the southeast Minnesota region and Rochester. Several transmission
projects are being considered which will affect the 161kV and 345kV systems in the
region.
The development of a project to increase the transfer capacity into the RPU service
territory is important to allow RPU to rely on the firm delivery of its CROD amount. In
addition, it is also desirable through the development of a project to have increased
transfer capacity for importation of market power or participation in regional projects,
such as for a coal or wind resource, on a firm basis.
Use of local generation is becoming more of an issue as regional loads increase and the
capability of the transmission system becomes more limited. Due to must run issues
during portions of the year and contract requirements of MMPA, the SLP is required to
remain operational for the foreseeable future. The current limitations on the transmission
system being below the level required to support the RPU load from outside resources
point out the importance of generation internal to the RPU service area.
Potential Resource Options
The capacity needs of RPU are projected to increase substantially over the study period.
The range of capacity needs is reflected in Table II-4 for various retirement scenarios of
Cascade Creek Unit 1 and Silver Lake Plant Units 1-4.
Table II-4
Range of Capacity Requirements for Various Retirements Scenarios
(MW of Capacity Deficiency)
2016
2020
2025
2030
All Units in Service
8
56
123
201
Retire CC Unit 1
36
84
151
229
Retire CC1, SLP 1-3
83
131
198
276
Retire CC1, SLP 1-4
128
176
243
321
In addition to an assessment of demand shortfalls, a review of energy needs is also
necessary to determine if only peaking type resources are needed, or if low cost energy,
reflective of intermediate or base load resources, is potentially beneficial. Figures II-5 A
through C provide the estimated load duration curves for RPU for the years 2005, 2010
and 2015, respectively.
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Figure II-5A
Approximate RPU Load Duration Curve
2005
400
2005 Projected Load Duration Curve
350
300
Peak Demand = 276 MW
Total Energy = 1,378 GWh
Load Factor = 57.0%
Load (MW)
250
200
150
SMMPA 1,364 GWh (72% CF)
100
50
0
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Hour
Figure II-5B
Approximate RPU Load Duration Curve
2010
400
2010 Projected Load Duration Curve
350
300
Peak Demand = 315 MW
Total Energy = 1,574 GWh
Load Factor = 57.0%
Load (MW)
250
200
150
SMMPA 1,527 GWh (81% CF)
100
50
0
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Hour
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Figure II-5C
Approximate RPU Load Duration Curve
2015
400
2015 Projected Load Duration Curve
350
300
Peak Demand = 370 MW
Total Energy = 1,845 GWh
Load Factor = 57.0%
Load (MW)
250
200
150
SMMPA 1,714 GWh (91% CF)
100
50
0
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Hour
A review of the load duration curves indicates that the SMMPA CROD level would
approach its maximum utilization in the 2010 to 2015 time frame. The energy
(represented by the colored areas above the SMMPA energy) would be provided by RPU.
Therefore, in addition to capacity needs, RPU will also need to consider the availability
of low cost energy resources for the period beyond 2016.
The projected hourly loads for RPU during the year 2016 are shown in Figure II-6.
Review of the hourly loads indicates that the majority of the RPU needs occur in the
summer months, between May and September. There are several hours when the load
will be below the CROD level. This indicates that resources may need to be cycled if
load following is required.
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Figure II-6
RPU Projected Hourly Load – 2016
400000
350000
300000
KW
250000
200000
150000
100000
50000
0
1
367 733 1099 1465 1831 2197 2563 2929 3295 3661 4027 4393 4759 5125 5491 5857 6223 6589 6955 7321 7687 8053 8419 8785
The operational issues associated with meeting the projected RPU load requirements can
also be reviewed by looking more closely at the load swings. Graphs for the hourly
loading during winter and summer weeks are shown in Figures II-7A and B respectively
for every five years from 2016 to 2030. The growth in the daily swings from winter to
summer provide an indication of the seasonal types of energy needs which RPU will be
required to provide. The load on the figures is the load above the CROD amount.
Therefore, the zero point on the vertical axis represents a load of 216MW, provided by
the SMMPA contract.
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Figure II-7A
RPU Projected Hourly Loads Week of January 1-7
350000
300000
250000
200000
150000
100000
50000
0
1
7
13
19
25
31
37
43
49
55
61
67
73
2015
79
85
91
2020
97 103 109 115 121 127 133 139 145 151 157 163
2025
2030
Figure II-7B
RPU Projected Hourly Loads Week of July 1-7
350000
300000
250000
200000
150000
100000
50000
0
1
7
13
19
25
31
37
43
49
55
2015
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67
73
2020
79
85
91
2025
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97 103 109 115 121 127 133 139 145 151 157 163
2030
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Fuel Considerations
The availability to develop resources within a utility’s service area requires a review of
area capabilities for the delivery of low cost fuel for the units. Current utility options for
fuel include coal, natural gas, fuel oil, water, and renewable options such as solar, wind
and biomass.
Coal
RPU currently burns coal at the SLP facility. The coal is delivered by barge/truck and
rail, with approximately 50 percent delivered by each method. It is not expected that the
consumption of coal will increase beyond the limitations of the permits for SLP Unit 4.
If RPU pursued the development of an additional coal resource within its service area,
rail facilities to deliver the coal from the Powder River Basin in the west or from eastern
mines, besides those currently available from Illinois and Indiana, would need to be
expanded. Currently, the RPU service area has a rail line being reactivated which would
allow delivery of Powder River Basin coal. Acquisition of several hundred acres of
property adjacent to the rail line would be required or a rail loop would have to be
constructed if the property was located remote from the rail line.
The use of coal by the utility industry is expected to increase. Its availability within the
United States has certain security advantages. Its price has been historically low and
stable when compared to natural gas and fuel oil. Its main disadvantage lies in the
emission during its combustion. New requirements are increasing the controls necessary
on new coal plants to reduce the emissions to levels that are approximately one tenth of
units constructed under prior Clean Air laws.
Natural Gas
The use of natural gas in new utility plant is typically limited to simple or combined cycle
applications. Modern gas units require gas pressures typical of interstate lines.
Additional gas based resources for RPU would require the acquisition of additional
property, since the existing Cascade Creek site is fully utilized and the SLP site has
inadequate gas capacity. Modern units could be placed on a site of less than one hundred
acres.
The historical availability of natural gas has been such that it was abundant in the
summer months when residential and commercial heating demands were low and subject
to interruption during the winter when the heating demands increased. When utilities
developed the peaking gas resources, they were typically required in the summer with
minimal expectations for operation in the winter. Utilities relied on this pattern and
purchased the gas on a non-firm basis to reduce delivery costs. For the minimal hours of
operation in the winter, back up operation on fuel oil could be relied on if the gas delivery
was curtailed.
Recent demands for peaking and combined cycle energy fired from natural gas in both
the summer and winter have increased to the point where the electric utilities are
affecting the storage and availability of natural gas. In addition, due to environmental
restrictions, more natural gas is used by many utilities to achieve compliance with their
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operating permits, which occurs primarily in the summer months. The use of non-firm
purchasing approaches to the gas is becoming more of a problem in the winter months as
utilities are required to provide increasing amounts of energy from these units to meet
winter demands.
Dependence on natural gas by the utility industry has become more of a concern as the
United States becomes an importer of the fuel from Canada and through liquefied natural
gas ports from other countries. The cost of gas is expected to remain volatile and
increase with the increasing demand for it by other countries as their economies improve.
It is expected that over the study horizon, natural gas costs will not only increase due to
commodity pressure, but from the need to firm up the delivery as well.
Other Options
The use of fuel oil is only considered on an emergency basis or when its cost is below the
cost of natural gas. Emissions from use of fuel oil in electric plants typically restrict its
use to few hours of the year. It is not considered as a basis for any resource expansion
plan for RPU.
RPU and the surrounding regions do not have significant access to hydro-electric based
development. The current hydro resources are fully committed. One area of potential
access to hydro-electric power is the further development by Manitoba Hydro of projects
that have been considered for several years. Access to this energy would require
significant improvement in the region’s transmission facilities.
Renewable resources are an increasing source of energy for utilities. Wind is the primary
source and Minnesota has several hundred megawatts of wind in operation and more is
being developed. In addition, wind resources are being developed in the neighboring
states of Iowa, South Dakota and North Dakota are developing wind resources. Solar is
becoming an increasing option for higher cost utilities on the east and west coasts as the
cost of solar systems decrease and the cost of the utilities’ energy increases.
A consideration for the use of solar and wind is the inability to dispatch the resource.
Variability and availability of the energy can create operational issues with area
generating units and can lead to a degradation of frequency and voltage control if the
amount of solar and wind energy becomes a high component of the utility’s energy
needs. The inability to dispatch the resources has to be considered with regards to the
CROD requirements.
Biomass is another option for renewable energy. Biomass plants are typically rated
below about 50MW and operate in a steam cycle similar to the SLP plants. The
candidates for biomass are typically;
•
•
•
wood chips and other tree product residues,
agricultural wastes such as fruit pits and nut hulls, and
grasses.
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The limiting factor on the development of a biomass plant is the availability of fuel.
These plants are developed in areas where there is a continuous, ready availability of the
fuel. Due to the poor storage capabilities of most of the candidate biomass fuel options, a
continuing supply of quality fuel is necessary to make the process viable. The regional
surrounding RPU is not known to have an adequate supply of typical candidate biomass
fuels.
However, there is one area where RPU may have access to a limited amount of biomass
fuel. Minnesota has also included municipal solid waste as a biomass fuel under
Minnesota 2003 Statute 216. Therefore municipal waste and refuse derived fuel (RDF)
burned in a power plant will be counted as biomass energy. The availability of RDF is
typically sufficient in municipal areas the size of Rochester to support several megawatts
of RDF fired generation.
Olmsted County has developed a municipal solid waste to energy facility. The Olmsted
Waste to Energy Facility (OWEF) currently produces approximately 1.9MW of biomass
fueled energy. This resource could be a source of biomass energy for RPU.
Summary
The RPU is confronted with several long term decisions associated with its generation
and transmission resources. Based on the review of the resource issues as identified in
this part, the following observations can be developed.
1. The projected load growth indicates that the CROD obtained from the SMMPA
will essentially be fully utilized in the 2010 to 2015 time frame.
2. The SLP facility will be subjected to environmental regulations being
implemented and future regulations under consideration. The cost of these
regulations, the ongoing maintenance costs, sales obligations and the efficiency of
the existing units require an assessment of an RPU future with varying amounts of
the SLP available.
3. The RPU transmission system supplying RPU is currently inadequate to deliver
the firm requirements of the CROD amount and to be relied upon to provide firm
access to outside resources. Therefore, any reliance on resources outside the RPU
area for firm energy will require the upgrading of the system in the vicinity of
RPU. Depending on the location of any resource in which RPU may want to
participate or purchase capacity from, upgrades of the regional system may also
be required.
4. RPU capacity needs include resources to provide low cost capacity and energy
over the study period. The ability to acquire the capacity and energy from outside
the RPU service territory or the need to locate resources within the service area
will be dependent on the transmission system upgrades pursued in the region by
regional utilities.
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5. The existing RPU generation locations do not have adequate space or access to
fuel and transmission to support significant additional facilities. RPU will need to
acquire additional property to support most types of generation options
constructed within its service area.
6. RPU has options for development of wind and solar units and purchasing biomass
energy from the Olmsted Waste to Energy Facility for renewable resources.
7. The market changes in the electric industry surrounding RPU will impact the
resource decisions. Due to the uncertainty associated with the implementation of
the MISO market, the level of participation by regional utilities, and the rules
which participants will be required to follow, it is difficult for any firm conclusion
to be made on the availability of market capacity and energy as a reliable resource
which could be used by RPU to meet its needs.
*****
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Resource Options Analysis
Part III
Resource Options Analysis
Part II provided a review of the expected capacity and energy needs of RPU over the
study period. From the review, RPU is expected to have needs for both capacity and low
cost energy resources beginning in 2013 and increasing each year thereafter.
Additionally, a discussion of the existing resources indicates that the Cascade Creek Unit
1 is anticipated to be retired in 2015. Also, the future of the SLP is uncertain due to the
age of the facilities and the ongoing operation, maintenance and environmental upgrades
needed to keep the plant operational. This part of the report discusses portfolio options
considered for RPU using traditional resource options.
Regional Market Conditions
Coal Unit Development
RPU’s projected need for low cost energy limits the traditional options for supplying this
energy to energy produced by coal. The amount of capacity required by RPU is expected
to be in the 50 to 100MW level. In order to attain reduced capital and operating costs, it
is typical for utilities to join and construct a unit to be shared among several parties.
Therefore, the ability for RPU to obtain coal energy is realistically dependent on
participating in a joint facility.
The MAPP region maintains a 15% reserve margin and penalizes those utilities who fall
below this level. As such, the capacity margins in the MAPP region are projected to be
maintained to have sufficient generation available to meet unit outages and weather
extremes. The generation used to meet the reserve margin in the MAPP region, as in
other regions, has primarily been natural gas fired simple and combined cycle
combustion turbine units. There are coal plants being considered in the MAPP region.
Plants are being developed by the following entities:
•
•
•
OPPD – 600MW Nebraska City 2. Participation in the unit is through contract
sales. The unit is fully subscribed.
South Dakota – A large coal plant in eastern South Dakota is being considered by
regional utilities. Participation will be through ownership shares.
Mid-American Energy – Council Bluffs Unit 4. Participation is through
ownership shares. The unit is fully subscribed and under construction.
These plants are all located on the west side of MAPP. Significant transmission
constraint and operational issues would need to be resolved before reliable firm service
could be provided to RPU from these facilities. There are other utilities discussing units
in MAPP which may offer reduced transmission delivery issues to RPU. In addition,
RPU could join with other interested parties and develop a unit which could be sited
more beneficially to RPU and have an in service date more in line with the needs of RPU.
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Market Pricing
The power supply market in the MAPP regional is undergoing significant change. The
Midwest Independent System Operator (MISO) is gaining operational control of a
significant amount of transmission as utilities comply with orders of the Federal Energy
Regulatory Commission (FERC) for regulated utilities to transfer operational control of
their transmission systems to an independent operator. Additionally, MISO is furthering
the FERC agenda of implementing a standard market design for the wholesale market.
The operational rules of this market are currently being developed and the MISO is
working towards implementation of the market by January 1, 2005. It is expected that
this schedule will slip due to the numerous issues still to be resolved.
The MAPP regional has traditionally had a surplus of low cost energy. The pricing of
this energy is increasing to reflect the marginal price of the combined cycle units that
have recently been commissioned in the region and the need for additional base load
facilities. Figure III-1 provides an indication of the increase in MAPP prices for the north
region. The graphs reflect the increase in pricing due to the increased reliance on natural
gas for electricity production.
Figure III-1
MAPP Spot Energy Pricing 1997-2003
MAPP / MAPP North Spot Market Price Duration Curves
100
90
80
Index Price ($/MWh)
70
60
1997
1998
50
1999
2000
2001
40
2002
2003
30
20
10
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Hours
The development of portfolio options for RPU considered the availability of a coal plant
for RPU participation.
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Resource Requirements
Portfolios were developed to reflect the decision tree issues associated with the following
availability of the SLP beyond 2015:
•
•
•
SLP fully retired
Units 1-3 retired, Unit 4 remains operational
All SLP units available
In addition, the retirement of the Cascade Creek Unit 1 was assumed to occur in 2015.
The retirement of this unit increases the capacity required by 28MW in the study period.
Figures III-2 through 4 shows the balance of loads and resource for each of the above
SLP futures.
Figure III-2
RPU Balance of Loads and Resources –No SLP
700
600
500
MW
400
300
200
100
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Hydro
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SMMPA
CCreek1
CCreek2
III-3
SLP
Peak Forecast
Peak +15%
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Resource Options Analysis
Figure III-3
RPU Balance of Loads and Resources -45MW of SLP
700
600
500
MW
400
300
200
100
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Hydro
SMMPA
CCreek1
CCreek2
SLP
Peak Forecast
Peak +15%
Figure III-4
RPU Balance of Loads and Resources –All SLP
700
600
500
MW
400
300
200
100
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Hydro
Rochester Public Utilities
SMMPA
CCreek1
CCreek2
III-4
SLP
Peak Forecast
Peak +15%
Burns & McDonnell
Part III
Resource Options Analysis
The resource requirements were developed to maintain the reserve requirements of RPU.
The current level of reserves is required by MAPP to be 15 percent of the amount of load
requirements above the CROD amount.
Traditional Options
The traditional options included new resources fueled by coal and natural gas. These
options are discussed in more detail in the following paragraphs.
Gas-Fired Options
Gas fired generation today is performed by combustion turbines operating in simple cycle
or combined cycle mode. Simple cycle combustion turbines operate similar to jet aircraft
engine technology. These units vent their exhaust direct to a stack and typically have
efficiencies above 10,000 Btu per kWh. Combined cycle units include the simple cycle
machine with its exhaust vented into a heat recovery steam generator (HRSG) and then
through a stack. The steam produced by the HRSG drives a steam turbine/electric
generator combination as in a typical steam driven plant. Combined cycle plants have
efficiencies in the upper 6000 Btu per kWh range.
RPU currently operates two simple cycle combustion turbines. The new unit added at
Cascade Creek is the latest to be added to the system. These units are typically operated
when the load increases on the system during a few hours of the day. Simple cycle units
typically have the lowest capital cost of larger generating options. Project costs in the
range of $400 to $600 per kW are typical, with the smaller units having the higher cost
per kW. Due to their efficiency, these units are typically operated at capacity factors
below 15 to 20 percent.
Combined cycle plants have higher capital costs than simple cycle machines, due to the
steam cycle cost. Project costs for these machines range from $500 per kW to $750 per
kW, again with the smaller plants having the higher cost per kW. These plants have been
the predominate plant installed by merchant independent power producers over the past
few years and are expected to account for the majority of the installed capacity for the
foreseeable future. Since these plants operate at higher efficiencies, they operate at
capacity factors above those of simple cycle machines and are typically between 25-50%.
Gas-fired combustion turbines have nitrous and carbon oxides as their main emissions.
Simple cycle units use water in emission control and in inlet air fogging systems.
Combined cycle units also use water in cooling cycles for the steam condensing and
boiler makeup.
The existing gas fired generation on RPU's system is used primarily for peaking and
reserve service. The gas supply for these units is operated on a non-firm basis.
Operating with a non-firm fuel supply allows the energy to be produced for essentially
the cost of the gas commodity and a small delivery charge. RPU could develop gas-fired
units within its service territory without the need for partners due to the lower effect of
economies of scale.
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Part III
Resource Options Analysis
Coal-Fired Options
Traditional coal-fired steam power plants are being considered for electricity production
again as the cost of natural gas and the concern over its availability increases. Coal-fired
plants, such as RPU's Silver Lake Plant, burn coal to produce steam which drives a steam
turbine/electrical generator to generate electricity. Coal plants are being designed to
reduce the emissions from the coal burning process to very low levels. Facilities added to
clean the exhaust path include scrubbers to remove the sulfur dioxide, baghouses to
remove the particulates and selective catalytic reduction equipment to remove nitrous
oxide. Processes are being developed to also reduce the mercury in the exhaust.
To achieve economies of scale, coal plants are typically above 250 MW in capacity. At
this size, there are two combustion types, fluidized bed and pulverized coal. There are
major differences in the boiler and plant design for the two units. The main difference is
in the method to control sulfur emissions. The fluidized bed units blend limestone in the
combustion chamber to achieve reductions in the sulfur emissions. Pulverized coal units
use scrubbers to inject lime into the exhaust stream and remove the sulfur. The SLP coal
units are pulverized coal units. The current upper commercial limit on the fluidized bed
units is 250 MW.
Coal plants typically operate with capacity factors of 60-80%. In order to achieve these
economies of scale, a joint owned unit would be required or RPU would have to enter
into contract sales to support the costs of the facility until the entire plant could be used
for RPU requirements.
It is assumed that any new plant would burn coal from the Powder River Basin. However,
new facilities are considering bituminous coal from the east as it is easier to remove the
mercury from the exhaust stream. A coal plant developed by RPU could be served by the
Dakota Minnesota and Eastern railroad, which is extending its system into the Powder
River Basin. Another area option might be the Union Pacific line. Expansion of the rail
system would be needed if an additional unit is located in RPU’s service territory. No
specific siting assessment has been performed for this option.
Traditional Resource Portfolios
Considering the capacity needs for the SLP availability scenarios, the resource portfolios
shown in Table III-1 were developed.
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Part III
Resource Options Analysis
Table III-1
Resource Portfolios
Case
None216-100Coal
None216-50Coal
None216-100CC
None216-LMS100
None216-SC
45216-50Coal_CoalFirst
45216-50Coal_SLPfirst
45216-100CC
45216-LMS100
45216-SC
All216-50Coal_CoalFirst
All216-50Coal_SLPfirst
All216-100CC
All216-LMS100
All216-SC
Existing Capacity - MW
CROD
Other
SLP
216
51
0
216
51
0
216
51
0
216
51
0
216
51
0
216
51
45
216
51
45
216
51
45
216
51
45
216
51
45
216
51
92
216
51
92
216
51
92
216
51
92
216
51
92
Coal
100(15)
50(15)
50(15)
50(15)
50(15)
50(15)
Capacity Added - MW(year installed)
Combined Cycle
Twin Pac
50(15)
50(20)
100(15)
50(20)
100(15)
50(15)
50(20)
100(15)
50(15)
50(20)
150(15)
50(20)
50(15)
50(20)
50(15)
50(20)
100(15)
50(20)
100(15)
50(20)
100(15)
50(20)
50(20)
50(20)
100(20)
50(20)
100(20)
50(20)
50(15)
50(20)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
50(25)
The case titles are developed such that the None, 45 or all refers to the amount of SLP
capacity available, 216 refers to the CROD amount and the last numbers refer to the MW
of resource added. SC refers to simple cycle, CC refers to combine cycle, and LMS 100
refers to a new simple cycle unit being developed. References to CoalFirst and SLPFirst
are associated with the order of dispatch.
The simple cycle units considered are based on the current Cascade Creek Unit 2 type
facility, the Pratt and Whitney Twin Pac. The combined cycle unit is based on a purchase
of a 125MW portion of an area combined cycle project. The coal resources are assumed
to be from a regional project whereby RPU would purchase the indicated amount as an
owner.
Transmission delivery charges for the coal plant were included to provide an assumption
on the MISO transmission service fees. No transmission was assessed the combined
cycle unit or the simple cycle units as they were expected to be constructed within RPU’s
service territory.
Hourly and monthly production cost models were developed that dispatched the
resources on an economic dispatch basis, considering limitations on energy from Unit 4.
Assumptions for the new and existing units are included in Appendix II.
The energy to supply the RPU projected load growth is summarized in Table III-2 for the
coal and gas resource options. The load curves produced in Part II provide an indication
that the energy is more heavily utilized in the summer season than the winter period.
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Part III
Resource Options Analysis
Table III-2
Summary of Energy Sources from Gas or Coal Portfolios
2016
Energy in GWh
2020
2025
2030
Gas
3
36
121
Coal
1,839
1,806
1,721
Gas
21
79
248
Coal
2,023
1,965
1,796
Gas
72
187
479
Coal
2,257
2,142
1,850
Gas
171
423
773
Coal
2,490
2,238
1,888
45216-Coal
45216-Gas
4
34
1,838
1,808
25
93
2,019
1,951
79
243
2,250
2,086
187
536
2,474
2,125
All216-Coal
All216-Gas
4
34
1,838
1,808
25
93
2,019
1,951
79
243
2,250
2,086
187
536
2,474
2,125
None216-100Coal
None216-50Coal
None216-Gas
Note: Above numbers do not include a negligible amount of hydro energy
The above table reflects the energy estimated to be taken from the various generation
resources within the respective expansion portfolios. The energy in the gas columns
includes energy generated by RPU and purchased from the market. The coal energy
includes that purchased from SMMPA and generated by RPU. As seen, where the coal
energy is limited to the existing resources, significant increases in the gas energy is
necessary. It should be noted that all of the cases include additional gas-fired resources.
The cases that are based solely on natural gas-fired resource additions would require a
gas supply adequate to provide approximately 3056 MCF of gas per hour at
approximately 600psi when all of the units are operational in 2030. The RPU gas
consumption in 2030 with one of the all gas portfolios would be approximately 5360
million cubic feet. Even though a portion of the gas requirements are expected to be met
by market purchases, it is considered that the energy provided by the market would also
be gas based. Therefore, even if the gas is not directly used by RPU, it will be required
by the regional generation providing the market energy.
Production Cost Results
The results of the production cost modeling for the traditional portfolios are summarized
in Table III-3. The net present values for the cases were developed for the 15 year study
horizon in 2015 dollars. The values shown reflect the incremental costs of each option
and, therefore, do not include all of RPU’s costs which would be common among all of
the cases.
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Part III
Resource Options Analysis
Table III-3
Summary of Net Present Values for Portfolio Options
(2015 $000)
45216-LMS100
45216-50Coal_CoalFirst
All216-50Coal_CoalFirst
45216-50Coal_SLPfirst
All216-50Coal_SLPfirst
None216-50Coal
All216-LMS100
45216-SC
All216-SC
None216-100Coal
None216-LMS100
None216-SC
All216-100CC
45216-100CC
None216-100CC
$320,892
$325,782
$327,201
$328,750
$330,169
$342,102
$347,789
$347,544
$351,098
$353,725
$362,430
$387,146
$389,434
$396,788
$435,755
% Below
Base
1.52%
1.97%
2.45%
2.89%
6.61%
8.38%
8.31%
9.41%
10.23%
12.94%
20.65%
21.36%
23.65%
35.80%
The above portfolios all have a mixture of coal and natural gas resources used to
minimize RPU’s overall average energy costs. The results indicate that the availability of
low cost energy from the SLP unit 4 or an additional coal plant purchase is a lower cost
scenario than relying only on natural gas for the energy needs above the CROD level.
Details for each of the above cases can be found in Appendix III.
Summary
Based on the evaluations of several traditional resource options, Burns & McDonnell
offers the following conclusions about resource expansion plans.
1. The addition of capacity is required to meet the MAPP reserve requirements and
to satisfy RPU’s obligation to serve its load requirements over the period 2016 to
2030.
2. The review of traditional additions of natural gas and coal-fired options indicates
that the addition of coal capacity decreases the exposure to the supply and price
risk of natural gas.
3. The scenarios with SLP remaining operational provide lower evaluated costs than
the total retirement of SLP.
4. The lower cost scenarios include the addition of a 50MW value of coal capacity
or a low capital cost combined cycle type resource along with continued
investment in Twin Pac type combustion turbines to meet peaking needs.
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Resource Options Analysis
5. RPU will need to participate in a coal project to acquire the 50MW portion with
any economies of scale. The exposure to transmission congestion and delivery
problems would be reduced if the plant was developed in or near the RPU service
area.
6. The gas based resources can be developed solely by RPU. Consideration of the
capabilities of the gas infrastructure for the Rochester area will have to be
reviewed closer to the time that the facilities are needed to determine if pipeline
capabilities need to be expanded to support the expected gas demand.
Based on the above conclusions, the lower cost options from the traditional resource
portfolios were reviewed in greater detail in Part IV.
*****
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Part IV
Economic Analysis of Preferred Options
Part IV
Economic Analysis of Preferred Options
The development of the power supply options in Part III identified several low cost
evaluated options for RPU to consider in the long range planning. The lower cost plans
included a mix of coal and gas-fired resources to minimize the average energy costs.
With the long term plan identified, decisions on the near term issues can be made with
more certainty on their long term affects on RPU’s rates. This part of the report provides
a closer assessment of the long range options and provides recommendations on the near
and longer term power supply paths which RPU should pursue.
Options for Review
The lower cost evaluated options for RPU in Part III are shown in Table IV-1. The
options included reflect the various scenarios considered for the SLP plant.
Table IV-1
Lowest Evaluated Cost Traditional Resource Portfolios
45216-LMS100
45216-50Coal_CoalFirst
All216-50Coal_CoalFirst
45216-50Coal_SLPfirst
All216-50Coal_SLPfirst
None216-50Coal
$320,892
$325,782
$327,201
$328,750
$330,169
$342,102
% Below
Base
1.52%
1.97%
2.45%
2.89%
6.61%
The options include the following characteristics:
•
•
Coal energy is provided through SLP for the lower cost cases, with the possible
addition of a 50MW amount.
Gas resources include simple cycle combustion turbines similar to the Twin Pac
unit and an efficient unit with low capital and operating costs, represented by the
LMS100 unit currently becoming commercial from GE.
The options were evaluated with certain assumptions subjected to modification over a
range. The analysis used the @risk software from Palisades. The factors subjected to
variation are summarized in Table IV-2.
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Part IV
Economic Analysis of Preferred Options
Table IV-2
Assumption Variations Used to Evaluate Lower Cost Resource Portfolios
Min.
Likely
Max.
2.0%
2.7%
3.4%
$3.62
0.0%
$0.32
$4.82
1.0%
$0.42
$7.23
2.0%
$0.53
Coal Commodity 2006 Price ($/MMBtu)
Coal Commodity Real Escalation
Coal Transportation 2006 Price ($/MMBtu)
$0.35
0.0%
$0.55
$0.41
0.5%
$0.65
$0.52
1.0%
$0.75
Fuel Oil 2006 Price
$4.62
$5.44
$6.25
1.5%
5.5%
2.5%
6.5%
8.0%
3.5%
8.0%
Market Data:
On-Peak Market Energy Availability
On-Peak Market Price Adjustment
10.0%
-10.0%
40.0%
0.0%
50.0%
10.0%
New Unit Data:
Capital Cost Variance
-15.0%
0.0%
15.0%
$3.17
$954
$1,267
$3.73
$1,122
$1,491
$4.29
$1,290
$1,715
$0
$0
$0
$0
$0
$0
Load Escalation
Fuel Prices
Gas Commodity 2006 Price ($/MMBtu)
Gas Commodity Real Escalation
Gas Transportation 2006 Price ($/MMBtu)
Gas Transportation Escalation
Financial Rates
Inflation Rate
Interest Rate
Discount Rate
Resource Data
Coal Unit Data:
Transmission cost ($/kW-mo)
SO2 Allowance Cost ($/ton)
NOx Credit Costs ($/ton)
CO2 Tax ($/ton)
Particulate Costs ($/ton)
Emission costs for the coal units were varied using a @risk function. The detailed
assumptions for the above factors can be found in Appendix II.
The results of the risk analysis are summarized in Figure IV-1.
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Economic Analysis of Preferred Options
Figure IV-1
Probability Distributions for the Lower Evaluated Resource Portfolios
Probability Distribution of Net Present Values
Rochester Public Utilities
2.0
1.8
45216-50coal_coalfirst
Mean = $327,037
1.6
All216-50coal_coalfirst
Mean = $328,581
Probability (0.01%)
1.4
1.2
All216-50coal_SLPfirst
Mean = $331,568
1.0
45216-50coal_SLPfirst
Mean = $330,067
0.8
0.6
None216-50coal
Mean = $342,826
0.4
All216-LMS100
Mean = $347,416
0.2
0.0
250
300
350
400
450
500
NPV of Costs ($Millions)
The results of the risk analysis indicate that the portfolios with approximately 100MW of
coal energy provided through SLP Unit 4 and an additional 50MW result in the lower
cost options. The scenario with the LMS100 case is shifted up due to the low probability
that the capital cost will remain at the level of the initial units GE is bidding to obtain
market acceptance. The portfolio with no SLP and 50MW of new coal capacity shows a
broader distribution primarily due to the variance in capital and interest costs.
The four portfolios with the more narrow distribution indicate the following:
1. The SLP Unit 4 should be maintained in service.
2. An approximately 50MW amount of additional coal capacity provides value to
RPU in offsetting the exposure to gas based energy.
3. Using the SLP Units 1-3 as regulatory reserves operated on natural gas or retiring
them and replacing the capacity with a Twin Pac unit makes little difference since
the energy expected to be generated by them is negligible.
The above analysis has been performed on a net present value basis. A review of the
total, demand related and energy related annual costs provide an insight to determine if
the timing of the coal units might make a difference in the evaluation. Due to RPU’s low
load in the winter until about 2020, additional coal capacity would be difficult to fully
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Burns & McDonnell
Part IV
Economic Analysis of Preferred Options
utilize. To review this issue, the annual costs of the portfolios with the LMS100 and the
50MW coal purchase were compared. The annual total costs for the cases are shown in
Figure IV-2. The total costs for the two cases cross about 2020, indicating that the
energy from the coal unit does not begin to overcome its high capital cost until this point.
Figure IV-2
Total Annual Costs for the 50MW Coal Case and the LMS100 Case
($000)
Total Annual Costs
$120,000
$100,000
$80,000
$60,000
$40,000
$20,000
$0
2015
2017
2018
2019
2020
2021
2022
45216-50
2023
2024
2025
2026
2027
2028
2029
2030
All216-LMS100
A case was developed which reflected this type of sequencing for the gas and coal units.
The net present value for the revised case was $288,674,000 or approximately 10 percent
below the lowest evaluated case above. Application of the risk analysis to this case was
performed and is included in Figure IV-3.
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Part IV
Economic Analysis of Preferred Options
Figure IV-3
Probable Net Present Values
With Coal in 2020 Case
Probability Distribution of Net Present Values
Rochester Public Utilities
2.5
2.0
45216-50coal_coalfirst
Mean = $327,037
45216-LMS100-50Coal
Mean = $290,082
Probability (0.01%)
All216-50coal_coalfirst
Mean = $328,581
1.5
All216-50coal_SLPfirst
Mean = $331,568
45216-50coal_SLPfirst
Mean = $330,067
1.0
None216-50coal
Mean = $342,826
0.5
All216-LMS100
Mean = $347,416
0.0
200
250
300
350
400
450
500
NPV of Costs ($Millions)
The risk analysis shown above indicates that combining the benefits of the LMS100 case
with the 50MW coal case provides a lower risk case than the all gas cases. The major
advantage is the delay of acquisition of the coal unit until its energy can be more fully
utilized. This allows RPU to capture the early benefits of the LMS100 portfolio and the
later benefits of the 50MW coal portfolios. Therefore, the sequencing of the unit
additions should be considered with the gas unit in 2016 and the coal purchase in 2020.
Near Term Issues
The above analysis provides an insight to the course which RPU should pursue over the
next ten years. The balance of loads and resources using the above 45216-LMS10050Coal case is shown in Figure IV-4. As shown, the resource additions will still require
that RPU acquire seasonal capacity to maintain its MAPP reserve requirements. The
costs for these acquisitions have been included in the analysis. Figure IV-5 is an
approximate energy dispatch curve to provide an indication of the sources of energy for
the RPU in 2030.
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Part IV
Economic Analysis of Preferred Options
Figure IV-4
RPU Balance of Loads and Resources
45216-LMS100-50Coal
700
600
500
MW
400
300
200
100
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Hydro
SMMPA CROD
SLP
New Coal
Existing CT
New CT
Peak Forecast
Peak +15%
LMS100 CT
Figure IV-5
Approximate 2030 Energy Sources for RPU
600
Peak Market Energy
83,287 MWh
500
Peak Demand = 537 MW
Total Energy = 2,682 GWh
Load Factor = 57.1%
2 X 49 MW CTs
40,701 MWh
400
100 MW LMS100 CT
71,729 MWh
Load (MW)
300
45 MW SLP 227,540 MWh
2.7 MW Hydro
21,049 MWh
New 50 MW Coal 349,411 MWh
200
100
216 MW CROD
1,888,344 MWh
0
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Hour
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Part IV
Economic Analysis of Preferred Options
Silver Lake Power Plant
The longer term portfolio options indicate that it is advantageous to continue the
operation of the SLP, especially Unit 4 on coal. RPU should identify and implement
strategies that will result in reduced air emissions and allow for continued operation on
coal at an increased capacity factor. A boiler assessment should also be performed to
determine if it would be beneficial to replace components which have had tubes plugged
over the years to continue operation and delay maintenance investment.
Units 1-3 should be maintained in sufficient status to allow MAPP accreditation. Since
these units are capable of being fired on natural gas available at the site, fuel switching
may be an option to emission controls through the addition of flue gas based emission
control devices. The cost of maintaining these units should be compared to replacing
them with another resource closer to the 2016 time frame.
Maintaining the SLP plant also allows continued servicing of the Franklin Heating
Station contract with excess steam and avoids any need to assess options for disposition
of the contract with the Mayo Clinic.
Coal Unit Participation
There are several opportunities for RPU to participate in coal plants being developed in
the regional. The units which are inviting participants are scheduled for in service dates
of approximately 2010. Analysis of the coal portfolios indicates that RPU does not need
coal capacity until after 2016 and more probably closer to 2020 based on the current
forecast of load. Therefore, there is no urgency for RPU to identify a resource in which
to participate.
RPU should maintain contact with regional utilities who may be considering a resource
closer to the time when RPU could absorb the energy. It is expected that additional units
will be required by others at a similar time that RPU is in need of coal energy.
Transmission Investment
RPU should aggressively pursue the upgrading of the transmission system. Certainly the
firm delivery of the CROD energy should be regained since RPU is paying the SMMPA
for firm all-requirements capacity and energy up to 216MW. This should be the number
one priority of RPU in discussions with SMMPA.
RPU is participating in studies with other utilities on transmission projects which would
improve the import capabilities into the service area. It is expected that the approach to
improving the transmission system reliability into the RPU service area will be
determined within the next 12 to 18 months. Currently, the state of the transmission
system does not permit reliance on the market for firm purchases. Therefore, RPU will
only be using the transmission system for non-firm energy deliveries above the CROD
amount until increased firm transfer capability is available into RPU’s area. Sufficient
generation capacity will need to exist within RPU’s service area to firm up the
transmission system.
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Economic Analysis of Preferred Options
In discussions with RPU, it is uncertain what will happen to the CROD amount past
2030, which is the current termination date of the SMMPA contracts with its members.
If the CROD energy is not available, then RPU will be in need of essentially 250MW of
coal capacity. This amount of capacity requirement would support the construction of a
unit within the RPU service area by RPU as the sole owner. With this amount of capacity
inside the RPU service area, the import capability required of the transmission system
would be reduced.
Due to the length of time it takes to construct transmission lines and complete the
upgrade, it is recommended that RPU develop a parallel project to install similar Twin
Pac units to maintain the required probable outage hour levels as would be maintained
with the transmission upgrade. Should the upgrade be delayed, the generating units could
be installed within RPU’s service area and used for transmission reliability service until
the upgrade was completed.
Summary
Overall, RPU is in relatively good condition to meet its load requirements for several
years without any additions to its resource mix. Challenges to RPU in the area of
transmission reliability and understanding what future market operation impacts will
bring are typical of the environment in which utilities operate today and will be a primary
focus of RPU. Plant related issues will include the investment necessary to bring the SLP
into compliance with environmental regulations currently taking affect.
Based on the analysis performed for RPU in this effort, Burns & McDonnell is of the
opinion that RPU should:
Over the next few months:
1. RPU is not in need of additional coal capacity with the current CROD level
and load forecast until approximately 2020. Therefore, participation in any
coal plant currently being developed does not appear to be advantageous.
2. Pursue firming up the transmission system to allow firm delivery of the
CROD amount of 216MW.
3. Consider taking options on approximately 100 acres of land within the RPU
service territory near a high pressure gas line and transmission facilities under
RPU control for installation of future combustion turbine capacity.
4. Develop a parallel path project to accelerate installation of combustion turbine
capacity required in the long term plan to maintain system reliability should
the selected transmission upgrade project be delayed.
5. Develop the upgrade plan and timing for SLP Units 1-4 for the addition of
emission controls and other life extension modifications.
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Economic Analysis of Preferred Options
Between 2005 and 2015:
1. Complete the transmission upgrade or the installation of additional
combustion turbines.
2. If the transmission upgrade is completed, compare the market conditions at
the time to the installation of additional generation resources within the
service territory.
3. Review the then current generation technology, fuel options and RPU needs
against the long range plan developed herein to determine if new technologies
or reduced RPU needs have usurped the analysis and recommendations
associated with current options.
4. Complete the modifications to the SLP Unit 4. Initiate the emission controls
to be applied to Units 1-3 in light of their expected operation.
5. Around 2010, depending on the status of the RPU system needs, the regional
market, and other technology considerations for resource options, RPU should
consider taking an option on approximately 1500 acres to support the
development of a coal-fired generation plant within the RPU service territory.
The site should have access to rail, electric transmission and water
infrastructure to support several hundred megawatts of generation.
6. Around 2012, assuming that new generation is required in accordance with the
long range plan and that generation has not been installed in connection with
the transmission issue, begin the process for installation of approximately 50
to 100MW of natural gas-fired generation for an in service date of 2016. The
generation should be low capital cost with as low an operating cost as is
consistent with expected operating capacity factors.
Between 2015 and 2030:
1. Install generation as necessary and prudent using the long range plan prepared
above as a guide and comparing the assumptions used herein to the existing
market conditions. The generation additions should follow the in service
schedule identified in portfolio 45216-LMS100-50Coal.
2. If development of a local coal unit appears likely, purchase the necessary land
and begin the development process around 2015 for an in service date of
2020.
*****
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Demand Side Management and Renewable Options
Part V
Demand Side Management and Renewable Options
Rochester Public Utilities (RPU) is active in promoting demand side programs to its
customers to help conserve electric energy, and reduce demand in its service territory.
Numerous programs are offered to assist customers in reducing their electrical
requirements. The development of the financial plan for RPU requires the assessment of
the impacts that customers are making, and could make, in the reduction of future
electrical requirements, and delay the need for additional capacity.
Current DSM Efforts
Utilities in Minnesota are required to invest a portion of the revenues into DSM
programs. For RPU, this amounts to approximately $1,300,000 per year. RPU has
created a department to manage the budget associated with DSM programs. The
department is staffed with individuals who work with customers to promote the various
DSM programs in place, provide energy audit services, and look for new programs to
implement.
RPU is working with the cities of Owatonna and Austin, Minnesota on DSM offerings.
These utilities have formed the Triad, which allows the cities to share personnel, study
costs, and other assets in order to reduce the overheads and program costs associated with
the DSM programs.
The programs offered by RPU include:
•
Conserve and $ave – a program to promote the use of Energy Star appliances and
other high-efficiency equipment in place of lower efficiency options. The
program is open to residential, commercial, and industrial customers. Rebates are
provided for a variety of appliances, equipment, and lighting options.
•
Partners Load Management – a program to allow RPU to control central air
conditioner compressors and electric water heaters during times of high demand
and reduce the load on the system.
•
Energy Audits – these are provided to customers upon request.
The cumulative estimated reductions due to these programs as of January 1, 2004 are:
•
Energy savings of 7,860 MWh.
•
Demand savings of 5,960 kW.
Using an average of $600/kW of installed capacity and $55 per MWh as an avoided
energy cost, the programs have provided approximately $3,500,000 of reduced
investment cost and $432,000 of annual energy savings.
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Study Approach
A variety of tasks were undertaken to develop the expected impacts that current and
potential DSM programs could provide in reducing the RPU need for additional power
supply resources. These tasks included an end use survey of RPU’s customers, a benefit
cost analysis of RPU programs, and an estimation of the electric energy and demand
reduction potential for RPU’s customer base.
In addition to these tasks, public involvement was solicited to discuss options and
considerations from the ratepayer’s perspective. RPU developed a task force made up of
a representative from the various rate classes and other involved citizens served by RPU.
End Use Survey
RPU retained Morgan Marketing Partners of Madison, Wisconsin to perform an end use
survey of their residential and commercial customers. Large industrial customers were
not surveyed due to the unique nature of their loads. These customers are actively
involved in reducing the consumption of their processes. Also, RPU devotes a staff
person to work with these individuals to help them reduce their consumption.
The survey questionnaire was developed and mailed to 1,497 residential, and 2,193
commercial and industrial customers. These responses provided a statistically significant
result and were considered to be acceptable for use in analyzing the appliance inventory
in the RPU service territory. The questionnaires and a summary of the results of the
survey are included in Appendix IV.
Benefit Cost Analysis
In addition to the end use survey, RPU needed to perform a benefit cost analysis of the
various DSM offerings applicable to RPU. RPU retained the Center for Energy and the
Environment (CEE) to perform this analysis. The CEE is a not-for-profit corporation in
Minnesota that is funded by utilities to assist with DSM program analysis. The CEE is
very experienced in performing analyses of DSM programs in accordance with the
requirements of the Minnesota state regulatory bodies for utilities. The CEE works with
the Triad and has the information on the various programs offered, avoided costs, and
other information necessary to perform the benefit cost analysis.
The analysis of avoided costs for RPU is different from the other members of the Triad in
that the other Triad members are full service customers of SMMPA, while RPU takes a
portion of its requirements from SMMPA and a portion from other resources. The RPU
avoided costs vary between seasons based on whether the demand is being provided
solely by SMMPA or from both SMMPA and RPU resources.
The analysis looked at the benefit and costs using the four typical tests for DSM
programs. These included:
•
Revenue requirements – this test looks at the benefit cost from the RPU
perspective;
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•
•
•
Demand Side Management and Renewable Options
Rate impact – this test looks at the benefit cost from the non-participant
perspective;
Participant – this test looks at the benefit cost from the participant’s perspective;
Societal – this test looks at the benefit cost from society’s perspective.
A variety of conservation programs were selected for the residential and commercial
sectors. The initial assessment of the programs identified that the avoided costs for RPU
needed to be revised when compared to the other Triad members. RPU has a different
cost structure due to the limitation of the demand and energy received from the SMMPA.
This means that the avoided demand charge is different through the year. Also, the
method of meeting demand in the summer is through combustion turbine capacity, which
is lower cost than that of the SMMPA demand. This information was updated in the CEE
model for RPU.
The program costs for each of the programs were provided by RPU to CEE for use in the
assessment. These costs included staff, rebates and incentives, advertising, and other
costs associated with maintaining the various programs. The model used by CEE
processed the information with regard to the specific test being developed. The
appliances and programs selected for review were based on the experience of CEE in
performing these tests for a variety of utilities in Minnesota. The results are shown on
Table V-1.
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Table V-1
Summary of Benefit Cost Analysis Results
Cost Benefit Analysis for Rochester Public Utilities
2004 Results
Program Name
RESIDENTIAL
Electric VSD/ECM Motors
Clothes Washer (Elec WH)
13 SEER Central A/C
14 SEER Central A/C
Ground Source Heat Pumps (3 ton unit example)
Room A/C
Dish Washer (Elec WH)
B/C Ratio
Revenue
Rate Impact
Requirements
Measure
Participant
Societal
5.53
4.14
4.10
3.53
2.31
1.70
1.47
1.09
1.28
2.01
1.86
1.27
1.14
0.80
2.21
0.89
1.13
1.07
0.98
1.89
1.60
1.83
0.96
1.95
1.73
1.08
1.52
0.98
Refrigerator
Dish Washer (Gas WH)
CFL's
Clothes Washer (Gas WH)
Load Management
0.93
0.64
0.60
0.42
0.00
0.53
0.47
0.30
0.35
0.00
2.50
0.98
19.48
0.24
38,950.33
0.83
0.43
0.59
0.10
0.00
COMMERCIAL
VSD (200 hp)
Premium Efficiency AC 3-Phase Motor (200 hp)
ECPM (1.5 hp)
VSD (3 hp)
40.34
4.02
2.99
2.92
1.61
1.10
0.94
1.06
5.21
7.00
8.90
1.12
6.38
3.55
2.33
0.96
Air-Conditioners EER=11.0 (7.5 tons)
Lighting Retrofit - Exit Sign (20W Incan. to LED)
Lighting Retrofit (F40T12 4 lamp to F32T8 LP 4 lamp)
Premium Efficiency AC 3-Phase Motor (1.5 hp)
GSHP (5 ton unit example)
ECPM (0.1 hp)
0.83
0.66
0.57
0.20
0.13
0.11
0.54
0.45
0.40
0.18
0.12
0.10
2.55
4.29
6.95
3.36
2.20
2.06
0.69
0.57
0.53
0.19
0.12
0.11
The results indicate that most of the residential and all of the commercial programs
evaluated are beneficial from the Participant perspective. However, only about half of
the programs are beneficial from the other three perspectives. All of the appliances are
currently included in the Triad Conserve and $ave program. The load management
program does not look beneficial at this point due to the excess capacity and the cool
summer weather that has depressed demand during the summer months. With this
combination, RPU does not need to cycle air conditioners or water heaters to reduce
demand. The Participants see this as a significant benefit since they are still provided a
credit from RPU for having the switch installed.
CEE has recommended that the overhead costs and incentives for the Triad should be
reviewed to improve the number of programs with a benefit cost ratio greater than one.
The Triad has developed a report on the modifications to the demand side management
programs currently in effect and additional programs to be undertaken in their report
“Next Level”. This report identifies numerous adjustments to the programs in the areas
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of incentives, education, and expected participation levels. A copy of the report is
included in Appendix IV.
Task Force
As part of the assessment of DSM programs and opportunities, RPU created a Task Force
made up of representatives from residential, commercial, and industrial RPU rate classes.
In addition, representatives from local environmental groups were included. There were
12 members in total. The group met three times to discuss the issues associated with
DSM programs. The first meeting was held to educate the group on the current supply
and demand side issues and opportunities facing RPU. The second meeting provided
information about the end use survey and the benefit cost study being prepared for RPU.
The third meeting was to provide the estimated impacts of various DSM activities and to
collect feedback and recommendations from the group on how RPU should proceed.
In general, the Task Force had the following recommendations:
1. Programs involving rebates should be simple and provide immediate benefit to
the customer.
2. Conservation programs and other efficiency enhancing programs require
continual education of the customers.
3. Revising rate structures to support demand side and renewable energy efforts
should be pursued.
4. Implementing time-of-use rates should be pursued.
The summary of recommendations from the group is included in Appendix IV.
Review of Conservation Potential
The potential for electrical energy and demand reductions on the RPU system were
estimated using the end use survey data and typical savings information from a variety of
sources used to estimate the reductions by appliance or facility change. The end use
survey information provided an estimate of the number of appliances on the system that
were available for enhanced efficiencies. The appliance usage was estimated to
determine the amount of energy savings which could result from a conversion. The
expected usage patterns through the day were approximated in order to estimate total
demand reduction. Assumptions for energy reductions were obtained from Energy Star
calculators that are available from the Department of Energy, the assumptions in the
Benefit Cost study and other sources.
Residential Potential
The residential customers of RPU are typical of households across the US. The use of
central air conditioning is widespread. The availability of natural gas has led to a high
utilization of gas-fired heating systems and water heaters. Therefore, the maximum
electrical demand is in the summer season. (See Figure II-6 in Part II for the RPU annual
load shape.)
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The number of central AC units older than 5 years provided an estimate of the number of
units that had a SEER of below 8. Units installed within five years have had a SEER of
at least 10. From the survey, an estimated 20,000 central AC units have a SEER of 8 or
less. The benefit cost analysis identified that conversion of this appliance to a SEER of
13 and14 was beneficial from all perspectives. In addition to the AC units, conversion of
the blower motor in the air handler was also beneficial from all perspectives. These two
categories represent the largest efficiency enhancement benefits available from the
residential sector.
Another category of appliances with a high potential for savings are the washer and
dryers. Energy Star washers reduce the water necessary to clean clothes and also remove
more water than traditional washers to reduce the drying time necessary. New efficient
dryers have moisture sensors that determine when the clothes are dry. From the benefit
cost study, it is seen that the current level of benefits from the Participant’s perspective
do not make replacement of units with an Energy Star rated unit attractive. This is
primarily due to the high cost of the replacement appliances.
Other kitchen appliances provide minimal benefit from all perspectives. Compact
fluorescent lights (CFL) provide significant benefits from the Participant’s perspective.
From the end use survey, it appears that over half of the homes in RPU’s service territory
have some amount of CFLs installed. The residential CFL replacements provide
primarily energy reductions with minimal impact on the RPU peak.
Table V- 2 provides a summary of the maximum potential reductions for the residential
sector estimated from a variety of efficiency improvements for appliance conversions or
for change out of central AC units to a SEER 13. The number and efficiency of existing
appliances was determined from the end use survey.
An area of interest to some utilities is the conversion of electric appliances to natural gas,
where gas is available. A list of appliances that could potentially be converted and the
expected electrical reductions is also included in Table V- 2.
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Table V-2
Estimated Maximum Potential Reductions
Residential RPU Customers
Estimated Savings
Residential
Energy Star Conversions
Central Air more than 5 years old
Room Air more than 5 years old
Refrigerator more than 5 years old
Freezer more than 5 years old
No Compact FL
W ashing Machine
Dishwasher-heated drying (elec DHW )
Dishwasher-heated drying (gas DHW )
Quantity
20,484
2,618
13,176
1,231
15,214
38,705
1,175
8,617
Unit
Customers
each
each
each
Customers
Customers
Customers
Customers
Other Options
Electric heat-Main
Dryer
Spa/Hot tub
W ater Heater
Range/Oven
788
30,342
585
4,375
30,704
Customers
Customers
Customers
Customers
Customers
Demand
Energy
Each
Total
(MW)
(kWh)
(MWh)
346
7,091
4.7
58
151
0.1
95
1,252
0.2
80
98
0.0
124
1,887
0.0
361
13,973
2.4
103
121
0.0
45
388
0.0
24,960
7.4
Total Use
Total
Demand
Each
(kWh)
(MWh)
(MW)
43,174
34,021
n/a
995
30,190
5.2
1,680
983
n/a
4,811
21,048
1.5
256
7,860
n/a
94,103
Commercial Potential
The commercial sector of RPU reviewed in the survey is made up primarily of small
commercial office buildings, shopping malls, restaurants, and other typical buildings.
Estimates of reductions for the commercial sector required comparing end used
information from the survey with industry data, forecast sales by class, correlation with
SMMPA data in its Integrated Resource Plan and other factors.
References and calculation tools used in the commercial assessment include:
•
End-use Survey of RPU Commercial Customers: A survey sent to 2,145 of
RPU’s commercial customers. Used to determine quantities of customers and
appliances.
•
eQUEST: A computer simulation program that is a full implementation of the
widely recognized DOE 2.2 calculation engine. It can perform hourly
calculations for an entire year and incorporates local weather data.
•
U.S. Department of Energy – 2004 Buildings Energy Data Book: This reference
includes over 100 pages of data tables dealing directly with buildings and their
energy use.
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•
Energy Star Homepage: Web site with a variety of reference material and
calculation tools for various technologies. Estimates that involved use of these
calculation tools includes room air conditioners, freezers, washing machines,
dishwashers, computers, printers, and copiers.
•
SMMPA Integrated Resource Plan 2003-2018: In particular Table VII-8,
“SMMPA Sales Profile”, which has an end-use breakdown of electricity use for
commercial customers. The metric used is the Energy Use Indices (EUI) which
has the units of kWh/yr/sq ft.
There are a number of assumptions included in the DSM measure energy reduction
estimates for commercial customers that involve usage estimates per square foot of
commercial building space. A review of the 2,145 survey population of customers used
in the survey indicated the following:
•
•
•
•
61.5% consisted of small commercial properties totaling 5,000 sq. ft. or less,
28.8% were 5,001 – 25,000 sq. ft.,
9.1% were 25,001 – 250,000 sq. ft. and
0.6% were 250,000 or more sq. ft.
Due to the effort in the existing DSM programs on the large customers, the focus of the
analysis in this study was on the commercial space of less than 25,000 square feet. A
review of information included in the SMMPA IRP provided that RPU commercial
customers account for 50 percent of the SMMPA commercial customers’ energy use.
Based on other information about the square feet of commercial office space in the
member cities’ service areas, it was determined that RPU’s commercial customers
account for 50 percent of the SMMPA commercial customers’ floor space (i.e., 50
percent of 67,210,000 sq. ft. or 33,605,000 sq. ft.).
The above area of commercial space was used to derive an estimated energy usage. One
reference for determining the energy usage was data from the US Department of Energy
– 2004 Building Energy Data book. To determine the potential reduction for estimating
DSM impacts, it was assumed that the DSM measures will have 100 percent penetration.
In other words all customers that are candidates for a given DSM measure will implement
the measure.
The approach used to determine the potential energy savings for RPU’s commercial
customers included three basic steps. These are:
1. Identify the appliances and energy using systems that account for the majority of
overall electric consumption.
2. Use the end-use survey to determine the number of customers, or quantity of
energy using devices identified in step 1. In some cases the DOE – 2004
Buildings Energy Data book was used as a reference for average typical
commercial customers.
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3. Use engineering calculations to determine the energy savings for the devices and
quantities identified in steps 1 and 2 respectively.
The results of the analysis are summarized in Table V-3.
Table V-3
Estimated Maximum Potential Reductions
Commercial RPU Customers
Estimated Savings
Commercial
Efficiency conversions
Central Air more than 7 years old
Room Air more than 7 years old
Refrigerator more than 7 years old
Freezer more than 7 years old
No Compact FL
Washing Machine
Dishwasher-heated drying
Non electronic ballast flourescent
VSD on 3 HP AC unit fans
Computers
Printers
Copiers
Quantity
936
226
2,214
858
1,386
515
67
1,639
3,595
18,190
7,096
5,103
Unit
Customers
each
each
each
Customers
Customers
Customers
Customers
each
each
each
each
Other Options
Energy Using System/Device
Electric heat-Main
Dryer
Range/Oven
Water Heater
Quantity
118
498
44
568
Unit
Customers
Customers
Customers
Customers
Energy
Demand
Each
Total
(MW)
(kWh)
(MWh)
3,948
3,695
5.3
121
27
0.1
143
315
0.2
120
103
0.0
4,015
5,565
2.0
722
372
0.1
78
5
0.0
9,489
15,552
8.8
5,489
19,734
0.3
201
3,656
1.2
180
1,277
0.4
324
1,653
0.5
51,957
18.8
Total Use
Each
Total
Demand
(kWh)
(MWh)
(MW)
86,348
10,189
n/a
1,493
743
0.4
384
17
n/a
9,622
5,465
2.4
16,415
Information for both the commercial and residential impacts determined above are
included in Appendix IV.
Load Shape Modification Programs
Utilities have been controlling demand on the system since the late 1970’s through the
use of load management programs, interruptible rates and other programs that entice the
customer to allow the utility to remove a portion of their load during high usage times.
The economics of these programs are dependent on the cost of the marginal capacity on
the system. As the utility moves between deficit and excess capacity conditions, the
value of the program changes.
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Another type of program which is gaining prominence is called a Demand Response
Program. These programs are trying to bring the consumption side of the industry into
the market to allow a demand response feedback to the hourly pricing. As wholesale
markets move to day ahead pricing with load bidding into the market, these programs are
becoming more useful.
The current wholesale market is discounting the value of capacity. Although the forward
market (in the post 2010 time frame) is seeing the need for additional base load facilities
which have high fixed cost, the current market is not pricing capacity above that for a
combustion turbine, if that. However, the price for energy is increasing as more of the
marginal energy produced is from natural gas-fired units. It is expected that this market
will continue in this manner for several years at least. No significant structural change to
this pricing on the wholesale markets operated by PJM and MISO is expected until base
load units are added to the system beyond 2010.
Load Management
RPU has approximately 8,800 customers with load management switches installed. The
evaluation of load management programs in the Benefit Cost Study revealed that there
was no benefit from any perspective except for the Participant. This is due to the current
capacity situation in RPU and the mild summer experienced in 2004. With the expected
return of capacity from the Silver Lake Plant over the next several years, RPU has
sufficient capacity to meet its obligations. Therefore, there is no cost avoided for the
reduction in peak.
The primary benefit from the load management program will be from the opportunity to
market excess capacity. Also, having the load management system provides some
increased system security during times when the transmission capacity into RPU is
constrained and load needs to be curtailed in the RPU area.
Another aspect of the load management program is that the appliances controlled are
primarily central AC units and electric water heaters. Over the next several years,
replacement units will be installed for the approximately 20,000 central air conditioning
units with SEER ratings below 8. These units will be replaced with AC units with a
SEER rating of 13 or better. These newer units have a lower demand than the older units.
Also, since many of the units were installed oversized, smaller units may be used for the
replacements. These two factors lead to the conclusion that the amount of reduction per
point for the load management system will decline over the next five years. It is
estimated that this reduction will be approximately .1 to .2 kW per central AC unit.
Change out of electric water heaters to gas units would also reduce the amount of load
under control.
Demand Response Programs
Demand response programs are gaining in popularity with utilities as markets move to
the day ahead pricing structure used by the PJM, the MISO Day 2 market to start in
March, 2005 and as promoted by the FERC in the Standard Market Design. These
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programs have a variety of definitions, but in general, entail using time-of-use metering
or notification devices and rates to encourage consumers to reduce electric energy
consumption during periods of high energy pricing. As the electric wholesale market
moves to the day ahead of energy pricing, the knowledge of tomorrow’s costs are more
readily determined. These then can be shared with the customers to allow them to control
their consumption during the periods when the pricing is above their threshold.
There are two broad categories of demand response programs. The first is applicable to
markets where the load is bid into the market, such as will exist in the MISO area when
its Day 2 operations are implemented. This conversion is expected to occur on or after
March 1, 2005. In this program, qualifying customers are paid to reduce their demand by
the level contracted with the utility. Verification of the amount of reduction is required.
A set strike price for the capacity is often provided, such that there is no activity of the
control unless the price exceeds a set level. In these programs, the customer is actually
paid by the utility to reduce consumption at an agreed to rate. Qualifying customers are
typically those that can reduce at least 100kW or more.
The other type of program incorporates the residential and small commercial customers.
In this type of program, the customer is sent information on the time-of-use cost of the
electricity. The customer then makes the choice on whether to shift usage away from the
higher priced times to lower priced periods. This type of program simply results in the
customer realizing a reduction in their bill due to avoiding the higher cost periods.
The first type of program could be used by RPU to release capacity for sale in the day
ahead of the MISO market. Therefore, although the demand reduction has no specific
value to RPU from an avoided capacity purchase, there may be value from the
opportunity cost of potential sales and positioning for future years when capacity may be
tighter. The development of the MISO Day 2 market on or after March 1, 2005 will need
to be monitored to determine if this type of program would be of benefit and the revenues
to the qualifying participants significant enough to gain a critical mass for participation.
The use of a demand response program by RPU for the residential and small commercial
customers would require creating time-of-use pricing information for transmission to the
customers who wish to participate. This pricing could be based on the MISO Day 2
market, which will provide the day ahead hourly pricing for the next day. Adjustments to
this price for RPU costs would be made and forwarded to the participating customers.
Although time-of-use programs have been offered for several years, recent technology
and communication changes have allowed the programs to be lower cost to implement.
Savings resulting from the programs have been discussed in recent markets, such as
California’s during its crisis, and found to be significant when the price is above the
customer’s threshold. Although claims of 2kW per consumer in the program have been
made by companies promoting the systems to support the programs, RPU would have to
perform a pilot to determine what the level of pricing would need to be to influence the
consumers in RPU’s service territory to make any meaningful adjustment to their usage
patterns.
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Finally, it is important to note that from a customer’s perspective, demand response
strategies are effective only for those that are willing to change their energy usage habits.
Contrarily, demand response strategies will not benefit those that are unwilling to change
their usage habits. Therefore, selling DSM must be promoted as a conservation strategy
and targeted to those that are willing to change their energy usage habits.
RPU DSM Program
The estimation of actual DSM impacts from various programs that have been or could be
implemented by RPU allows a determination of the potential influence on the need for
supply side resources. Since the DSM programs require acceptance by RPU customers,
one unknown in the equation is the amount of participants in any program. The
companion uncertainty to the level of participation is the amount per year who will
participate.
In addition, natural replacement of appliances over time tends to reduce the average
consumption since the replacement models have improved efficiencies. For instance,
central AC unit efficiencies were increased to a minimum SEER of 10 in 1992. New
standards are set to take affect in 2006 that increase the minimum SEER to 13. With this
natural increase in efficiencies, the affect on RPU’s load could be a reduction of
approximately 30 percent of the energy over the approximately 20,000 central AC units
that are older than five years. Major reductions would come from units that were
installed prior to 1992. Similar improvements would come about from natural
replacements of other appliances such as refrigerators and dishwashers.
In addition to the traditional impacts from DSM programs, RPU is also developing a
cogeneration system with the Mayo Clinic’s Franklin Heating Plant. This cogeneration
effort will remove approximately 5MW (electric) from the system in 2008 and grows to
approximately 15MW (electric) in 2015. This demand and its associated energy are
removed from the electric system.
Using the information provided in Table V-2 and V-3 for the efficiency improvements
and the benefit cost analysis Table V-1, estimates of reduction were developed. The
resultant expected levels of reduction per year were identified to allow a determination of
the impact on the load forecast as adjusted for DSM programs. A summary of the
projections are shown in Table V-4. These projections include efforts to achieve
reductions that are influenced by RPU and naturally occurring efficiency improvements
in the existing appliance inventory. It is assumed that the naturally occurring efficiency
savings would be achieved by 2015. Beyond 2015, the ongoing DSM activities of RPU
would be the source of additional savings.
Due to the efficiency standards taking affect in 2006 and the need to develop the
educational and incentive programs to be implemented to achieve savings, it was
assumed that no savings would accrue in 2005 beyond the existing DSM program
impacts. Starting in 2006, one third of the savings would accrue each year until the full
savings of approximately 9,000 MWh annually would be achieved. It is estimated that
Rochester Public Utilities
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Part V
Demand Side Management and Renewable Options
these efficiency improvements would be completed after ten years and the savings from
these areas would then remain constant after 2015. For purposes of estimating savings,
one half of the Table V-4 projections are to be included in the RPU DSM future savings,
while the remainder is considered to be an aggressive DSM alternative.
Table V-4
Estimated Additional DSM and Efficiency Impacts
To RPU Energy Forecast
(MWh)
Program
Residential
Central AC
Blower Motors
CFLs
Refrigerators
Gas switched appliances
Commercial
Central Air more than 7 years old
No Compact FL
Non electronic ballast flourescent
VSD on 3 HP AC unit fans
Computers
Printers
Copiers
Gas switched appliances
Total
Cumulative Total
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
0
0
0
0
0
236
692
63
42
83
475
1,391
127
84
168
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
709
2,076
190
125
250
0
0
0
0
0
0
0
0
123
185
517
658
122
43
55
250
248
373
1,040
1,322
245
86
111
503
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
370
556
1,552
1,973
365
128
165
750
0
0
3,069
3,069
6,170
9,239
9,208
18,447
9,208
27,656
9,208
36,864
9,208
46,073
9,208
55,281
9,208
64,489
9,208
73,698
9,208
82,906
The estimated demand and energy impacts, including the Mayo cogeneration project, are
shown in Table V-5. The Original Energy Forecast was the energy projection used for
Phase I. The Existing DSM Impacts include the existing RPU DSM program estimated
savings. The Future DSM impacts are one half of the saving shown in Table V-4. The
Revised Energy Forecast is determined by subtracting the Future and Existing DSM
Impacts from the Original Energy Forecast. The Aggressive Energy Forecast includes
the remainder of the savings estimated in Table V-4.
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Part V
Demand Side Management and Renewable Options
Table V-5
Estimated DSM and Efficiency Improvement Impacts
Demand (MW) and Energy (MWh)
Year
Annual
Peak
Demand
Adjustments
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
277
284
292
300
308
316
325
334
343
352
362
16.6
21.8
23.1
25.1
25.3
26.9
29.2
31.8
34.9
38.4
42.8
Adjusted
annual Original Energy
Peak
Forecast
260
262
269
275
283
289
296
302
308
314
319
1,377,767
1,414,967
1,453,171
1,495,732
1,532,702
1,574,085
1,616,585
1,663,932
1,705,059
1,751,096
1,798,375
Future
DSM
Impacts
Existing
DSM
Impacts
Revised
Energy
Forecast
0
1,535
4,620
9,224
13,828
18,432
23,036
27,641
32,245
36,849
41,453
8,590
56,310
64,550
72,650
80,650
88,500
96,210
103,790
111,150
118,450
125,770
1,369,177
1,357,122
1,384,001
1,413,858
1,438,224
1,467,153
1,497,339
1,532,501
1,561,664
1,595,797
1,631,152
Aggressive
Energy
Forecast
Renewable Energy Options
The state of Minnesota has implemented requirements for renewable energy under
Minnesota Statute 2003 Chapter 216B. Retail electric utilities must offer customers an
opportunity to purchase, at cost, renewable energy beginning July 1, 2002. RPU is
offering customers the opportunity to purchase this energy under its Wind Power
program in association with SMMPA.
Utilities are required to generate or procure renewable energy sufficient to ensure that by
2005, 1 percent of total retail sales are from renewable energy. This “Renewable Energy
Objective” (REO) ramps up by 1 percent each year until 2015 when a total of 10 percent
of retail sales must be from renewable energy. The REO also requires that, of the
renewable generation required, in 2005 at least 0.5 percent be from biomass energy
technology, increasing to 1.0 percent by 2010.
The integration of this energy into RPU’s resource mix will require adjustments to the
dispatch determined in the traditional resource portfolios identified above.
There are several renewable energy options in commercial use. The most often
considered include solar, wind, and biomass. In addition, the REO allows the use of
electricity generated using municipal solid waste and existing hydro-electric generation to
count towards the renewable requirement. The application of these options requires an
assessment of their energy production capabilities, resultant power costs and the benefit
to the RPU requirements. Following is a discussion of these alternatives.
Solar
The use of photovoltaic solar panels for electricity production is increasing annually. The
largest increases are in those locations with high power costs coupled with net metering
Rochester Public Utilities
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Burns & McDonnell
1,369,177
1,355,588
1,379,382
1,404,635
1,424,396
1,448,721
1,474,302
1,504,861
1,529,420
1,558,948
1,589,699
Part V
Demand Side Management and Renewable Options
regulations, such as California, and remote from the grid applications. The Department
of Energy has initiated a program to promote the use of solar through programs such as
the Million Solar Roofs program. Probably the most advanced utility application of solar
is in California and the leading utility is the Sacramento Municipal Utility District
(SMUD) in Sacramento. For an idea of the size of an installation, a 2 MW array takes
about 8100 square meters (about 2 acres). Costs of these installations are about $5000
per kW. Rooftop arrays provided under the SMUD program cost about $3500/kW and,
on average for each kW produced, about 1800kWh of energy per year.
The output of the array is obviously dependent on the sun and the location of the array.
In order to obtain specific information about the solar output in the RPU area, RPU
assisted in the installation of an array on a residence in Rochester in the spring of 2004.
The unit is a fixed plate array rated at 2.6kW and was installed in April 2004 at a
residential customer. Information from the site is summarized in Table V-6. The cost of
this array was $17,951 or approximately $6,900 per kW.
Table V-6
Solar Information from a 2.6kW Fixed Plate Array
Rochester, MN
Month
No.
Days
Produced
Cap Factor
April
May
June
July
August
September
October
November
17
31
30
31
31
30
31
7
156.047
276.071
300.097
310.481
248.101
194.925
91.791
37.111
0.1476711
0.14326763
0.16092718
0.16112478
0.12875254
0.10452864
0.04763514
0.08528912
Yr. 2004
208
1614.624
0.1248812
Max Output
2.096
2.216
2.084
2.108
2.04
1.3
1.88
Legend:
Produced: The number of kWh produced by the PV array.
Capacity Factor: Based on a 2.59kW array rating
Max Output: The maximum kWh per hour measured
Note: Information from RPU’s installation. Installed April, 2004.
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The information from RPU is based on a flat plate array installed on a local residence.
The output for the array was combined with the RPU system load for the same time
period. The results are shown in Figures V-1 and V-2. Additional information was
obtained for solar installations in the Minneapolis area.1 A copy of the analysis is
included in Appendix IV.
As shown in Figure V-1, the solar output drops to zero before the RPU system load
declines significantly. This would require that RPU have sufficient generation available
to meet its system needs in addition to having the solar output available. Also, the solar
maximum output day is not coincident with the RPU peak day. This would require that
RPU have capacity available for its peak day when the solar output was reduced from its
maximum. The results from the RPU analysis are essentially the same as indicated in the
referenced paper.
Figure V-1
Maximum RPU System Peak Day
Photovoltaic Study Data
(hourly readings)
PV Sold to RPU (kwh)
PV Output (kwh)
RPU System Load (MW/100)
7/21/2004
2.5
2
1.5
kwh/MW
1
0.5
7/21/2004
0
1
2
3
4
5
RPU System Load (MW/100)
6
7
8
9
10 11
12 13
14 15
16 17
Hour
18 19
20 21
PV Output (kwh)
PV Sold to RPU (kwh)
22
23
24
1
Statistical Relationship Between Photovoltaic Generation and Electric Utility Demand in Minnesota
(1996-2002), Taylor, Mike, Minnesota Department of Commerce State Energy Office
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Demand Side Management and Renewable Options
Figure V-2
Maximum Solar Array Day
Photovoltaic Study Data
(hourly readings)
PV Sold to RPU (kwh)
PV Output (kwh)
RPU System Load (MW/100)
06/19/2004
2
1.8
1.6
1.4
1.2
kwh/MW
1
0.8
0.6
0.4
0.2
06/19/2004
0
1
2
3
4
5
RPU System Load (MW/100)
6
7
8
9
10 11
12 13
14 15
16 17
Hour
18 19
20 21
PV Output (kwh)
PV Sold to RPU (kwh)
22
23
24
Wind
Wind power is being installed in several states with wind regimes suitable for their
installation. In general, the units are in the 600kW to 750kW size range and are
positioned in clusters of several machines. A 750kW machine has a rotor diameter of
164 feet and is mounted 164 feet above the ground. The output of the units is dependent
on the average wind speed of the region. Table V-7 lists several operating projects, their
average energy and capacity factor.
Table V-7
Wind Project Statistics
Site
Cedar Falls, IA
Searsburg, VT
NPPD
Glenmore, WI
Size of Unit
750kW
550kW
750kW
600kW
Average Output
per Unit
1,800MWh
1,220MWh
2,100MWh
1,630MWh
Capacity
Factor
30%
27%
32%
31%
From the list and other projects that Burns & McDonnell has evaluated in regions with
similar wind regimes to Minnesota, the energy output from the machines results in an
approximate 30 percent capacity factor. Operation and maintenance costs are estimated
at $0.015 per kWh. Estimates of the energy cost from the machines for RPU considering
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Demand Side Management and Renewable Options
capital and operating costs are in the range of $41to $53 per MWh. This assumes
retirement of the debt in 15 years at an interest rate of 6 percent. Sales of output from
wind power developments will be priced to include discounts for the energy credits from
federal and state levels. In addition, green tags are being traded which provides another
revenue stream for renewable projects.
Minnesota created a 1.5¢ per kilowatt-hour state renewable energy production incentive
(REPI) for the first 100 MW of installed capacity of small wind generation projects. This
state REPI was expanded by the 2003 Minnesota Legislature to be available to an
additional 100 MW of small wind projects.
The energy produced by a wind generator is a non-dispatchable energy. Therefore, it has
a limited capacity value. MAPP accreditation for wind resources is approximately 10 to
15 percent. Therefore, RPU would need to install approximately 8.5MW of traditional
capacity for every 10MW of wind turbines installed to equal installation of a traditional
resource to meet its MAPP capacity and reserve obligations.
Biomass
Biomass is typically used as a fuel stock for steam fired boilers in the production of
electricity. Types of vegetation used for biomass fuel include wood waste, switchgrass,
and certain forms of specific woody crops, such as bamboo. Biomass plants are typically
rated below 50 MW due to the area required to acquire sufficient fuel for the plant. The
lack of economies of scale pushes the capital cost of these plants up into the $1500 to
$2000 per kW range for capital costs. Fuel for the biomass plants requires collection from
dispersed areas by truck and delivery to the plant site.
There is an estimated 7000 MW of biomass fired power plants in the US in current
operation. The plants produced approximately 39,000,000MWh of energy and consumed
approximately 60 million tons of fuel. Reports from the Bioenergy group of Oak Ridge
National Laboratories estimate the average cost of electricity from the plants is about $90
per MWh.
Under Minnesota Statute 2003, Chapter 216B, municipal waste is defined as a biomass
fuel. RPU has access to energy derived from this biomass resource from the Olmsted
Waste to Energy Facility (OWEF). The OWEF is a solid waste fueled unit that currently
produces approximately 1.9MW. The plant has sufficient refuse available to support an
estimated additional 5MW. RPU is in discussions with the county to purchase the output.
The plant has operated with an historic 90 percent availability. A 5MW waste to energy
plant would satisfy the renewable energy requirements of RPU under the Minnesota
regulations until approximately 2023.
Fuel Cells
Although not strictly a renewable resource plant, fuel cells have been under development
as a major alternative to traditional electrical generation methods. Fuel cells based on
phosphoric acid have been in commercial operation for about ten years. These units are
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Demand Side Management and Renewable Options
typically sized at a 200kW level. They are being deployed in certain high energy cost
areas. Current phosphoric acid fuel cells are producing electricity with an efficiency of
about 30-35 percent. An estimate of the stack life indicates that they will need to be
replaced every 5 to 6 years. The estimated stack replacement cost is $100,000 for a
200kW unit, resulting in fixed maintenance cost of $83 to $100/kW-yr.
Fuel cells being considered for small commercial and residential application based on
proton exchange membrane technology are entering the pre-commercial testing phase and
have additional research required prior to being readily available as a commercially
available technology. Combined heat and power concepts are working to increase the
overall efficiency; however, they are in the early stages of development. Testing is
indicating that reliability and the packaging approach for ease of repair and maintenance
needs to be improved.
Molten carbonate (MC) fuel cells are currently being deployed on a pre-commercial test
basis in several locations. These units operate at higher temperatures than the normal
fuel cells and are being targeted for large utility and industrial applications. Units are
being demonstrated on coal bed methane and land fill gas. The MC units are expected to
operate at efficiencies approaching 60%.
The hope for fuel cells is their ability to operate on hydrogen and produce limited
noxious emissions. Currently, almost all fuel cells operate on either methane gas from
landfills or coal beds and pipeline natural gas due to the limited availability of hydrogen.
RPU is conducting fuel cell research with the University of Minnesota-Rochester (UMR).
The Hybrid Energy System Study (HESS) project’s primary objective is to complete the
static and dynamic evaluation of fuel cell technology using a 1200-watt fuel cell system
installed in the RPU headquarters building in Rochester. Phase I which was completed
last October, acquainted RPU and UMR with the latest in fuel cell technology that is
being used in the commercial market. The fuel cell system performance was analyzed
and compared with respect to efficiency, reliability, availability and serviceability.
With the completion of the Phase I basic study on fuel cells, the RPU/UMR partnership
will move early in 2005 to a project level that begins to make full use of fuel cell
capabilities. Fuel cells typically run at an efficiency level of about 40% when generating
electricity. A major part of the efficiency loss is in the heat generated during the fuel
cells operation. Capturing this heat and making use of it as part of a system’s energy
solution is the focus of Phase II. In particular, we will integrate a fuel cell and a
geothermal (GX) heating system, therefore, capturing the heat generated by the fuel cell
and raising the efficiency of the system to over 80%. During summer time operation, this
extra heat could be used to provide more energy to heat hot water, swimming pools, etc.
Renewable Portfolio Program
RPU is committed to not only providing its required portion of renewable energy to
satisfy the requirements of the Minnesota Statute 216B, but to integrate renewable energy
where it makes good business sense to do so. The energy above CROD amount provided
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Demand Side Management and Renewable Options
by SMMPA is shown in Table V-8 for 2016 to the end of the study period. The growth
in renewable energy required between 2005 and 2016 can be met through the energy
from the Zumbro River hydro facility. Using the ten percent requirement from the
Statute, the required amount of energy beyond 2015 can be determined. The amount of
energy estimated to be available from the Zumbro River hydro facility is also shown.
The resulting renewable energy required beyond that currently provided is shown in
Table V-8.
Using the average capacity factors for the fixed plate solar arrays from Table V-6 and the
average 30 percent capacity factor for wind units, the average amount of solar and wind
capacity required to meet the RPU annual renewable energy requirements can be
estimated. These estimates were derived from using the Revised Energy Forecast from
Table V-5. Table V-8 provides the estimates. The energy above CROD requirements
predicted in Table V-8 assumed the energy savings are evenly distributed across all hours
of the year. To the degree the savings accrue more from programs reducing energy above
or below the CROD level, the estimates in Table V-8 will vary actual results.
Table V-8
Estimated MW of Wind or Solar Required to Meet the RPU
Renewable Energy Requirements Post 2015
Year
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Energy Above
CROD (MWh)
70,589
82,305
96,279
112,425
134,112
159,422
190,077
224,847
264,465
305,705
349,486
396,145
445,435
496,336
549,802
Renewable
From Zumbro
Requirement (10%) River Hydro
7,059
9,000
8,230
9,000
9,628
9,000
11,243
9,000
13,411
9,000
15,942
9,000
19,008
9,000
22,485
9,000
26,446
9,000
30,570
9,000
34,949
9,000
39,614
9,000
44,543
9,000
49,634
9,000
54,980
9,000
Solar
Wind
Resultant
Capacity Capacity
Renewable Required Required
Req.
(MW)
(MW)
0.0
0.0
-1,941
0.0
0.0
-770
0.0
0.0
628
2.0
0.9
2,243
4.0
1.7
4,411
6.3
2.6
6,942
9.1
3.8
10,008
12.3
5.1
13,485
15.9
6.6
17,446
19.7
8.2
21,570
23.7
9.9
25,949
28.0
11.6
30,614
32.5
13.5
35,543
37.1
15.5
40,634
42.0
17.5
45,980
The solar and wind resources’ ability to provide a certain amount of capacity relief was
reviewed. The peak needs of RPU and the solar availability are shown in Figures V-1
and V-2. The figures indicate that the peak requirements extend beyond the time period
when solar is available. Cloud cover can also significantly reduce the solar output below
the demand required of RPU. Therefore, for supply reliability, additional resources are
required to provide energy when the solar output is unavailable. The MAPP accreditation
process for solar array output from the above paper indicates that for the Minneapolis
solar arrays, the units were able to have capacity accredited between 8 percent and 44
Rochester Public Utilities
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Part V
Demand Side Management and Renewable Options
percent of their AC ratings. Correlation of the specific RPU data will need to be made to
determine the proper estimated accreditation for solar arrays in the RPU service territory.
Allowing wind the MAPP upper 15 percent capacity credit indicates that only a portion
of the wind capacity may be available across the peak. Therefore, the renewable
portfolio options may require the installation of peaking capacity to support them during
times when they are unavailable and load demand is still higher than the existing resource
capability. For the wind portfolio, approximately 85 percent of the capacity in the
traditional options could be required.
If the OWEF increases its output to 5MW, the plant would produce approximately 32,850
MWh per year, assuming a 75 percent capacity factor. Since this unit counts as
renewable energy and under the Statute utilities are to provide 1 percent of their energy
from biomass, it could satisfy the RPU biomass renewable requirements through the
study period. When combined with the Zumbro River hydro facility total renewable
requirements could be satisfied until approximately 2027. Table V-9 provides an
assumed purchase scenario. Due to the requirement in the REO of obtaining 1 percent of
energy from biomass, the output of the OWEF will be required beginning in 2005.
Table V-9
RPU Estimated Annual Renewable Energy Requirements (MWh)
Available from OWEF
Year
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Renewable
Requirement (10%)
7,059
8,230
9,628
11,243
13,411
15,942
19,008
22,485
26,446
30,570
34,949
39,614
44,543
49,634
54,980
From
Biomass
71
82
96
112
134
159
190
225
264
306
349
396
445
496
550
1.9MW @
75%CF
12,483
12,483
12,483
12,483
12,483
12,483
12,483
5MW @
75%CF
32,850
32,850
32,850
32,850
32,850
32,850
32,850
32,850
From
Zumbro
River
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
9,000
Total
Hydro &
Biomass
21,483
21,483
21,483
21,483
21,483
21,483
21,483
41,850
41,850
41,850
41,850
41,850
41,850
41,850
41,850
Note: All energy values in MWh
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Part V
Demand Side Management and Renewable Options
DSM and Renewable Impacts on RPU Supply Needs
The balance of loads and resources using the DSM and renewable impacts was modified
to include the above forecasts. The resulting impacts are shown in Figure V-3.
Figure V-3
Comparison of Base and Revised Forecasts
With DSM and Renewable Impacts
Forecast Comparisons
SMMPA
RPU Resources
Uncontrolled Demand
Phase I Forecast
DSM Impact
DSM + Renewables
600
500
400
MW
300
200
100
0
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
The impacts to the forecast indicate that the projected impacts of DSM and renewables do
not delay the year when RPU becomes capacity deficit, however, they substantially
reduce the amount of capacity needed. In addition, they delay the need for additional
capacity in the future. Figure V-4 is the balance of loads and resources of the
recommended traditional resource plan. As shown, the impact of the DSM and
renewables on the forecast allows a delay in the installation of the LMS-100 combustion
turbine by about 2 - 3 years. The impacts also allow a delay in the need for the coal unit
by a similar period.
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Demand Side Management and Renewable Options
Figure V-4
Impact of DSM and Renewables
On Lowest Evaluated Traditional Resource Plan
Balance of Loads and Resources
700
600
500
MW
400
300
200
100
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Hydro
SMMPA CROD
SLP
New Coal
LMS100 CT
Existing CT
New CT
Peak Forecast
Peak +15%
DSM+Ren
Conclusions and Recommendations
Based on the review of the information provided by RPU and the analysis developed in
this study, Burns & McDonnell has developed the following conclusions and
recommendations about the DSM programs and renewable energy alternatives available
to RPU.
1. The review of the DSM end use surveys and benefit cost ratios provided an
indication of the amount and value of various conservation programs to the RPU
customer base that is sufficient to use for planning purposes.
2. The estimates of energy and demand reductions from the programs with benefit
cost ratios greater than one is sufficient to warrant study by RPU in determining
the impact on rates for development of various programs and the impact on
forecasts for energy and demand.
3. Considering the forecast, RPU has several years before it is in a capacity deficit
condition due to load needs. Estimates of DSM and renewable impacts to the
forecast provide the opportunity for RPU to delay the installation of resources by
Rochester Public Utilities
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Burns & McDonnell
Part V
Demand Side Management and Renewable Options
two to three years, depending on the successful acceptance of the DSM programs
by the RPU customers.
4. The development of the MISO Day 2 market will make day ahead pricing more
predictable and potentially provide RPU with the opportunity to engage customers
in demand adjustments based on the cost of energy. The current Partners program
could see a decrease in the number of MW under control due to more efficient air
conditioners being installed on the system and potential fuel switching of water
heaters. These two developments are an indication that RPU should consider
realigning its approach to demand reductions on the customer side of the meter.
Because of this need, RPU should prepare a pilot program for implementation of
demand response type programs across the residential, commercial and industrial
classes in order to gain experience and begin shifting away from the direct control
programs to market based programs.
5. RPU’s renewable obligations under the Minnesota Statute Chapter 216B can be
met for several years through purchase of energy from the OWEF and the Zumbro
River hydro facility. If the OWEF facility is expanded, as is being considered,
RPU renewable energy requirements could be satisfied until approximately 2027
with these two resources.
6. Discussions with the OWEF should proceed to determine if additional output is
available. If it is not, then wind energy should be pursued as the next renewable
option. Based on the cost and output of photovoltaic units, solar photovoltaic is
the most expensive renewable option for the RPU to pursue.
7. Based on information from RPU, the SMMPA is in discussions on acquisition of
additional resources which could affect the cost of capacity and energy under the
CROD. At the current time, there is insufficient information to be able to
determine how DSM programs could reduce the impact of these potential costs.
If SMMPA moves ahead with resource acquisitions based on RPU impacts to the
SMMPA resource mix, RPU should discuss with SMMPA the ability of DSM
options to reduce the resource need impacts to SMMPA.
*****
Rochester Public Utilities
V-24
Burns & McDonnell
Part VI
Financial Forecast
Part VI
Financial Forecast
The results of the resource planning, demand side management and renewable
assessments were reviewed on an incremental cost approach to determine lower
evaluated options. In order to bring these options together to determine the
recommended RPU future, a financial forecast model was developed by RPU to
incorporate the total costs of RPU. This model allowed a complete evaluation of future
costs, the impact to average rates and other financial factors of interest to RPU. This part
of the report provides a discussion of the model and the results.
Financial Model
The model was developed by Bryan Blom of the RPU staff. It is a very flexible tool that
will provide RPU with the capability to do scenario analysis rapidly, with a variety of
measurements to gauge the benefits of certain futures. The model incorporates all of the
RPU costs of operations, investments, and financial targets such as for cash balances and
reserve accounts.
The financial model was used to analyze the following futures:
•
The recommended expansion plan from Part IV with the forecast unaffected by
demand side management,
•
The recommended plan adjusted by using the normal demand side management
forecast with SLP operating on coal and adjustments to the new resources,
•
The recommenced plan adjusted by using the normal demand side management
forecast with SLP operating on natural gas and the coal unit replaced with gasfired capacity,
•
The recommended plan adjusted by using the aggressive demand side
management results with SLP operating on coal and adjustments to the new
resources,
•
The recommended plan adjusted by using the aggressive demand side
management results with SLP operating on natural gas and the coal unit replaced
with gas-fired capacity.
Input Assumptions
A variety of assumptions were made to the financial model. The main driver for the
model is the energy forecast. The energy forecast for the three futures is summarized in
Table VI-1. The demand forecast is also included.
Rochester Public Utilities
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Burns & McDonnell
Part VI
Financial Forecast
Table VI-1
Financial Model Load Forecast
System MWH Requirements
Year
No DSM
System KW Peaks
Aggr DSM, Coal
Gas Mix / Aggr
DSM, All Gas
No DSM
Aggr DSM, Coal
Gas Mix / Aggr
DSM, All Gas
2005
1,377,188
1,369,244
275,532
273,943
2006
1,414,592
1,355,882
283,016
271,270
2007
1,452,466
1,379,800
290,593
276,055
2008
1,495,753
1,405,507
299,254
281,198
2009
1,532,736
1,424,557
306,653
285,009
2010
1,573,748
1,448,206
314,858
289,741
2011
1,615,858
1,473,719
323,283
294,845
2012
1,664,019
1,504,173
332,918
300,938
2013
1,705,167
1,529,146
341,151
305,934
2014
1,750,796
1,559,194
350,280
311,946
2015
1,797,648
1,589,834
359,653
318,076
2016
1,850,380
1,635,664
370,203
327,245
2017
1,897,159
1,672,869
379,562
334,689
2018
1,947,044
1,717,704
389,543
343,659
2019
2,000,216
1,762,000
400,181
352,521
2020
2,058,896
1,812,798
411,921
362,684
2021
2,108,877
1,857,723
421,920
371,672
2022
2,167,552
1,907,527
433,659
381,637
2023
2,225,664
1,958,667
445,286
391,868
2024
2,289,846
2,017,133
458,127
403,565
2025
2,346,599
2,067,127
469,481
413,568
2026
2,410,705
2,122,550
482,307
424,656
2027
2,475,342
2,180,536
495,239
436,257
2028
2,547,984
2,244,526
509,772
449,060
2029
2,612,433
2,301,298
522,666
460,418
2030
2,681,160
2,364,171
536,416
472,997
2031
2,753,599
2,426,667
550,909
485,500
2032
2,827,996
2,490,816
565,794
498,335
2033
2,904,405
2,556,663
581,081
511,508
2034
2,982,881
2,624,252
596,781
525,031
The load forecast was used to derive estimates for a variety of other assumptions, such as:
•
•
•
•
•
•
Energy dispatch from RPU sources, including market sources, above the SMMPA
supplied energy,
Generation fuel expense,
Purchased power expense for energy, capacity, and transmission,
Administrative and general costs,
Distribution and substation additions,
Retail revenue forecasts.
Rochester Public Utilities
VI-2
Burns & McDonnell
Part VI
Financial Forecast
Forecasts for investment in other projects, such as for transmission upgrades, capital
investments in plant, and other improvements were provided by the respective operating
divisions of RPU. The Silver Lake Plant was assumed to have the recommended
environmental modifications from the Utility Engineering report “Rochester Public
Utilities Emissions Control Feasibility Study, Silver Lake Plant,” Dec 2004 in the futures
with coal. The budgets for the demand side management and marketing programs were
included based on the level of DSM considered in the forecast. The list of input
assumptions is included in Appendix V.
Methodology
The financial model uses the energy forecast and estimated energy price from the
resources available to determine the amount of energy derived from each source. If the
load level is at or below the 216MW level of the SMMPA contract, then the energy is
assumed to come from SMMPA. If the load is above the 216MW level, then the lowest
cost resource is dispatched to provide the energy with the exception that small load
increments were dispatched first from peaking units until the point where the increment
was high enough to feasibly dispatch baseload generation.
The economic impacts of resource additions were determined based on the estimated
capital, fixed and variable operating and maintenance costs. The targeted financial goals
for debt service coverage ratios, average cash balances and other targets based on capital
investments were included. In-service years and the amount of capacity added were
adjusted in the futures with demand side management included to reflect the benefits to
delays in and amounts of capital investment.
Estimates of purchases from the market were made using a forecast market demand and
energy price. For certain years, market capacity was purchased on a seasonal basis to
provide the necessary capacity shortfall rather than install a new resource. Also, when
market energy was estimated to be lower cost than an RPU resource’s energy cost, the
market was used to provide the energy.
The operation of the SLP to meet wholesale energy and steam production contract
obligations was modeled. The operations included estimated energy and steam
production based on current discussions with counter parties to the contracts.
The operation and capital budgets of each RPU division were incorporated to provide a
complete financial picture of the utility. The revenue requirements were then used to
determine the amount of adjustment to rates necessary to meet those requirements.
Average impact to retail rates and customer average bills were also estimated. The model
covers a thirty year time period from 2005 to 2034.
Externalities
The values of externalities were included in this analysis. The values of externalities
used by the Minnesota Public Utilities Commission (Rural) for utilities to evaluate
externalities are shown in Table VI-2. These values were adjusted for the gross domestic
Rochester Public Utilities
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Burns & McDonnell
Part VI
Financial Forecast
price inflator (4.4%) for 2004. A midpoint range for the adjusted values was selected for
use in the analysis. These values are also shown in Table VI-2.
Table VI-2
Externality Values
PM10
CO
Nox
Pb
CO2
Low Value
2003
2004
$645.00 $673.38
$ 0.24 $ 0.25
$ 21.00 $ 21.92
$461.00 $481.28
$ 0.34 $ 0.35
High Value
2003
2004
$981.00 $1,024.16
$ 0.47
$ 0.49
$117.00
$122.15
$514.00
$536.62
$ 3.56
$ 3.72
2004
AVG
$848.77
$ 0.37
$ 72.04
$508.95
$ 2.04
The emission rates from the resources considered in the financial model are summarized
in Table VI-3. The emissions were placed on a dollar per MWh basis for use with the
expected dispatch MWh determined from the financial model. Externalities on contract
and market purchases were also included to reflect one half of the purchases from new
coal units and one half from combined cycle gas units.
Table VI-3
Emission Rates
(lb/MWh)
Emission
SO2
PM10
CO
Nox
Pb
CO2
LMS100
0
0.14
5.85
0.87
0
1125.48
CC2
0
0.0166
2.96
1.52
0
1051.2
SLP
Coal
Gas
4.85
0.01
0.21
0.07766
0.28
0.924
1.60
3.08
0.000606 0.0000055
2,460.97
1126
New Coal
0.96
0.17
1.44
0.67
0.0002406
2761.51
Market
0
0.07
0.117
0.084
0
825
Renewable Options
The values for the average energy costs from the expected resources and certain
renewable resources are shown in Table VI-4. The RPU currently purchases renewable
energy from the Olmsted County Waste to Energy Facility, which counts towards the
utilities biomass energy requirement. This facility is considering increasing the energy
production which could provide additional biomass energy for RPU. Energy from a solar
installation in the RPU service territory is currently being purchased at the net metered
residential energy rate. Wind energy is purchased through the SMMPA. The amount of
predominate renewable energy is from the Zumbro River hydro-electric facility.
Rochester Public Utilities
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Burns & McDonnell
Part VI
Financial Forecast
Table VI-4
Average Energy Costs with Externalities
(2004$ per MWh)
Option
SLP Coal
New Coal
New Gas
LMS 100
Market
Solar PV
OWEF
Wind
Zumbro
Fixed O&M
$13.85
$ 3.01
$ 6.73
$ 3.75
Var O&M
$6.59
$2.15
$4.01
$3.30
Purchase/
Fuel
$25.34
$11.07
$58.27
$53.79
$35.88
$75.10
$60.00
$33.44
Transmission
$5.00
$5.00
Externality
$2.65
$2.91
$1.13
$1.24
$1.89
$5.00
$5.00
$2.17
Although it is acceptable to consider energy costs on a one for one basis between
traditional and renewable resources, the capacity cannot always be considered in a
comparable fashion. This is due to the non-dispatchability of most renewable options.
For instance, the utility has to take energy from a wind turbine when the wind blows.
The energy availability and the utility needs may not necessarily coincide. The line-up of
solar energy with the RPU demand is shown in Part V and demonstrates this issue.
RPU operates in the Mid-Continent Area Power Pool (MAPP) reliability region. Utilities
within this region must maintain a reserve margin of 15 percent or be assessed a penalty.
In order to meet this requirement, resources must meet certain capacity tests. From past
experience with wind turbine and solar array capacity, MAPP has established that wind
capacity provides only 15 percent of the equivalent traditional resource capacity value
and solar provides approximately 40 percent (summer season). This means that if RPU
wanted to install wind or solar capacity to meet its MAPP reserve requirements, which
for every MW of traditional resource considered either 6.67MW of wind or 2.5MW of
solar would be needed. The impact of these requirements on the average cost of energy
from the resources is shown in Table VI-5.
Table VI-5
Impacts of Equivalent Capacity on Energy Cost
(Average Annual Debt Service)
Rochester Public Utilities
Option
$/MWh
SLP Coal
New Coal
New Gas
LMS 100
Solar PV
Wind
$11.73
$16.99
$32.48
$36.30
$852.50
$222.91
VI-5
Capacity
Factor-%
40
80
20
20
20
30
Burns & McDonnell
Total
$48.43
$24.14
$70.14
$62.08
$42.77
$75.10
$65.00
$38.44
$2.17
Part VI
Financial Forecast
Based on the evaluation of the externalities and MAPP accreditation impacts, RPU has
determined that renewable energy will be used to displace traditional resource energy
where economic. However, renewable resources will not be considered to meet future
capacity obligations.
Renewable energy from the Zumbro River facility was included in the financial model as
the primary renewable resource, wind energy under the SMMPA program included at its
historical average, and with OWEF assumed to be the biomass resource.
Results
Resource Plan
The impact of the demand side management efforts on the load forecast are shown in
Part V, Figure V-1 and 2 for the demand and energy respectively. Figure V-4 provides
the potential impacts the forecast could have to the resource needs in the traditional
resource plan. The reduction in the demand and energy forecast provides an opportunity
to delay the gas resource considered for 2016 and the in service year and amount of
capacity for the coal resource considered in 2020. In the financial model, the combustion
turbine considered for installation in 2016 was delayed two years and the coal unit was
reduced to 25MW and its in service date delayed to 2025.
Rates
Figure VI-1 and 2 provide the results based on average retail rate impacts and average
customer bills. As seen, there are significant advantages in the demand side management
impacts on both rates and average bills. When considering the cost impacts due to the
futures with and without coal, it is seen that the coal case provides economic benefits.
The rate impacts determined from the analyses are summarized in Figure VI-3. RPU in
any of the futures is expected to need rate increases of from 1 to 3 percent in almost each
year of the assessment. The differences in the expected and aggressive demand side
management scenarios were not significant and only the aggressive forecast is included
here. The more detailed results of the financial model analyses are included in Appendix
V.
Rochester Public Utilities
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Burns & McDonnell
Figure VI-1
Retail $/MWH-Major Customer Classes
$140
Coal/Gas Mix
All Gas
No DSM
$120
$100
$/MWH
$80
$60
$40
$20
$0
2005
2007
2009
2011
2013
2015
2017
2019
Year
VI-7
2021
2023
2025
2027
2029
2031
2033
Figure VI-2
Average Annual Bill-Major Customer Classes
$6,000
$5,000
Dollars
$4,000
Coal/Gas Mix
All Gas
No DSM
$3,000
$2,000
$1,000
$0
2005
2007
2009
2011
2013
2015
2017
2019
Year
VI-8
2021
2023
2025
2027
2029
2031
2033
Figure VI-3
Percentage of Annual Retail Rate Increase
25
Ratio or Rate Increase %
20
15
Rate Increase %-Coal/Gas Mix
Rate Increase %-All Gas
Rate Increase %-No DSM
10
5
0
2005
2007
2009
2011
2013
2015
2017
2019
Year
VI-9
2021
2023
2025
2027
2029
2031
2033
Part VI
Financial Forecast
As seen from the above graphs, the DSM cases with the coal and gas fuel scenario are the
only cases that help to reduce both the average rates and customer bills.
Emissions
The emissions from each of the futures were considered from both absolute tons per
externality and the cost aspect using the Minnesota value for externalities. Table VI-6
provides the summary of tons emitted by externality based on the energy dispatch used
for the RPU retail resource future over the thirty years of the analysis. As shown, there is
a substantial advantage to the demand side reductions. The costs of the externalities and
the total costs of the specific future are included in Table VI-7.
Table VI-6
Total Tons of Emissions by Scenario
Scenario
Original Forecast
Normal DSM Coal & Gas
Normal DSM All Gas
Aggressive DSM Coal & Gas
Aggressive DSM All Gas
SO2
7,808
5,228
379
4,931
343
Nox
4,587
3,105
5,086
2,886
4,714
PM10
770
485
296
448
272
Pb
1.25
0.79
0.10
0.73
0.09
CO
9,811
7,048
8,341
6,504
7,644
CO2
10,472,370
6,263,420
3,784,419
5,720,385
3,474,437
Table VI-7
Retail Portion of RPU Costs of Various Plans with Externalities
(2004$ 000’s)
Scenario
Original Forecast
Normal DSM Coal & Gas
Normal DSM All Gas
Aggressive DSM Coal & Gas
Aggressive DSM All Gas
Retail Revenue
$ 5,649,613
$ 5,134,851
$ 5,672,269
$ 5,104,864
$ 5,569,761
Externalities
$22,308
$13,390
$ 8,325
$12,236
$ 7,646
$
$
$
$
$
Total
5,671,921
5,148,241
5,680,594
5,117,100
5,577,408
Conclusions
Based on the analysis performed for this study, Burns & McDonnell has developed the
following conclusions:
1. The uncertainty surrounding the conversion of the electricity wholesale market in
the RPU region from its traditional operation to its new operation under MISO
and the existing transmission limitations for importing power into the RPU area
makes it necessary for RPU to continue to have capacity available within its
service area for reliability and economic purposes.
Rochester Public Utilities
VI-10
Burns & McDonnell
Part VI
Financial Forecast
2. The use of traditional resources to meet the RPU capacity obligations is lower
cost than the use of wind or solar equivalent capacity. Energy costs from certain
renewable options can be attractive when compared to the energy costs from coal,
gas, or market resources.
3. The impacts of demand side management allow RPU to delay and reduce the
amount of capacity required when compared to the forecast without significant
demand side management effects included.
4. The future evaluated with coal and gas energy and aggressive demand side
management was the only future that provided both lower average rates and lower
average total bills when compared to the other futures. This ranking is not
changed with the inclusion of externalities.
5. The emissions from the aggressive demand side management future with coal and
gas are approximately one-half of the emissions from the traditional resource
future.
Recommendations
Based on the above conclusions and the analyses performed, Burns & McDonnell
provides the following recommendations for consideration by RPU.
1. Due to the need for future capacity additions internal to RPU, RPU should pursue
the acquisition of property to install additional combustion turbine capacity. The
property should be located in close proximity to high capacity electric and gas
transmission lines.
2. RPU should pursue emission control upgrades to the SLP facility to allow
continued operations while meeting ongoing environmental regulations and
follow the general course of operations as modeled in the DSM futures with coal
and gas fuels in the operating mix.
3. Improved transmission import capability should be reviewed with area utilities to
allow increased access to market capacity. Although the plans anticipate future
resource additions, there is also continued reliance on market purchases to meet
future load growth.
4. RPU should monitor the operations of the MISO Day 2 market to determine how
to participate in the market.
5. RPU should continue to design and market DSM programs to achieve the levels
of forecast reductions for demand and energy. Periodic comparison of actual
results to those forecasts should be made to determine if adjustments in the
forecast results is necessary.
Rochester Public Utilities
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Burns & McDonnell
Part VI
Financial Forecast
6. RPU should take advantage of renewable energy from the Zumbro River resource
to the full extent of its output. The renewable energy from the OWEF should be
considered to provide the RPU biomass energy requirements. Purchases above
the requirements should be compared to the cost of other energy available.
*****
Rochester Public Utilities
VI-12
Burns & McDonnell
Appendix I – Load Forecast (Without DSM Impacts)
Annual Peak Demand and Energy Requirements
Year
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Peak (MW)
261.3
268.4
275.6
283.1
290.7
298.6
306.6
314.9
323.4
332.2
341.1
350.3
359.8
369.5
379.5
389.7
400.3
411.1
422.2
433.6
445.3
457.3
469.6
482.3
495.3
508.7
522.4
536.6
Esc.
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
Energy (MWh)
1,306,276
1,344,534
1,377,767
1,414,967
1,453,171
1,495,732
1,532,702
1,574,085
1,616,585
1,663,932
1,705,059
1,751,096
1,798,375
1,851,046
1,896,798
1,948,012
2,000,608
2,059,202
2,110,100
2,167,072
2,225,583
2,290,766
2,347,559
2,410,943
2,476,038
2,548,370
2,611,549
2,682,061
Esc.
9.6%
2.9%
2.5%
2.7%
2.7%
2.9%
2.5%
2.7%
2.7%
2.9%
2.5%
2.7%
2.7%
2.9%
2.5%
2.7%
2.7%
2.9%
2.5%
2.7%
2.7%
2.9%
2.5%
2.7%
2.7%
2.9%
2.5%
2.7%
LF
57.1%
57.2%
57.1%
57.1%
57.1%
57.2%
57.1%
57.1%
57.1%
57.2%
57.1%
57.1%
57.1%
57.2%
57.1%
57.1%
57.1%
57.2%
57.1%
57.1%
57.1%
57.2%
57.1%
57.1%
57.1%
57.2%
57.1%
57.1%
Monthly Peak Demand and Energy Requirements
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Year
2006
2006
2006
2006
2006
2006
2006
2006
2006
2006
2006
2006
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2007
2008
2008
2008
2008
2008
2008
2008
2008
2008
2008
2008
2008
2009
2009
2009
2009
2009
2009
2009
2009
2009
2009
2009
2009
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
Peak Demand (MW)
Annual Peak
Ratio
283.1
0.648
283.1
0.645
283.1
0.631
283.1
0.687
283.1
0.770
283.1
0.966
283.1
1.000
283.1
0.984
283.1
0.977
283.1
0.694
283.1
0.656
283.1
0.687
290.7
0.648
290.7
0.645
290.7
0.631
290.7
0.687
290.7
0.770
290.7
0.966
290.7
1.000
290.7
0.984
290.7
0.977
290.7
0.694
290.7
0.656
290.7
0.687
298.6
0.648
298.6
0.645
298.6
0.631
298.6
0.687
298.6
0.770
298.6
0.966
298.6
1.000
298.6
0.984
298.6
0.977
298.6
0.694
298.6
0.656
298.6
0.687
306.6
0.648
306.6
0.645
306.6
0.631
306.6
0.687
306.6
0.770
306.6
0.966
306.6
1.000
306.6
0.984
306.6
0.977
306.6
0.694
306.6
0.656
306.6
0.687
314.9
0.648
314.9
0.645
314.9
0.631
314.9
0.687
314.9
0.770
314.9
0.966
314.9
1.000
314.9
0.984
314.9
0.977
314.9
0.694
314.9
0.656
314.9
0.687
Peak
183.5
182.6
178.6
194.5
218.1
273.5
283.1
278.7
276.6
196.6
185.8
194.5
188.4
187.5
183.5
199.8
224.0
280.9
290.7
286.2
284.1
201.9
190.8
199.8
193.5
192.6
188.4
205.2
230.0
288.5
298.6
293.9
291.8
207.3
196.0
205.2
198.7
197.8
193.5
210.7
236.3
296.3
306.6
301.8
299.7
212.9
201.3
210.7
204.1
203.1
198.7
216.4
242.6
304.3
314.9
310.0
307.8
218.7
206.7
216.4
Total Energy Requirements (MWh)
Annual
Total
Ratio
Total
1,414,967
0.078
110,892
1,414,967
0.071
100,341
1,414,967
0.076
107,892
1,414,967
0.073
103,354
1,414,967
0.080
113,721
1,414,967
0.091
128,980
1,414,967
0.109
153,709
1,414,967
0.102
144,845
1,414,967
0.086
121,835
1,414,967
0.079
111,608
1,414,967
0.075
105,978
1,414,967
0.079
111,812
1,453,171
0.078
113,886
1,453,171
0.071
103,050
1,453,171
0.076
110,805
1,453,171
0.073
106,145
1,453,171
0.080
116,791
1,453,171
0.091
132,462
1,453,171
0.109
157,859
1,453,171
0.102
148,756
1,453,171
0.086
125,125
1,453,171
0.079
114,622
1,453,171
0.075
108,839
1,453,171
0.079
114,831
1,495,732
0.078
117,222
1,495,732
0.071
106,068
1,495,732
0.076
114,050
1,495,732
0.073
109,253
1,495,732
0.080
120,212
1,495,732
0.091
136,342
1,495,732
0.109
162,482
1,495,732
0.102
153,113
1,495,732
0.086
128,789
1,495,732
0.079
117,979
1,495,732
0.075
112,027
1,495,732
0.079
118,195
1,532,702
0.078
120,119
1,532,702
0.071
108,690
1,532,702
0.076
116,869
1,532,702
0.073
111,954
1,532,702
0.080
123,183
1,532,702
0.091
139,711
1,532,702
0.109
166,498
1,532,702
0.102
156,897
1,532,702
0.086
131,973
1,532,702
0.079
120,895
1,532,702
0.075
114,796
1,532,702
0.079
121,116
1,574,085
0.078
123,362
1,574,085
0.071
111,625
1,574,085
0.076
120,025
1,574,085
0.073
114,976
1,574,085
0.080
126,509
1,574,085
0.091
143,484
1,574,085
0.109
170,994
1,574,085
0.102
161,133
1,574,085
0.086
135,536
1,574,085
0.079
124,159
1,574,085
0.075
117,896
1,574,085
0.079
124,386
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2011
2011
2011
2011
2011
2011
2011
2011
2011
2011
2011
2011
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2013
2013
2013
2013
2013
2013
2013
2013
2013
2013
2013
2013
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2014
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
2015
323.4
323.4
323.4
323.4
323.4
323.4
323.4
323.4
323.4
323.4
323.4
323.4
332.2
332.2
332.2
332.2
332.2
332.2
332.2
332.2
332.2
332.2
332.2
332.2
341.1
341.1
341.1
341.1
341.1
341.1
341.1
341.1
341.1
341.1
341.1
341.1
350.3
350.3
350.3
350.3
350.3
350.3
350.3
350.3
350.3
350.3
350.3
350.3
359.8
359.8
359.8
359.8
359.8
359.8
359.8
359.8
359.8
359.8
359.8
359.8
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
209.6
208.6
204.1
222.3
249.2
312.5
323.4
318.4
316.1
224.6
212.3
222.3
215.3
214.3
209.6
228.3
255.9
320.9
332.2
327.0
324.6
230.7
218.0
228.3
221.1
220.0
215.3
234.4
262.8
329.6
341.1
335.8
333.4
236.9
223.9
234.4
227.0
226.0
221.1
240.8
269.9
338.5
350.3
344.9
342.4
243.3
230.0
240.7
233.2
232.1
227.1
247.3
277.2
347.6
359.8
354.2
351.6
249.8
236.2
247.2
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,616,585
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,663,932
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,705,059
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,751,096
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
1,798,375
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
126,693
114,639
123,266
118,081
129,925
147,358
175,610
165,484
139,195
127,511
121,079
127,745
130,404
117,996
126,876
121,539
133,730
151,674
180,754
170,331
143,272
131,246
124,625
131,486
133,627
120,913
130,012
124,543
137,035
155,423
185,221
174,541
146,814
134,490
127,705
134,736
137,235
124,177
133,522
127,906
140,735
159,619
190,222
179,253
150,777
138,121
131,153
138,374
140,940
127,530
137,127
131,359
144,535
163,929
195,358
184,093
154,848
141,850
134,694
142,110
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2016
2016
2016
2016
2016
2016
2016
2016
2016
2016
2016
2016
2017
2017
2017
2017
2017
2017
2017
2017
2017
2017
2017
2017
2018
2018
2018
2018
2018
2018
2018
2018
2018
2018
2018
2018
2019
2019
2019
2019
2019
2019
2019
2019
2019
2019
2019
2019
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
2020
369.5
369.5
369.5
369.5
369.5
369.5
369.5
369.5
369.5
369.5
369.5
369.5
379.5
379.5
379.5
379.5
379.5
379.5
379.5
379.5
379.5
379.5
379.5
379.5
389.7
389.7
389.7
389.7
389.7
389.7
389.7
389.7
389.7
389.7
389.7
389.7
400.3
400.3
400.3
400.3
400.3
400.3
400.3
400.3
400.3
400.3
400.3
400.3
411.1
411.1
411.1
411.1
411.1
411.1
411.1
411.1
411.1
411.1
411.1
411.1
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
239.5
238.4
233.2
253.9
284.7
357.0
369.5
363.7
361.1
256.6
242.5
253.9
245.9
244.8
239.5
260.8
292.4
366.6
379.5
373.6
370.9
263.5
249.1
260.8
252.6
251.4
245.9
267.8
300.3
376.5
389.7
383.6
380.9
270.6
255.8
267.8
259.4
258.2
252.6
275.1
308.4
386.7
400.3
394.0
391.1
277.9
262.7
275.0
266.4
265.2
259.4
282.5
316.7
397.1
411.1
404.6
401.7
285.4
269.8
282.5
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,851,046
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,896,798
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
1,948,012
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,000,608
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
2,059,202
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
145,068
131,265
141,143
135,207
148,768
168,730
201,080
189,485
159,384
146,005
138,639
146,272
148,654
134,510
144,632
138,549
152,445
172,900
206,050
194,168
163,323
149,613
142,066
149,887
152,667
138,141
148,537
142,289
156,561
177,569
211,613
199,411
167,733
153,653
145,902
153,934
156,789
141,871
152,548
146,131
160,789
182,363
217,327
204,795
172,262
157,802
149,841
158,091
161,382
146,026
157,015
150,411
165,498
187,704
223,692
210,793
177,307
162,423
154,230
162,721
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2021
2021
2021
2021
2021
2021
2021
2021
2021
2021
2021
2021
2022
2022
2022
2022
2022
2022
2022
2022
2022
2022
2022
2022
2023
2023
2023
2023
2023
2023
2023
2023
2023
2023
2023
2023
2024
2024
2024
2024
2024
2024
2024
2024
2024
2024
2024
2024
2025
2025
2025
2025
2025
2025
2025
2025
2025
2025
2025
2025
422.2
422.2
422.2
422.2
422.2
422.2
422.2
422.2
422.2
422.2
422.2
422.2
433.6
433.6
433.6
433.6
433.6
433.6
433.6
433.6
433.6
433.6
433.6
433.6
445.3
445.3
445.3
445.3
445.3
445.3
445.3
445.3
445.3
445.3
445.3
445.3
457.3
457.3
457.3
457.3
457.3
457.3
457.3
457.3
457.3
457.3
457.3
457.3
469.6
469.6
469.6
469.6
469.6
469.6
469.6
469.6
469.6
469.6
469.6
469.6
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
273.6
272.3
266.4
290.1
325.3
407.9
422.2
415.6
412.6
293.2
277.1
290.1
281.0
279.7
273.6
298.0
334.0
418.9
433.6
426.8
423.7
301.1
284.6
297.9
288.6
287.2
281.0
306.0
343.1
430.2
445.3
438.3
435.1
309.2
292.3
306.0
296.4
295.0
288.6
314.3
352.3
441.8
457.3
450.1
446.9
317.5
300.2
314.2
304.4
302.9
296.4
322.7
361.8
453.7
469.6
462.3
458.9
326.1
308.3
322.7
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,110,100
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,167,072
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,225,583
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,290,766
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
2,347,559
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
165,370
149,636
160,896
154,129
169,588
192,343
229,221
216,003
181,689
166,438
158,042
166,743
169,835
153,676
165,241
158,290
174,167
197,537
235,410
221,835
186,595
170,932
162,309
171,245
174,421
157,825
169,702
162,564
178,870
202,870
241,766
227,825
191,633
175,547
166,691
175,868
179,529
162,447
174,672
167,325
184,109
208,812
248,847
234,497
197,246
180,688
171,573
181,019
183,980
166,475
179,003
171,474
188,673
213,989
255,016
240,311
202,136
185,168
175,827
185,507
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2026
2027
2027
2027
2027
2027
2027
2027
2027
2027
2027
2027
2027
2028
2028
2028
2028
2028
2028
2028
2028
2028
2028
2028
2028
2029
2029
2029
2029
2029
2029
2029
2029
2029
2029
2029
2029
2030
2030
2030
2030
2030
2030
2030
2030
2030
2030
2030
2030
482.3
482.3
482.3
482.3
482.3
482.3
482.3
482.3
482.3
482.3
482.3
482.3
495.3
495.3
495.3
495.3
495.3
495.3
495.3
495.3
495.3
495.3
495.3
495.3
508.7
508.7
508.7
508.7
508.7
508.7
508.7
508.7
508.7
508.7
508.7
508.7
522.4
522.4
522.4
522.4
522.4
522.4
522.4
522.4
522.4
522.4
522.4
522.4
536.6
536.6
536.6
536.6
536.6
536.6
536.6
536.6
536.6
536.6
536.6
536.6
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
312.6
311.1
304.4
331.5
371.6
466.0
482.3
474.8
471.3
334.9
316.6
331.4
321.0
319.5
312.6
340.4
381.6
478.6
495.3
487.6
484.1
344.0
325.1
340.4
329.7
328.1
321.0
349.6
391.9
491.5
508.7
500.8
497.1
353.3
333.9
349.6
338.6
337.0
329.7
359.0
402.5
504.7
522.4
514.3
510.6
362.8
342.9
359.0
347.7
346.1
338.6
368.7
413.4
518.4
536.6
528.2
524.3
372.6
352.2
368.7
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,410,943
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,476,038
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,548,370
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,611,549
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
2,682,061
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
0.078
0.071
0.076
0.073
0.080
0.091
0.109
0.102
0.086
0.079
0.075
0.079
188,948
170,970
183,836
176,103
193,767
219,766
261,902
246,799
207,593
190,168
180,574
190,516
194,049
175,586
188,799
180,858
198,999
225,700
268,973
253,463
213,198
195,302
185,450
195,660
199,718
180,715
194,315
186,142
204,812
232,294
276,831
260,867
219,427
201,007
190,867
201,375
204,669
185,195
199,132
190,756
209,890
238,052
283,694
267,335
224,867
205,991
195,599
206,368
210,196
190,196
204,509
195,907
215,557
244,480
291,354
274,553
230,938
211,553
200,881
211,940
Appendix II-Resource Operating Information and Other
Modeling Assumptions
General Assumptions
9 15-year Net Present Value of incremental production expenses:
January 2016 to December 2030 time frame, NPV in 2015 dollars
Financial Assumptions
9 Interest Rate:
5.0% / 6.5% / 8.0% (min / likely / max)
9 Financing Period: 30 Years
9 Inflation Rate:
1.5% / 2.5% / 3.5% (min / likely / max)
9 Discount Rate:
8.0%
Existing Resource Assumptions
Hydro Units:
9 2.68 MW capacity
9 $0.98/MWh VO&M cost (2006$)
9 Dispatched first after CROD up to maximum capacity each hour
Silver Lake Plant:
9 45 MW or 92 MW capacity
9 Unit 4 assumed to be only unit to dispatch
9 10,500 Btu/kWh heat rate
9 $1.88/MMBtu fuel cost (2004$) from EIA data for reported fuel receipts at plant
9 $6.17/MWh VO&M cost (2006$) from O&M allocation file provided by RPU,
escalating at 2.5% per year
9 $4.3 million in 2006 to $6.0 million in 2030 total capital and FO&M for Unit 4
Existing TwinPac CT:
9 49 MW capacity
9 11,100 Btu/kWh heat rate, assumed at 80% average load based on info from RPU
9 $3.89/MWh VO&M cost (2006$) from O&M allocation file provided by RPU,
escalating at 2.5% per year
9 No fixed costs (debt service, fixed O&M, etc.) included
New Resource Assumptions
New Coal Unit Purchase:
9 500 MW total capacity
9 9,622 Btu/kWh heat rate, PRB fuel
9 $1,958/kW for 2015 online date - $149/kW-yr debt service cost
9 $2.09/MWh VO&M cost (2004$)
9 $20.47/kW-yr FO&M (2004$)
9 0.11
lb/MMBtu SO2 at $1,122/ton, no escalation
9 0.05 lb/MMBtu NOX at $1,491/ton, no escalation
9 $3.732/kW-mo transmission cost for new unit, no escalation
New Combined Cycle Unit Purchase:
9 125 MW total capacity
9 7,763 Btu/kWh heat rate
9 $1,136/kW for 2015 online date - $87/kW-yr debt service cost
9 $2.81/MWh VO&M cost (2004$)
9 $14.02/kW-yr FO&M (2004$)
New LMS100 High-Efficiency Combustion Turbine:
9 100 MW total capacity
9 9,379 Btu/kWh heat rate
9 $629/kW for 2020 online date - $48/kW-yr debt service cost
9 $3.30/MWh VO&M cost (2004$)
New FT8 TwinPac Combustion Turbines:
9 50 MW total capacity
9 11,100 Btu/kWh heat rate
9 $789/kW for 2015 online date - $60/kW-yr debt service cost
9 $3.89/MWh VO&M cost (2004$)
9 $11.44/kW-mo FO&M cost (2004$)
On-Peak Non-Firm Market Energy:
9 Historical Henry Hub natural gas prices used to calculate an implied heat rate for each
day of historical MAIN market peak prices (2001-2003)
9 Monthly implied heat rates used to calculate market price based on current monthly
gas price:
Jan
8,300 Btu/kWh
Jul
11,400 Btu/kWh
Feb 7,590 Btu/kWh
Aug 9,870 Btu/kWh
Mar 8,300 Btu/kWh
Sep 6,970 Btu/kWh
Apr 7,590 Btu/kWh
Oct
6,860 Btu/kWh
May 5,810 Btu/kWh
Nov 7,170 Btu/kWh
Jun
6,480 Btu/kWh
Dec 6,260 Btu/kWh
Load Forecast
Year
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
MW
369.5
379.5
389.7
400.3
411.1
422.2
433.6
445.3
457.3
469.6
GWh
1,851
1,897
1,948
2,001
2,059
2,110
2,167
2,226
2,291
2,348
2026
2027
2028
2029
2030
482.3
495.3
508.7
522.4
536.6
2,411
2,476
2,548
2,612
2,682
9 Monthly pattern applied to annual peak demand and total energy:
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Ratio to Annual Peak
0.648
0.645
0.631
0.687
0.770
0.966
1.000
0.984
0.977
0.694
0.656
0.687
Ratio to Annual Total Energy
0.0784
0.0709
0.0763
0.0730
0.0804
0.0912
0.1086
0.1024
0.0861
0.0789
0.0749
0.0790
Fuel Assumptions
Year
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Henry Hub Gas Trans.
($/MMBtu) ($/MMBtu)
7.39
0.54
7.65
0.55
7.92
0.56
8.20
0.58
8.49
0.59
8.78
0.61
9.09
0.62
9.41
0.64
9.75
0.66
10.09
0.67
10.45
0.69
10.81
0.71
11.19
0.72
11.59
0.74
12.00
0.76
PRB Coal,
Minemouth
($/MMBtu)
0.58
0.59
0.61
0.63
0.65
0.67
0.69
0.71
0.73
0.75
0.77
0.80
0.82
0.85
0.87
PRB Coal
Transportation
($/MMBtu)
0.83
0.85
0.87
0.90
0.92
0.94
0.97
0.99
1.01
1.04
1.07
1.09
1.12
1.15
1.18
FO#2
($/MMBtu)
6.96
7.14
7.31
7.50
7.69
7.88
8.07
8.28
8.48
8.70
8.91
9.14
9.36
9.60
9.84
9 Monthly pattern applied to annual average natural gas price:
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Ratio to Annual Average
1.088
1.079
1.049
0.968
0.959
0.961
0.965
0.968
0.966
0.969
0.999
1.031
Case Assumptions
Existing Capacity
Case
None216-100Coal
None216-50Coal
None216-100CC
None216-LMS100
None216-SC
4521650Coal_CoalFirst
4521650Coal_SLPfirst
45216-100CC
45216-LMS100
45216-SC
All21650Coal_CoalFirst
All21650Coal_SLPfirst
All216-100CC
All216-LMS100
All216-SC
CROD Other
216
51
216
51
216
51
Capacity Added - MW(year)
Combined
SLP Coal
Cycle
Twin Pac
0 100(15)
50(15) 50(20) 50(25)
0 50(15)
100(15) 50(20) 50(25)
0
100(15) 50(15) 50(20) 50(25)
216
216
51
51
0
0
216
51
45
216
216
216
216
51
51
51
51
216
216
216
216
216
100(15)
50(15) 50(20)
150(15) 50(20)
50(25)
50(25)
50(15)
50(15) 50(20)
50(25)
45
45
45
45
50(15)
50(15) 50(20)
100(15)
50(20)
100(15)
50(20)
100(15) 50(20)
50(25)
50(25)
50(25)
50(25)
51
92
50(15)
50(20)
50(25)
51
51
51
51
92
92
92
92
50(15)
50(20)
50(25)
50(20)
50(20)
50(15) 50(20)
50(25)
100(20)
100(20)
None, 45, All refers to amount of Silver Lake Plant available
166 or 216 refers to CROD amount
MWCoal refers to amount of coal capacity added in case
MWCC refers to combined cycle added in case
SC refers to only simple cycle TwinPac units added
Appendix III – Production Cost Analysis Details
Financial Analysis
None216-100CC
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
0
74
0
0
47
1,851
1,740
11
0
85
1
0
60
1,897
2018
1,760
13
0
93
4
0
78
1,948
2019
1,777
15
0
102
8
0
100
2,001
2020
1,796
16
0
110
0
0
138
2,059
2021
1,805
16
0
115
4
0
170
2,110
2022
1,817
17
0
122
8
0
203
2,167
2023
1,829
17
0
128
16
0
236
2,226
2024
1,844
18
0
135
27
0
266
2,291
2025
1,850
18
0
142
11
0
326
2,348
2026
1,859
19
0
150
24
0
359
2,411
2027
1,868
19
0
158
42
0
389
2,476
2028
1,881
20
0
166
60
0
422
2,548
2029
1,883
20
0
175
84
0
449
2,612
2030
1,888
21
0
183
113
4
473
2,682
$12
$0
$4,708
$0
$0
$2,405
$7,125
$15
$0
$5,576
$68
$0
$3,182
$8,840
$18
$0
$6,329
$402
$0
$4,488
$11,237
$21
$0
$7,202
$780
$0
$6,141
$14,143
$23
$0
$8,060
$0
$0
$8,913
$16,996
$24
$0
$8,802
$418
$0
$11,594
$20,839
$26
$0
$9,620
$915
$0
$14,584
$25,145
$27
$0
$10,516
$1,781
$0
$17,738
$30,061
$29
$0
$11,496
$3,200
$0
$20,886
$35,611
$30
$0
$12,567
$1,322
$0
$26,505
$40,425
$32
$0
$13,727
$3,038
$0
$30,259
$47,056
$33
$0
$14,993
$5,445
$0
$33,893
$54,364
$35
$0
$16,372
$8,096
$0
$37,940
$62,444
$37
$0
$17,884
$11,754
$0
$41,621
$71,296
$39
$0
$19,340
$16,245
$628
$45,289
$81,541
DEMAND/FIXED COST ($000)
New CC
New CT
Total Fixed Costs
$14,591
$3,776
$18,367
$14,650
$3,795
$18,445
$14,710
$3,815
$18,525
$14,772
$3,835
$18,607
$14,836
$8,106
$22,942
$14,901
$8,149
$23,049
$14,968
$8,192
$23,160
$15,036
$8,237
$23,273
$15,106
$8,282
$23,388
$15,178
$13,138
$28,316
$15,251
$13,210
$28,462
$15,327
$13,284
$28,611
$15,404
$13,360
$28,764
$15,483
$13,438
$28,921
$15,564
$13,517
$29,082
TOTAL COST
$25,492
$27,285
$29,762
$32,750
$39,938
$43,888
$48,304
$53,334
$59,000
$68,741
$75,517
$82,975
$91,208
$100,217
$110,623
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
$435,755
$1.32
$1.35
$1.38
$1.42
$1.45
$1.49
$1.53
$1.56
$1.60
$1.64
$1.68
$1.73
$1.77
$1.81
$1.86
$260.22
$238.60
$93.03
$226.79
$96.19
$216.02
$99.46
$208.72
$205.38
$106.34
$202.32
$109.96
$199.60
$113.79
$197.22
$117.75
$195.19
$121.58
$193.58
$125.89
$192.31
$130.26
$191.38
$134.73
$190.74
$139.38
$50.92
$53.02
$57.49
$61.45
$64.52
$68.32
$71.83
$75.28
$78.41
$81.23
$84.30
$87.09
$89.98
$92.67
$191.16
$144.21
$3,240.01
$95.74
Financial Analysis
45216-LMS100-50Coal
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
LMS100
CTs
New CT
On-Peak Market Energy
Total Energy
2017
1,721
9
0
87
21
0
0
13
1,851
1,740
11
0
99
26
3
0
17
1,897
2018
1,760
13
0
116
31
7
0
21
1,948
2019
1,777
15
0
134
36
12
0
28
2,001
2020
1,796
16
169
65
12
0
0
2
2,059
2021
1,805
16
195
71
17
0
0
5
2,110
2022
1,817
17
222
78
22
0
0
10
2,167
2023
1,829
17
249
86
27
2
0
16
2,226
2024
1,844
18
273
97
32
6
0
20
2,291
2025
1,850
18
292
111
38
0
0
38
2,348
2026
1,859
19
308
130
44
4
0
47
2,411
2027
1,868
19
320
153
51
10
0
55
2,476
2028
1,881
20
331
180
57
17
0
63
2,548
2029
1,883
20
340
206
64
29
0
70
2,612
2030
1,888
21
349
228
72
41
0
83
2,682
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
LMS100
CTs
New CT
On-Peak Market Energy
Total Variable Costs
$12
$0
$3,147
$1,628
$0
$0
$935
$5,721
$15
$0
$3,697
$2,048
$274
$0
$1,212
$7,245
$18
$0
$4,440
$2,513
$687
$0
$1,460
$9,118
$21
$0
$5,277
$3,033
$1,191
$0
$1,883
$11,404
$23
$3,230
$2,635
$1,076
$0
$0
$139
$7,103
$24
$3,831
$2,974
$1,526
$0
$0
$492
$8,847
$26
$4,472
$3,365
$2,028
$0
$0
$938
$10,829
$27
$5,130
$3,782
$2,591
$206
$0
$1,427
$13,163
$29
$5,771
$4,401
$3,222
$769
$0
$1,714
$15,906
$30
$6,341
$5,208
$3,925
$0
$0
$3,380
$18,884
$32
$6,846
$6,256
$4,705
$537
$0
$4,184
$22,561
$33
$7,298
$7,586
$5,573
$1,275
$0
$4,978
$26,742
$35
$7,742
$9,146
$6,534
$2,343
$0
$5,734
$31,534
$37
$8,160
$10,794
$7,588
$3,992
$0
$6,471
$37,041
$39
$8,605
$12,273
$8,747
$5,877
$0
$7,817
$43,358
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
SLP (Unit 4 Upgrade/FO&M)
LMS100
New CT
Total Fixed Costs
$0
$4,903
$4,790
$0
$9,693
$0
$4,974
$4,790
$0
$9,764
$0
$5,045
$4,790
$0
$9,835
$0
$5,119
$4,790
$0
$9,909
$12,196
$5,195
$4,790
$0
$22,180
$12,234
$5,272
$4,790
$0
$22,296
$12,273
$5,351
$4,790
$0
$22,414
$12,312
$5,433
$4,790
$0
$22,535
$12,353
$5,516
$4,790
$0
$22,660
$12,395
$5,602
$4,790
$4,809
$27,596
$12,438
$5,689
$4,790
$4,833
$27,751
$12,482
$5,779
$4,790
$4,858
$27,909
$12,527
$5,871
$4,790
$4,883
$28,072
$12,574
$5,965
$4,790
$4,909
$28,238
$12,621
$6,062
$4,790
$4,935
$28,409
$15,415
$17,009
$18,954
$21,314
$29,283
$31,143
$33,243
$35,699
$38,566
$46,480
$50,311
$54,651
$59,605
$65,279
$71,767
TOTAL COST
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
$288,674
$1.32
$1.35
$1.38
$1.42
$92.43
$300.87
$87.20
$263.49
$93.62
$81.74
$237.07
$96.80
$77.56
$217.60
$100.07
$72.05
$70.46
$69.33
$68.23
$1.45
$91.36
$120.36
$475.65
$1.49
$82.25
$115.58
$373.33
$1.53
$75.31
$111.12
$313.56
$1.56
$70.14
$107.55
$274.74
$114.43
$1.60
$66.44
$102.35
$247.96
$118.33
$1.64
$64.11
$97.01
$228.97
$1.68
$62.68
$91.84
$215.19
$126.53
$1.73
$61.86
$87.20
$205.05
$130.84
$1.77
$61.28
$83.63
$197.62
$135.21
$1.81
$61.01
$81.38
$192.36
$139.70
$1.86
$60.75
$80.58
$188.72
$144.40
$86.89
$89.90
$90.59
$87.75
$86.04
$89.98
$89.72
$89.97
$91.27
$92.86
$93.86
Financial Analysis
45216-LMS100
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
LMS100
CTs
On-Peak Market Energy
Total Energy
2017
1,721
9
87
21
0
13
1,851
1,740
11
99
26
3
17
1,897
2018
1,760
13
116
31
7
21
1,948
2019
1,777
15
134
36
12
28
2,001
2020
1,796
16
155
41
4
48
2,059
2021
1,805
16
178
47
9
56
2,110
2022
1,817
17
202
53
15
64
2,167
2023
1,829
17
223
59
25
72
2,226
2024
1,844
18
233
66
35
94
2,291
2025
1,850
18
237
72
22
149
2,348
2026
1,859
19
237
74
33
189
2,411
2027
1,868
19
237
74
47
231
2,476
2028
1,881
20
237
74
64
272
2,548
2029
1,883
20
237
74
75
314
2,612
2030
1,888
21
237
74
87
360
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
LMS100
CTs
On-Peak Market Energy
Total Variable Costs
$12
$3,147
$1,628
$0
$935
$5,721
$15
$3,697
$2,048
$274
$1,212
$7,245
$18
$4,440
$2,513
$687
$1,460
$9,118
$21
$5,277
$3,033
$1,191
$1,883
$11,404
$23
$6,273
$3,610
$389
$3,486
$13,780
$24
$7,405
$4,244
$922
$4,087
$16,682
$26
$8,648
$4,942
$1,615
$4,727
$19,957
$27
$9,859
$5,708
$2,805
$5,424
$23,823
$29
$10,603
$6,543
$4,135
$7,218
$28,528
$30
$11,055
$7,451
$2,639
$11,889
$33,064
$32
$11,376
$7,934
$4,171
$15,721
$39,234
$33
$11,707
$8,204
$6,158
$20,077
$46,179
$35
$12,047
$8,484
$8,638
$24,733
$54,041
$37
$12,397
$8,773
$10,533
$29,758
$62,558
$39
$12,757
$9,072
$12,616
$35,398
$71,991
DEMAND/FIXED COST ($000)
SLP (Unit 4 Upgrade/FO&M)
LMS100
New CT
Total Fixed Costs
$4,903
$4,790
$0
$9,693
$4,974
$4,790
$0
$9,764
$5,045
$4,790
$0
$9,835
$5,119
$4,790
$0
$9,909
$5,195
$4,790
$4,251
$14,235
$5,272
$4,790
$4,272
$14,334
$5,351
$4,790
$4,294
$14,435
$5,433
$4,790
$4,316
$14,539
$5,516
$4,790
$4,339
$14,645
$5,602
$4,790
$9,171
$19,563
$5,689
$4,790
$9,219
$19,699
$5,779
$4,790
$9,269
$19,838
$5,871
$4,790
$9,319
$19,980
$5,965
$4,790
$9,371
$20,126
$6,062
$4,790
$9,424
$20,276
$15,415
$17,009
$18,954
$21,314
$28,016
$31,016
$34,392
$38,362
$43,173
$52,627
$58,932
$66,017
$74,022
$82,684
$92,267
TOTAL COST
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
$320,892
$1.32
$92.43
$300.87
$1.35
$87.20
$263.49
$93.62
$1.38
$81.74
$237.07
$96.80
$1.42
$77.56
$217.60
$100.07
$1.45
$74.05
$202.97
$103.50
$1.49
$71.36
$191.99
$107.02
$1.53
$69.44
$183.67
$110.62
$1.56
$68.46
$177.37
$114.27
$1.60
$69.05
$172.73
$118.10
$1.64
$70.42
$169.41
$122.23
$1.68
$72.15
$171.02
$126.31
$1.73
$73.93
$174.65
$130.58
$72.05
$70.46
$69.33
$68.23
$72.87
$73.33
$74.21
$75.13
$76.49
$79.82
$83.26
$87.08
$1.77
$75.76
$178.41
$135.00
$12,062.71
$90.90
$1.81
$77.64
$182.30
$139.56
$1,377.23
$94.64
$1.86
$79.57
$186.32
$144.29
$791.61
$98.40
Financial Analysis
45216-50coal (Dispatch New Coal First)
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
86
31
0
4
1,851
1,740
11
101
37
0
8
1,897
2018
1,760
13
120
42
0
12
1,948
2019
1,777
15
143
48
0
18
2,001
2020
1,796
16
169
54
0
25
2,059
2021
1,805
16
195
60
0
33
2,110
2022
1,817
17
222
68
0
43
2,167
2023
1,829
17
249
77
0
54
2,226
2024
1,844
18
273
90
0
66
2,291
2025
1,850
18
292
108
0
79
2,348
2026
1,859
19
308
130
0
95
2,411
2027
1,868
19
320
157
0
112
2,476
2028
1,881
20
331
185
1
132
2,548
2029
1,883
20
340
212
7
150
2,612
2030
1,888
21
349
236
13
174
2,682
$12
$1,484
$1,127
$0
$347
$2,969
$15
$1,790
$1,371
$0
$613
$3,789
$18
$2,189
$1,625
$0
$994
$4,827
$21
$2,676
$1,893
$0
$1,511
$6,100
$23
$3,230
$2,184
$0
$2,167
$7,603
$24
$3,831
$2,517
$0
$2,964
$9,337
$26
$4,472
$2,903
$0
$3,916
$11,317
$27
$5,130
$3,401
$0
$5,030
$13,588
$29
$5,771
$4,092
$0
$6,331
$16,222
$30
$6,341
$5,042
$0
$7,854
$19,267
$32
$6,846
$6,274
$0
$9,635
$22,787
$33
$7,298
$7,752
$0
$11,722
$26,805
$35
$7,742
$9,400
$78
$14,102
$31,358
$37
$8,160
$11,097
$924
$16,278
$36,497
$39
$8,605
$12,721
$1,884
$19,135
$42,385
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
SLP (Unit 4 Upgrade/FO&M)
New CT
Total Fixed Costs
$11,202
$4,903
$3,828
$19,934
$11,237
$4,974
$3,847
$20,057
$11,272
$5,045
$3,867
$20,184
$11,308
$5,119
$3,887
$20,314
$11,345
$5,195
$8,217
$24,757
$11,383
$5,272
$8,260
$24,915
$11,422
$5,351
$8,303
$25,077
$11,462
$5,433
$8,348
$25,243
$11,503
$5,516
$8,394
$25,413
$11,545
$5,602
$13,317
$30,463
$11,588
$5,689
$13,389
$30,666
$11,632
$5,779
$13,462
$30,873
$11,677
$5,871
$13,538
$31,086
$11,723
$5,965
$13,616
$31,305
$11,771
$6,062
$13,695
$31,528
TOTAL COST
$22,903
$23,847
$25,011
$26,414
$32,361
$34,252
$36,394
$38,831
$41,635
$49,730
$53,453
$57,678
$62,444
$67,801
$73,914
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
SLP
Existing CT
New CT
On-Peak Market Energy
$325,782
$1.32
$147.97
$193.40
$1.35
$129.13
$172.05
$1.38
$111.87
$157.02
$1.42
$97.50
$145.85
$1.45
$86.32
$136.87
$1.49
$77.90
$129.00
$1.53
$71.49
$121.97
$1.56
$66.72
$114.64
$1.60
$63.32
$106.66
$1.64
$61.20
$98.67
$1.68
$59.91
$91.71
$1.73
$59.20
$86.40
$1.77
$58.71
$82.75
$134.92
$1.81
$58.50
$80.59
$139.53
$1.86
$58.32
$79.64
$144.29
$77.33
$79.12
$81.49
$83.93
$86.39
$88.87
$91.36
$93.92
$96.57
$99.20
$101.82
$104.42
$106.93
$108.38
$109.76
Financial Analysis
45216-50Coal (Dispatch SLP First)
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
80
37
0
4
1,851
1,740
11
95
43
0
8
1,897
2018
1,760
13
114
49
0
12
1,948
2019
1,777
15
136
56
0
18
2,001
2020
1,796
16
160
63
0
25
2,059
2021
1,805
16
186
70
0
33
2,110
2022
1,817
17
211
79
0
43
2,167
2023
1,829
17
234
91
0
54
2,226
2024
1,844
18
255
108
0
66
2,291
2025
1,850
18
270
130
0
79
2,348
2026
1,859
19
282
156
0
95
2,411
2027
1,868
19
292
185
0
112
2,476
2028
1,881
20
301
214
1
132
2,548
2029
1,883
20
309
242
7
150
2,612
2030
1,888
21
317
268
13
174
2,682
$12
$1,389
$1,325
$0
$347
$3,073
$15
$1,682
$1,597
$0
$613
$3,908
$18
$2,066
$1,885
$0
$994
$4,963
$21
$2,534
$2,192
$0
$1,511
$6,257
$23
$3,065
$2,532
$0
$2,167
$7,787
$24
$3,641
$2,920
$0
$2,964
$9,550
$26
$4,242
$3,395
$0
$3,916
$11,578
$27
$4,833
$4,035
$0
$5,030
$13,926
$29
$5,385
$4,921
$0
$6,331
$16,665
$30
$5,858
$6,082
$0
$7,854
$19,825
$32
$6,275
$7,509
$0
$9,635
$23,451
$33
$6,658
$9,138
$0
$11,722
$27,552
$35
$7,051
$10,904
$78
$14,102
$32,171
$37
$7,422
$12,708
$924
$16,278
$37,370
$39
$7,820
$14,442
$1,884
$19,136
$43,321
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
SLP (Unit 4 Upgrade/FO&M)
New CT
Total Fixed Costs
$11,202
$4,903
$3,828
$19,934
$11,237
$4,974
$3,847
$20,057
$11,272
$5,045
$3,867
$20,184
$11,308
$5,119
$3,887
$20,314
$11,345
$5,195
$8,217
$24,757
$11,383
$5,272
$8,260
$24,915
$11,422
$5,351
$8,303
$25,077
$11,462
$5,433
$8,348
$25,243
$11,503
$5,516
$8,394
$25,413
$11,545
$5,602
$13,317
$30,463
$11,588
$5,689
$13,389
$30,666
$11,632
$5,779
$13,462
$30,873
$11,677
$5,871
$13,538
$31,086
$11,723
$5,965
$13,616
$31,305
$11,771
$6,062
$13,695
$31,528
TOTAL COST
$23,007
$23,965
$25,147
$26,572
$32,545
$34,465
$36,655
$39,169
$42,078
$50,288
$54,116
$58,426
$63,257
$68,674
$74,849
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
SLP
Existing CT
New CT
On-Peak Market Energy
$328,750
$1.32
$156.92
$169.82
$1.35
$136.27
$152.96
$1.38
$117.47
$140.65
$1.42
$101.92
$131.29
$1.45
$89.93
$123.60
$1.49
$80.94
$116.94
$1.53
$74.28
$110.51
$1.56
$69.55
$103.57
$1.60
$66.35
$96.34
$1.64
$64.45
$89.79
$1.68
$63.34
$84.54
$1.73
$62.69
$80.80
$1.77
$62.18
$78.36
$134.92
$1.81
$61.94
$77.02
$139.53
$1.86
$61.70
$76.58
$144.29
$77.33
$79.12
$81.49
$83.93
$86.39
$88.87
$91.36
$93.92
$96.57
$99.20
$101.82
$104.42
$106.93
$108.38
$109.76
Financial Analysis
All216-50coal (Dispatch New Coal Unit First)
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
86
31
0
4
1,851
1,740
11
101
37
0
8
1,897
2018
1,760
13
120
42
0
12
1,948
2019
1,777
15
143
48
0
18
2,001
2020
1,796
16
169
54
0
25
2,059
2021
1,805
16
195
60
0
33
2,110
2022
1,817
17
222
68
0
43
2,167
2023
1,829
17
249
77
0
54
2,226
2024
1,844
18
273
90
4
61
2,291
2025
1,850
18
292
108
0
79
2,348
2026
1,859
19
308
130
2
93
2,411
2027
1,868
19
320
157
7
105
2,476
2028
1,881
20
331
185
13
119
2,548
2029
1,883
20
340
212
22
135
2,612
2030
1,888
21
349
236
34
153
2,682
$12
$1,484
$1,127
$0
$347
$2,969
$15
$1,790
$1,371
$0
$613
$3,789
$18
$2,189
$1,625
$0
$994
$4,827
$21
$2,676
$1,893
$0
$1,511
$6,100
$23
$3,230
$2,184
$0
$2,167
$7,603
$24
$3,831
$2,517
$0
$2,964
$9,337
$26
$4,472
$2,903
$0
$3,916
$11,317
$27
$5,130
$3,401
$0
$5,030
$13,588
$29
$5,771
$4,092
$524
$5,822
$16,237
$30
$6,341
$5,042
$0
$7,854
$19,267
$32
$6,846
$6,274
$237
$9,404
$22,794
$33
$7,298
$7,752
$951
$10,797
$26,831
$35
$7,742
$9,400
$1,751
$12,473
$31,402
$37
$8,160
$11,097
$3,095
$14,222
$36,611
$39
$8,605
$12,721
$4,930
$16,332
$42,628
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
SLP (Unit 4 Upgrade/FO&M)
SLP (Unit 1-3 FO&M)
New CT
Total Fixed Costs
$11,202
$4,903
$3,547
$0
$19,653
$11,237
$4,974
$3,636
$0
$19,846
$11,272
$5,045
$3,727
$0
$20,044
$11,308
$5,119
$3,820
$0
$20,247
$11,345
$5,195
$3,915
$4,310
$24,765
$11,383
$5,272
$4,013
$4,331
$25,000
$11,422
$5,351
$4,114
$4,353
$25,240
$11,462
$5,433
$4,216
$4,375
$25,486
$11,503
$5,516
$4,322
$4,398
$25,739
$11,545
$5,602
$4,430
$9,297
$30,874
$11,588
$5,689
$4,541
$9,345
$31,163
$11,632
$5,779
$4,654
$9,394
$31,460
$11,677
$5,871
$4,771
$9,445
$31,764
$11,723
$5,965
$4,890
$9,497
$32,075
$11,771
$6,062
$5,012
$9,550
$32,395
TOTAL COST
$22,622
$23,636
$24,871
$26,347
$32,368
$34,336
$36,557
$39,074
$41,976
$50,141
$53,957
$58,290
$63,166
$68,686
$75,022
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
SLP
Existing CT
New CT
On-Peak Market Energy
$327,201
$1.32
$147.97
$193.40
$1.35
$129.13
$172.05
$1.38
$111.87
$157.02
$1.42
$97.50
$145.85
$1.45
$86.32
$136.87
$1.49
$77.90
$129.00
$1.53
$71.49
$121.97
$1.56
$66.72
$114.64
$1.60
$63.32
$106.66
$118.00
$1.64
$61.20
$98.67
$1.68
$59.91
$91.71
$126.17
$1.73
$59.20
$86.40
$130.47
$1.77
$58.71
$82.75
$134.92
$1.81
$58.50
$80.59
$139.58
$1.86
$58.32
$79.64
$144.39
$77.33
$79.12
$81.49
$83.93
$86.39
$88.87
$91.36
$93.92
$95.26
$99.20
$101.39
$102.86
$104.40
$105.62
$106.56
Financial Analysis
None216-50Coal
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
86
0
0
36
1,851
1,740
11
101
0
0
45
1,897
2018
1,760
13
120
0
0
55
1,948
2019
1,777
15
143
0
0
66
2,001
2020
1,796
16
169
0
0
79
2,059
2021
1,805
16
195
0
0
94
2,110
2022
1,817
17
222
0
0
111
2,167
2023
1,829
17
249
0
0
131
2,226
2024
1,844
18
273
0
3
153
2,291
2025
1,850
18
292
0
0
187
2,348
2026
1,859
19
308
0
2
223
2,411
2027
1,868
19
320
0
9
260
2,476
2028
1,881
20
331
0
16
301
2,548
2029
1,883
20
340
0
27
341
2,612
2030
1,888
21
349
0
41
382
2,682
$12
$1,484
$0
$0
$2,662
$4,157
$15
$1,790
$0
$0
$3,423
$5,229
$18
$2,189
$0
$0
$4,313
$6,521
$21
$2,676
$0
$0
$5,355
$8,051
$23
$3,230
$0
$0
$6,571
$9,824
$24
$3,831
$0
$0
$7,998
$11,853
$26
$4,472
$0
$0
$9,669
$14,167
$27
$5,130
$0
$0
$11,696
$16,853
$29
$5,771
$0
$360
$13,893
$20,052
$30
$6,341
$0
$0
$17,473
$23,844
$32
$6,846
$0
$310
$21,177
$28,365
$33
$7,298
$0
$1,158
$25,126
$33,615
$35
$7,742
$0
$2,110
$29,676
$39,564
$37
$8,160
$0
$3,789
$34,267
$46,254
$39
$8,605
$0
$5,902
$39,181
$53,727
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
New CT
Total Fixed Costs
$11,073
$7,551
$18,624
$11,107
$7,590
$18,697
$11,142
$7,629
$18,772
$11,179
$7,670
$18,848
$11,216
$11,962
$23,177
$11,254
$12,025
$23,279
$11,293
$12,091
$23,383
$11,333
$12,157
$23,490
$11,373
$12,226
$23,599
$11,415
$17,105
$28,521
$11,458
$17,202
$28,660
$11,502
$17,300
$28,802
$11,548
$17,401
$28,948
$11,594
$17,504
$29,098
$11,641
$17,610
$29,252
TOTAL COST
$22,781
$23,926
$25,292
$26,899
$33,001
$35,132
$37,551
$40,343
$43,651
$52,365
$57,025
$62,418
$68,512
$75,352
$82,979
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
Existing CT
New CT
On-Peak Market Energy
$342,102
$1.32
$146.46
$1.35
$127.85
$1.38
$110.79
$1.42
$96.60
$1.45
$85.55
$1.49
$77.23
$1.53
$70.91
$1.56
$66.20
$1.60
$62.85
$118.00
$1.64
$60.75
$1.68
$59.49
$126.17
$1.73
$58.79
$130.47
$1.77
$58.32
$134.92
$1.81
$58.12
$139.59
$1.86
$57.95
$144.39
$74.62
$76.71
$78.88
$81.04
$83.19
$85.32
$87.47
$89.55
$91.05
$93.41
$95.13
$96.64
$98.47
$100.38
$102.46
Financial Analysis
All216-50coal (Dispatch SLP First)
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
CTs
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
80
37
0
4
1,851
1,740
11
95
43
0
8
1,897
2018
1,760
13
114
49
0
12
1,948
2019
1,777
15
136
56
0
18
2,001
2020
1,796
16
160
63
0
25
2,059
2021
1,805
16
186
70
0
33
2,110
2022
1,817
17
211
79
0
43
2,167
2023
1,829
17
234
91
0
54
2,226
2024
1,844
18
255
108
4
61
2,291
2025
1,850
18
270
130
0
79
2,348
2026
1,859
19
282
156
2
93
2,411
2027
1,868
19
292
185
7
105
2,476
2028
1,881
20
301
214
13
119
2,548
2029
1,883
20
309
242
22
135
2,612
2030
1,888
21
317
268
34
153
2,682
$12
$1,389
$1,325
$0
$347
$3,073
$15
$1,682
$1,597
$0
$613
$3,908
$18
$2,066
$1,885
$0
$994
$4,963
$21
$2,534
$2,192
$0
$1,511
$6,257
$23
$3,065
$2,532
$0
$2,167
$7,787
$24
$3,641
$2,920
$0
$2,964
$9,550
$26
$4,242
$3,395
$0
$3,916
$11,578
$27
$4,833
$4,035
$0
$5,030
$13,926
$29
$5,385
$4,921
$524
$5,822
$16,680
$30
$5,858
$6,082
$0
$7,854
$19,825
$32
$6,275
$7,509
$237
$9,404
$23,457
$33
$6,658
$9,138
$951
$10,797
$27,578
$35
$7,051
$10,904
$1,751
$12,473
$32,215
$37
$7,422
$12,708
$3,095
$14,222
$37,484
$39
$7,820
$14,442
$4,930
$16,333
$43,563
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
SLP (Unit 4 Upgrade/FO&M)
SLP (Unit 1-3 FO&M)
New CT
Total Fixed Costs
$11,202
$4,903
$3,547
$0
$19,653
$11,237
$4,974
$3,636
$0
$19,846
$11,272
$5,045
$3,727
$0
$20,044
$11,308
$5,119
$3,820
$0
$20,247
$11,345
$5,195
$3,915
$4,310
$24,765
$11,383
$5,272
$4,013
$4,331
$25,000
$11,422
$5,351
$4,114
$4,353
$25,240
$11,462
$5,433
$4,216
$4,375
$25,486
$11,503
$5,516
$4,322
$4,398
$25,739
$11,545
$5,602
$4,430
$9,297
$30,874
$11,588
$5,689
$4,541
$9,345
$31,163
$11,632
$5,779
$4,654
$9,394
$31,460
$11,677
$5,871
$4,771
$9,445
$31,764
$11,723
$5,965
$4,890
$9,497
$32,075
$11,771
$6,062
$5,012
$9,550
$32,395
TOTAL COST
$22,726
$23,754
$25,007
$26,505
$32,552
$34,550
$36,818
$39,412
$42,419
$50,698
$54,620
$59,038
$63,979
$69,559
$75,958
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
SLP
Existing CT
New CT
On-Peak Market Energy
$330,169
$1.32
$156.92
$169.82
$1.35
$136.27
$152.96
$1.38
$117.47
$140.65
$1.42
$101.92
$131.29
$1.45
$89.93
$123.60
$1.49
$80.94
$116.94
$1.53
$74.28
$110.51
$1.56
$69.55
$103.57
$1.60
$66.35
$96.34
$118.00
$1.64
$64.45
$89.79
$1.68
$63.34
$84.54
$126.17
$1.73
$62.69
$80.80
$130.47
$1.77
$62.18
$78.36
$134.92
$1.81
$61.94
$77.02
$139.58
$1.86
$61.70
$76.58
$144.39
$77.33
$79.12
$81.49
$83.93
$86.39
$88.87
$91.36
$93.92
$95.26
$99.20
$101.39
$102.86
$104.40
$105.62
$106.56
Financial Analysis
All216-LMS100
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
Total Energy
2017
1,721
9
87
0
0
0
34
1,851
1,740
11
99
0
1
0
45
1,897
2018
1,760
13
116
0
6
0
53
1,948
2019
1,777
15
134
0
11
0
64
2,001
2020
1,796
16
155
41
4
0
48
2,059
2021
1,805
16
178
47
9
0
56
2,110
2022
1,817
17
202
53
15
0
64
2,167
2023
1,829
17
223
59
25
0
72
2,226
2024
1,844
18
233
66
35
0
94
2,291
2025
1,850
18
237
72
50
0
120
2,348
2026
1,859
19
237
74
66
0
155
2,411
2027
1,868
19
237
74
77
7
194
2,476
2028
1,881
20
237
74
88
13
236
2,548
2029
1,883
20
237
74
104
23
271
2,612
2030
1,888
21
237
74
141
36
285
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
$12
$3,147
$0
$0
$0
$2,799
$5,957
$15
$3,697
$0
$131
$0
$3,660
$7,503
$18
$4,440
$0
$604
$0
$4,332
$9,393
$21
$5,277
$0
$1,138
$0
$5,246
$11,681
$23
$6,273
$3,610
$389
$0
$3,486
$13,780
$24
$7,405
$4,244
$922
$0
$4,087
$16,682
$26
$8,648
$4,942
$1,615
$0
$4,727
$19,957
$27
$9,859
$5,708
$2,805
$0
$5,424
$23,823
$29
$10,603
$6,543
$4,135
$0
$7,218
$28,528
$30
$11,055
$7,451
$6,141
$0
$9,493
$34,171
$32
$11,376
$7,934
$8,376
$30
$12,878
$40,625
$33
$11,707
$8,204
$10,043
$864
$16,915
$47,767
$35
$12,047
$8,484
$11,872
$1,783
$21,461
$55,682
$37
$12,397
$8,773
$14,526
$3,171
$25,729
$64,632
$39
$12,757
$9,072
$20,483
$5,185
$28,072
$75,609
DEMAND/FIXED COST ($000)
SLP (Unit 4 Upgrade/FO&M)
SLP (Unit 1-3 FO&M)
LMS100
New CT
Total Fixed Costs
$4,903
$3,547
$0
$3,976
$12,427
$4,974
$3,636
$0
$3,995
$12,605
$5,045
$3,727
$0
$4,015
$12,787
$5,119
$3,820
$0
$4,035
$12,974
$5,195
$3,915
$5,109
$4,056
$18,275
$5,272
$4,013
$5,109
$4,077
$18,472
$5,351
$4,114
$5,109
$4,099
$18,673
$5,433
$4,216
$5,109
$4,121
$18,880
$5,516
$4,322
$5,109
$4,144
$19,092
$5,602
$4,430
$5,109
$4,168
$19,308
$5,689
$4,541
$5,109
$4,192
$19,531
$5,779
$4,654
$5,109
$4,216
$19,759
$5,871
$4,771
$5,109
$4,241
$19,992
$5,965
$4,890
$5,109
$4,267
$20,232
$6,062
$5,012
$5,109
$4,294
$20,477
TOTAL COST
$18,384
$20,107
$22,181
$24,656
$32,056
$35,154
$38,630
$42,703
$47,619
$53,479
$60,156
$67,526
$75,674
$84,864
$96,086
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
$347,789
$1.32
$92.43
$81.57
$1.35
$87.20
$1.38
$81.74
$1.42
$77.56
$99.82
$1.45
$74.05
$210.69
$103.50
$1.49
$71.36
$198.77
$107.02
$1.53
$69.44
$189.69
$110.62
$1.56
$68.46
$182.77
$114.27
$1.60
$69.05
$177.60
$118.10
$1.64
$70.42
$173.83
$122.10
$93.36
$96.53
$81.93
$82.18
$81.90
$72.87
$73.33
$74.21
$75.13
$76.49
$78.95
$1.68
$72.15
$175.31
$126.24
$17,836.07
$82.95
$1.73
$73.93
$178.94
$130.51
$769.03
$87.12
$1.77
$75.76
$182.70
$134.93
$457.07
$91.06
$1.81
$77.64
$186.59
$139.51
$327.97
$95.05
$1.86
$79.57
$190.61
$145.41
$264.09
$98.50
Financial Analysis
45216-SC
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
Total Energy
2017
1,721
9
87
0
0
34
1,851
1,740
11
99
0
0
46
1,897
2018
1,760
13
116
0
0
59
1,948
2019
1,777
15
134
0
0
75
2,001
2020
1,796
16
155
0
0
93
2,059
2021
1,805
16
178
0
0
111
2,110
2022
1,817
17
202
4
0
128
2,167
2023
1,829
17
223
10
0
146
2,226
2024
1,844
18
233
16
0
179
2,291
2025
1,850
18
237
11
0
232
2,348
2026
1,859
19
237
17
0
279
2,411
2027
1,868
19
237
30
0
322
2,476
2028
1,881
20
237
44
0
367
2,548
2029
1,883
20
237
58
3
412
2,612
2030
1,888
21
237
71
10
455
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
$12
$3,147
$0
$0
$2,799
$5,957
$15
$3,697
$0
$0
$3,787
$7,498
$18
$4,440
$0
$0
$4,917
$9,374
$21
$5,277
$0
$0
$6,349
$11,646
$23
$6,273
$0
$0
$7,954
$14,249
$24
$7,405
$0
$0
$9,733
$17,162
$26
$8,648
$401
$0
$11,342
$20,416
$27
$9,859
$1,122
$0
$13,071
$24,079
$29
$10,603
$1,919
$0
$16,002
$28,553
$30
$11,055
$1,282
$0
$21,313
$33,680
$32
$11,376
$2,192
$0
$25,914
$39,513
$33
$11,707
$3,955
$0
$30,353
$46,048
$35
$12,047
$5,960
$0
$35,262
$53,304
$37
$12,397
$8,053
$377
$40,404
$61,268
$39
$12,757
$10,234
$1,495
$45,830
$70,355
DEMAND/FIXED COST ($000)
SLP (Unit 4 Upgrade/FO&M)
New CT
Total Fixed Costs
$4,903
$7,551
$12,455
$4,974
$7,590
$12,563
$5,045
$7,629
$12,675
$5,119
$7,670
$12,789
$5,195
$11,962
$17,156
$5,272
$12,025
$17,297
$5,351
$12,091
$17,442
$5,433
$12,157
$17,590
$5,516
$12,226
$17,742
$5,602
$17,105
$22,707
$5,689
$17,202
$22,891
$5,779
$17,300
$23,079
$5,871
$17,401
$23,272
$5,965
$17,504
$23,470
$6,062
$17,610
$23,673
TOTAL COST
$18,412
$20,062
$22,049
$24,435
$31,406
$34,460
$37,858
$41,669
$46,295
$56,388
$62,404
$69,127
$76,576
$84,738
$94,028
$1.81
$77.64
$139.64
$6,622.75
$98.19
$1.86
$79.57
$144.37
$1,844.19
$100.75
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
$347,544
$1.32
$92.43
$1.35
$87.20
$1.38
$81.74
$1.42
$77.56
$1.45
$74.05
$1.49
$71.36
$1.53
$69.44
$110.35
$1.56
$68.46
$114.11
$1.60
$69.05
$118.00
$1.64
$70.42
$122.02
$1.68
$72.15
$126.17
$1.73
$73.93
$130.55
$1.77
$75.76
$135.03
$81.57
$82.19
$83.38
$84.14
$85.54
$87.37
$88.86
$89.47
$89.54
$91.75
$92.93
$94.32
$96.05
Financial Analysis
None216-100Coal
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
New Coal
SLP
Existing CT
New CT
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
New Coal
SLP
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
118
0
0
0
3
1,851
1,740
11
140
0
0
0
6
1,897
2018
1,760
13
166
0
0
0
9
1,948
2019
1,777
15
195
0
0
0
15
2,001
2020
1,796
16
227
0
0
0
21
2,059
2021
1,805
16
260
0
0
0
29
2,110
2022
1,817
17
295
0
0
0
38
2,167
2023
1,829
17
332
0
0
0
48
2,226
2024
1,844
18
369
0
0
0
59
2,291
2025
1,850
18
407
0
0
0
72
2,348
2026
1,859
19
446
0
0
0
87
2,411
2027
1,868
19
486
0
0
0
103
2,476
2028
1,881
20
526
0
0
0
122
2,548
2029
1,883
20
564
0
4
0
140
2,612
2030
1,888
21
602
0
10
0
161
2,682
$12
$2,045
$0
$0
$0
$254
$2,311
$15
$2,481
$0
$0
$0
$455
$2,951
$18
$3,012
$0
$0
$0
$774
$3,804
$21
$3,637
$0
$0
$0
$1,225
$4,882
$23
$4,339
$0
$0
$0
$1,819
$6,181
$24
$5,107
$0
$0
$0
$2,558
$7,689
$26
$5,939
$0
$0
$0
$3,449
$9,414
$27
$6,839
$0
$0
$0
$4,501
$11,367
$29
$7,812
$0
$0
$0
$5,731
$13,572
$30
$8,838
$0
$0
$0
$7,168
$16,037
$32
$9,930
$0
$0
$0
$8,851
$18,812
$33
$11,082
$0
$0
$0
$10,820
$21,935
$35
$12,309
$0
$0
$0
$13,123
$25,467
$37
$13,553
$0
$534
$0
$15,353
$29,477
$39
$14,818
$0
$1,461
$0
$17,861
$34,179
DEMAND/FIXED COST ($000)
New Coal (Including Transmission)
New CT
Total Fixed Costs
$22,146
$3,776
$25,921
$22,214
$3,795
$26,009
$22,285
$3,815
$26,100
$22,357
$3,835
$26,192
$22,431
$8,106
$30,537
$22,507
$8,149
$30,656
$22,585
$8,192
$30,777
$22,665
$8,237
$30,902
$22,747
$8,282
$31,029
$22,831
$13,138
$35,969
$22,917
$13,210
$36,127
$23,005
$13,284
$36,289
$23,095
$13,360
$36,455
$23,188
$13,438
$36,625
$23,283
$13,517
$36,800
TOTAL COST
$28,232
$28,960
$29,904
$31,074
$36,719
$38,345
$40,191
$42,269
$44,602
$52,006
$54,939
$58,224
$61,923
$66,102
$70,978
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
New Coal
Existing CT
New CT
On-Peak Market Energy
$353,725
$1.32
$204.75
$1.35
$176.66
$1.38
$152.83
$1.42
$133.34
$1.45
$118.02
$1.49
$106.06
$1.53
$96.61
$1.56
$88.99
$1.60
$82.75
$1.64
$77.74
$1.68
$73.61
$1.73
$70.20
$1.77
$67.33
$1.81
$65.09
$139.53
$1.86
$63.33
$144.29
$77.96
$79.60
$81.65
$84.18
$86.64
$89.18
$91.70
$94.27
$96.93
$99.63
$102.30
$104.97
$107.64
$109.58
$111.02
Financial Analysis
All216-SC
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
Total Energy
2017
1,721
9
87
0
0
34
1,851
1,740
11
99
1
0
45
1,897
2018
1,760
13
116
6
0
53
1,948
2019
1,777
15
134
11
0
64
2,001
2020
1,796
16
155
4
0
89
2,059
2021
1,805
16
178
10
0
101
2,110
2022
1,817
17
202
17
0
114
2,167
2023
1,829
17
223
29
0
127
2,226
2024
1,844
18
233
41
0
154
2,291
2025
1,850
18
237
29
0
214
2,348
2026
1,859
19
237
42
0
255
2,411
2027
1,868
19
237
57
0
295
2,476
2028
1,881
20
237
69
8
334
2,548
2029
1,883
20
237
83
15
374
2,612
2030
1,888
21
237
100
25
411
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
$12
$3,147
$0
$0
$2,799
$5,957
$15
$3,697
$131
$0
$3,660
$7,503
$18
$4,440
$604
$0
$4,332
$9,393
$21
$5,277
$1,138
$0
$5,246
$11,681
$23
$6,273
$458
$0
$7,510
$14,263
$24
$7,405
$1,078
$0
$8,687
$17,195
$26
$8,648
$1,915
$0
$9,891
$20,480
$27
$9,859
$3,298
$0
$11,057
$24,241
$29
$10,603
$4,832
$0
$13,360
$28,824
$30
$11,055
$3,499
$0
$19,250
$33,834
$32
$11,376
$5,261
$0
$23,125
$39,794
$33
$11,707
$7,441
$50
$27,249
$46,479
$35
$12,047
$9,356
$1,031
$31,623
$54,093
$37
$12,397
$11,600
$2,107
$36,247
$62,388
$39
$12,757
$14,418
$3,597
$41,035
$71,847
DEMAND/FIXED COST ($000)
SLP (Unit 4 Upgrade/FO&M)
SLP (Unit 1-3 FO&M)
New CT
Total Fixed Costs
$4,903
$3,547
$3,776
$12,226
$4,974
$3,636
$3,795
$12,404
$5,045
$3,727
$3,815
$12,587
$5,119
$3,820
$3,835
$12,774
$5,195
$3,915
$8,106
$17,216
$5,272
$4,013
$8,149
$17,434
$5,351
$4,114
$8,192
$17,657
$5,433
$4,216
$8,237
$17,886
$5,516
$4,322
$8,282
$18,120
$5,602
$4,430
$13,138
$23,170
$5,689
$4,541
$13,210
$23,440
$5,779
$4,654
$13,284
$23,718
$5,871
$4,771
$13,360
$24,002
$5,965
$4,890
$13,438
$24,293
$6,062
$5,012
$13,517
$24,591
TOTAL COST
$18,183
$19,907
$21,980
$24,455
$31,479
$34,628
$38,137
$42,127
$46,945
$57,004
$63,234
$70,197
$78,094
$86,681
$96,438
$1.77
$75.76
$135.00
$1,883.25
$94.60
$1.81
$77.64
$139.59
$1,029.43
$97.00
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
$351,098
$1.32
$92.43
$1.35
$87.20
$93.36
$1.38
$81.74
$96.53
$1.42
$77.56
$99.82
$1.45
$74.05
$103.21
$1.49
$71.36
$106.72
$1.53
$69.44
$110.38
$1.56
$68.46
$114.18
$1.60
$69.05
$118.10
$1.64
$70.42
$122.08
$1.68
$72.15
$126.27
$81.57
$81.93
$82.18
$81.90
$84.81
$85.75
$86.82
$87.03
$86.72
$89.89
$90.84
$1.73
$73.93
$130.57
$35,080.90
$92.45
$1.86
$79.57
$144.34
$686.59
$99.76
Financial Analysis
None216-LMS100
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
Total Energy
2017
1,721
9
0
41
7
0
73
1,851
1,740
11
0
46
11
0
88
1,897
2018
1,760
13
0
51
19
0
105
1,948
2019
1,777
15
0
56
27
0
126
2,001
2020
1,796
16
0
61
11
0
175
2,059
2021
1,805
16
0
67
20
0
202
2,110
2022
1,817
17
0
73
30
0
230
2,167
2023
1,829
17
0
74
42
0
262
2,226
2024
1,844
18
0
74
57
0
297
2,291
2025
1,850
18
0
74
37
0
368
2,348
2026
1,859
19
0
74
53
0
406
2,411
2027
1,868
19
0
74
68
2
445
2,476
2028
1,881
20
0
74
79
8
486
2,548
2029
1,883
20
0
74
90
15
528
2,612
2030
1,888
21
0
74
109
27
563
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
$12
$0
$3,161
$602
$0
$4,377
$8,151
$15
$0
$3,633
$1,061
$0
$5,369
$10,078
$18
$0
$4,152
$1,833
$0
$6,593
$12,596
$21
$0
$4,727
$2,701
$0
$8,173
$15,622
$23
$0
$5,362
$1,184
$0
$11,804
$18,373
$24
$0
$6,056
$2,163
$0
$14,034
$22,278
$26
$0
$6,815
$3,283
$0
$16,525
$26,649
$27
$0
$7,175
$4,841
$0
$19,662
$31,705
$29
$0
$7,419
$6,762
$0
$23,208
$37,419
$30
$0
$7,672
$4,484
$0
$30,000
$42,187
$32
$0
$7,934
$6,661
$0
$34,376
$49,002
$33
$0
$8,204
$8,855
$248
$39,158
$56,498
$35
$0
$8,484
$10,643
$1,146
$44,474
$64,781
$37
$0
$8,773
$12,617
$2,135
$50,178
$73,740
$39
$0
$9,072
$15,728
$3,848
$55,391
$84,077
DEMAND/FIXED COST ($000)
LMS100
New CT
Total Fixed Costs
$4,790
$3,776
$8,566
$4,790
$3,795
$8,585
$4,790
$3,815
$8,605
$4,790
$3,835
$8,625
$4,790
$8,106
$12,896
$4,790
$8,149
$12,939
$4,790
$8,192
$12,982
$4,790
$8,237
$13,027
$4,790
$8,282
$13,072
$4,790
$13,138
$17,928
$4,790
$13,210
$18,000
$4,790
$13,284
$18,074
$4,790
$13,360
$18,150
$4,790
$13,438
$18,228
$4,790
$13,517
$18,307
$16,717
$18,663
$21,201
$24,247
$31,269
$35,216
$39,631
$44,731
$50,491
$60,115
$67,003
$74,572
$82,931
$91,968
$102,385
TOTAL COST
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
LMS100
Existing CT
New CT
On-Peak Market Energy
$362,430
$1.32
$1.35
$1.38
$1.42
$1.45
$1.49
$1.53
$1.56
$1.60
$1.64
$1.68
$1.73
$1.77
$1.81
$1.86
$191.96
$90.54
$182.95
$93.58
$175.70
$96.67
$169.84
$99.91
$165.15
$103.50
$161.53
$106.89
$158.81
$110.46
$160.82
$114.19
$164.11
$118.06
$167.50
$122.13
$171.02
$126.26
$59.68
$60.92
$62.70
$64.65
$67.48
$69.59
$71.82
$74.90
$78.21
$81.48
$84.75
$174.65
$130.54
$7,143.26
$88.09
$178.41
$134.95
$1,712.76
$91.50
$182.30
$139.52
$1,020.41
$94.98
$186.32
$144.29
$652.30
$98.45
Financial Analysis
None216-SC
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
Total Energy
ENERGY/VARIABLE COST ($000)
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
2017
1,721
9
0
0
0
121
1,851
1,740
11
0
0
0
146
1,897
2018
1,760
13
0
2
0
173
1,948
2019
1,777
15
0
7
0
203
2,001
2020
1,796
16
0
0
0
248
2,059
2021
1,805
16
0
5
0
284
2,110
2022
1,817
17
0
11
0
322
2,167
2023
1,829
17
0
19
0
360
2,226
2024
1,844
18
0
31
0
397
2,291
2025
1,850
18
0
19
0
460
2,348
2026
1,859
19
0
32
0
501
2,411
2027
1,868
19
0
46
0
543
2,476
2028
1,881
20
0
60
3
585
2,548
2029
1,883
20
0
73
10
625
2,612
2030
1,888
21
0
88
18
666
2,682
$12
$0
$0
$0
$8,500
$8,511
$15
$0
$0
$0
$10,400
$10,415
$18
$0
$149
$0
$12,628
$12,796
$21
$0
$667
$0
$14,989
$15,677
$23
$0
$0
$0
$18,950
$18,972
$24
$0
$576
$0
$22,124
$22,723
$26
$0
$1,249
$0
$25,634
$26,909
$27
$0
$2,221
$0
$29,346
$31,595
$29
$0
$3,718
$0
$33,117
$36,864
$30
$0
$2,347
$0
$39,951
$42,329
$32
$0
$4,071
$0
$44,542
$48,644
$33
$0
$5,964
$0
$49,571
$55,568
$35
$0
$8,106
$395
$54,888
$63,425
$37
$0
$10,163
$1,449
$60,403
$72,053
$39
$0
$12,736
$2,604
$66,332
$81,711
DEMAND/FIXED COST ($000)
New CC
New CT
Total Fixed Costs
$0
$11,327
$11,327
$0
$11,385
$11,385
$0
$11,444
$11,444
$0
$11,504
$11,504
$0
$15,817
$15,817
$0
$15,902
$15,902
$0
$15,989
$15,989
$0
$16,078
$16,078
$0
$16,170
$16,170
$0
$21,073
$21,073
$0
$21,193
$21,193
$0
$21,316
$21,316
$0
$21,442
$21,442
$0
$21,571
$21,571
$0
$21,704
$21,704
TOTAL COST
$19,838
$21,799
$24,239
$27,181
$34,790
$38,625
$42,898
$47,673
$53,034
$63,401
$69,837
$76,884
$84,867
$93,624
$103,414
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
Existing CT
New CT
On-Peak Market Energy
$387,146
$1.32
$70.01
$1.35
$71.47
$1.38
$1.42
$96.53
$99.82
$72.80
$73.91
$1.45
$76.46
$1.49
$1.53
$1.56
$1.60
$1.64
$1.68
$1.73
$1.77
$1.81
$1.86
$106.72
$110.35
$114.14
$118.08
$122.03
$126.25
$130.58
$77.99
$79.72
$81.56
$83.43
$86.83
$88.99
$91.30
$135.02
$7,454.01
$93.86
$139.60
$2,216.09
$96.61
$144.35
$1,346.86
$99.54
Financial Analysis
All216-100CC
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
Total Energy
2017
1,721
9
87
0
0
0
34
1,851
1,740
11
99
0
1
0
45
1,897
2018
1,760
13
116
0
6
0
53
1,948
2019
1,777
15
134
0
11
0
64
2,001
2020
1,796
16
155
70
0
0
23
2,059
2021
1,805
16
178
80
0
0
32
2,110
2022
1,817
17
202
85
1
0
46
2,167
2023
1,829
17
223
90
5
0
60
2,226
2024
1,844
18
233
96
10
0
89
2,291
2025
1,850
18
237
102
21
0
120
2,348
2026
1,859
19
237
110
38
0
149
2,411
2027
1,868
19
237
117
56
0
179
2,476
2028
1,881
20
237
126
77
0
208
2,548
2029
1,883
20
237
135
105
3
229
2,612
2030
1,888
21
237
144
144
10
237
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
Total Variable Costs
$12
$3,147
$0
$0
$0
$2,799
$5,957
$15
$3,697
$0
$131
$0
$3,660
$7,503
$18
$4,440
$0
$604
$0
$4,332
$9,393
$21
$5,277
$0
$1,138
$0
$5,246
$11,681
$23
$6,273
$5,045
$0
$0
$1,353
$12,694
$24
$7,405
$5,964
$0
$0
$1,937
$15,331
$26
$8,648
$6,562
$97
$0
$3,138
$18,471
$27
$9,859
$7,213
$625
$0
$4,467
$22,192
$29
$10,603
$7,967
$1,217
$0
$6,962
$26,778
$30
$11,055
$8,807
$2,550
$0
$9,904
$32,346
$32
$11,376
$9,838
$4,782
$0
$12,634
$38,662
$33
$11,707
$10,971
$7,248
$0
$15,658
$45,618
$35
$12,047
$12,213
$10,386
$0
$18,716
$53,397
$37
$12,397
$13,582
$14,707
$376
$21,172
$62,272
$39
$12,757
$15,096
$20,938
$1,436
$22,711
$72,977
DEMAND/FIXED COST ($000)
SLP (Unit 4 Upgrade/FO&M)
SLP (Unit 1-3 FO&M)
New CC
New CT
Total Fixed Costs
$4,903
$3,547
$0
$3,776
$12,226
$4,974
$3,636
$0
$3,795
$12,404
$5,045
$3,727
$0
$3,815
$12,587
$5,119
$3,820
$0
$3,835
$12,774
$5,195
$3,915
$14,836
$3,856
$27,801
$5,272
$4,013
$14,901
$3,877
$28,063
$5,351
$4,114
$14,968
$3,898
$28,331
$5,433
$4,216
$15,036
$3,921
$28,606
$5,516
$4,322
$15,106
$3,944
$28,888
$5,602
$4,430
$15,178
$3,967
$29,176
$5,689
$4,541
$15,251
$3,991
$29,472
$5,779
$4,654
$15,327
$4,016
$29,776
$5,871
$4,771
$15,404
$4,041
$30,087
$5,965
$4,890
$15,483
$4,067
$30,405
$6,062
$5,012
$15,564
$4,093
$30,732
TOTAL COST
$18,183
$19,907
$21,980
$24,455
$40,495
$43,394
$46,802
$50,798
$55,666
$61,522
$68,135
$75,393
$83,484
$92,677
$103,709
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
$389,434
$1.32
$92.43
$81.57
$1.35
$87.20
$1.38
$81.74
$1.42
$77.56
$93.36
$96.53
$99.82
$81.93
$82.18
$81.90
$1.45
$74.05
$285.28
$1.49
$71.36
$261.90
$1.53
$69.44
$253.98
$109.96
$1.56
$68.46
$246.93
$113.70
$1.60
$69.05
$240.55
$117.57
$1.64
$70.42
$235.23
$121.71
$1.68
$72.15
$229.09
$125.95
$1.73
$73.93
$223.84
$130.28
$1.77
$75.76
$219.42
$134.77
$58.08
$61.04
$68.78
$74.05
$78.48
$82.61
$84.94
$87.48
$89.85
$1.81
$77.64
$215.69
$139.41
$1,642.15
$92.48
$1.86
$79.57
$212.58
$144.91
$553.75
$95.65
Financial Analysis
45216-100CC
2016
RESOURCE DISPATCH (GWh)
CROD
Hydro
SLP
New CC
CTs
On-Peak Market Energy
Total Energy
2017
1,721
9
87
32
0
2
1,851
1,740
11
99
41
0
5
1,897
2018
1,760
13
116
50
0
9
1,948
2019
1,777
15
134
60
0
15
2,001
2020
1,796
16
155
70
0
23
2,059
2021
1,805
16
178
80
0
32
2,110
2022
1,817
17
202
85
1
46
2,167
2023
1,829
17
223
90
5
60
2,226
2024
1,844
18
233
96
10
89
2,291
2025
1,850
18
237
102
3
137
2,348
2026
1,859
19
237
110
9
178
2,411
2027
1,868
19
237
117
19
215
2,476
2028
1,881
20
237
126
38
248
2,548
2029
1,883
20
237
135
56
281
2,612
2030
1,888
21
237
144
81
311
2,682
ENERGY/VARIABLE COST ($000)
Hydro
SLP
New CC
CTs
On-Peak Market Energy
Total Variable Costs
$12
$3,147
$2,054
$0
$93
$5,305
$15
$3,697
$2,686
$0
$259
$6,657
$18
$4,440
$3,390
$0
$473
$8,320
$21
$5,277
$4,174
$40
$862
$10,373
$23
$6,273
$5,045
$0
$1,353
$12,694
$24
$7,405
$5,964
$0
$1,937
$15,331
$26
$8,648
$6,562
$97
$3,138
$18,471
$27
$9,859
$7,213
$625
$4,467
$22,192
$29
$10,603
$7,967
$1,217
$6,962
$26,778
$30
$11,055
$8,807
$418
$11,166
$31,476
$32
$11,376
$9,838
$1,098
$15,147
$37,490
$33
$11,707
$10,971
$2,503
$19,027
$44,242
$35
$12,047
$12,213
$5,054
$22,560
$51,909
$37
$12,397
$13,582
$7,868
$26,330
$60,213
$39
$12,757
$15,096
$11,620
$30,007
$69,519
DEMAND/FIXED COST ($000)
SLP (Unit 4 Upgrade/FO&M)
New CC
New CT
Total Fixed Costs
$4,903
$14,591
$0
$19,495
$4,974
$14,650
$0
$19,624
$5,045
$14,710
$0
$19,756
$5,119
$14,772
$0
$19,892
$5,195
$14,836
$4,251
$24,281
$5,272
$14,901
$4,272
$24,445
$5,351
$14,968
$4,294
$24,613
$5,433
$15,036
$4,316
$24,785
$5,516
$15,106
$4,339
$24,961
$5,602
$15,178
$9,171
$29,951
$5,689
$15,251
$9,219
$30,160
$5,779
$15,327
$9,269
$30,374
$5,871
$15,404
$9,319
$30,594
$5,965
$15,483
$9,371
$30,819
$6,062
$15,564
$9,424
$31,050
TOTAL COST
$24,800
$26,280
$28,076
$30,264
$36,975
$39,775
$43,083
$46,976
$51,739
$61,426
$67,650
$74,616
$82,503
$91,033
$100,569
15-Year NPV (2015 $000):
Average Resource Cost ($/MWh)
Hydro
SLP
New CC
Existing CT
New CT
On-Peak Market Energy
$396,788
$1.32
$92.43
$513.13
$1.35
$87.20
$422.60
$1.38
$81.74
$361.57
$1.42
$77.56
$317.83
$99.46
$1.45
$74.05
$285.28
$1.49
$71.36
$261.90
$1.53
$69.44
$253.98
$109.96
$1.56
$68.46
$246.93
$113.70
$1.60
$69.05
$240.55
$117.57
$1.64
$70.42
$235.23
$121.58
$1.68
$72.15
$229.09
$125.72
$1.73
$73.93
$223.84
$130.14
$1.77
$75.76
$219.42
$134.69
$1.81
$77.64
$215.69
$139.32
$1.86
$79.57
$212.58
$144.13
$49.47
$51.18
$53.14
$55.83
$58.08
$61.04
$68.78
$74.05
$78.48
$81.26
$85.10
$88.33
$91.02
$93.81
$96.39
Appendix IV • End Use Survey & Summary of Results
• End Use Survey Question Forms for Residential,
Commercial and Industrial Customers
• “Next Level” Triad Report
• Task Force Recommendations
• Residential & Commercial End Use Information
• Statistical Relationship Photovoltaic Generation & Electric
Utility Demand in Minnesota (1996 – 2002)
End Use Survey & Summary of Results
MMP
Morgan Marketing Partners
Strategic Marketing Consulting
October 18, 2004
Rick Morgan & Rick Tate
Morgan Marketing Partners
Residential & Commercial/Industrial Customers
Presentation of Key Findings
END USE CUSTOMER
SURVEYS
1
MMP
„
„
„
„
„
2
Provide you with an overview of the
study process
Share Key Findings
Provide Recommendations
Discuss some uses of the
information
Questions
Today’s Objective
MMP
interest.
ƒLarge Customers get some indication of services of
3
information about current usage and conservation practices.
ƒInventory water using appliances and gather pertinent
characteristics such as age, number of rooms, number of
residents, and current energy usage and practices.
ƒGather information about homes and building
pertinent information about type, age, and usage.
ƒInventory major appliances (gas and electric) and gather
Planning - Not Customer Satisfaction
ƒPrimarily for End-Use Facility Forecast and DSM
Objectives
MMP
9Type/age of HVAC equipment
9Number and sizes of refrigerators and freezers
9Laundry appliances and usage
9Food preparation appliances and usage
9Compact fluorescent lighting
9Energy management practices currently using
9Water usage and conservation measures
with AOR. The primary issues covered in the surveys
were:
ƒMMP designed the survey instrument in conjunction
plan to control for costs but produce reliable results
4
ƒMMP worked with AOR Utilities to develop a sampling
Methodology
MMP
„
„
„
„
„
„
„
„
3 Heat pump
1
1
1
a. Day
b. Evening
c. Night
Never
2
2
2
Rarely
(20% time)
3
3
3
4
4
4
Sometimes Often
(40% time) (70% time)
5
5
5
Always
5
23. Please indicate how often the central air conditioner is used during the summer.
(Choose one for each time period)
22. Was the central air conditioning unit purchased or replaced within the last seven
years?
„ 1 Yes
2 No
3 Don’t know
21. Do you pay for your central air conditioning?
„ 1 Yes
2 No, it is part of the lease
20. What type of central air conditioner does this business have?
„ 0 None (SKIP TO Q.24)
1 Central 2 Central (roof top)
Central Air Conditioner
Sample Question
MMP
Sample
Mail Out
1,500
1,500
1,497
Population
10,565
9,436
39,414
Utility
Austin
Owatonna
Rochester
520
517
576
Responses
34.7%
34.5%
38.4%
Response
Rate
ƒ Response rates and statistical confidence
95%
95%
95%
Confidence
Level
6
+/-4.27%
+/-4.19%
+/-3.97%
Sampling
Error
cover letter and postage-paid return envelope. Completed
surveys were batched to MMP on a weekly basis for data
entry and processing.
ƒAOR Utilities printed and mailed the surveys along with a
Methodology - Continued
MMP
Large C&I
Commercial
48
2145
62
Large C&I
Rochester
941
Commercial
48
2145
62
941
16
16
Large C&I
Owatonna
626
Sample
Mail Out
626
Population
Commercial
Austin
Utility
7
381
14
202
4
152
Responses
14.6%
17.8%
22.6%
21.5%
25.0%
24.3%
Response Rate
NA
95%
NA
95%
NA
95%
Confidence Level
Methodology - Continued
7
NA
+/-4.55%
NA
+/-6.11%
NA
+/-6.92%
7
Sampling Error
MMP
0
10
20
30
50
40
60
70
90
80
100
0
10
20
30
40
50
60
70
98.3
One Story SingleFamily Home
40.8
58.0
51.3
45.5
Own
98.4
Owatonna
Austin
96.3
Owatonna
OWN OR RENT
Austin
Mobile Home
0 1.2 0.8
3.1 4.7
9.7
Rochester
1.7
Rochester
Re nt
1.6
Apartment/Condo
Number of Stories
Two-Story SingleFamily Home
33.0
41.9
BUILDING WHERE YOU LIVE
3.7
Other
3.7 3.1 3.3
8
ƒ Owner-occupied.
building.
ƒ One or two-story
Key Findings - Home and Lifestyle
Percent of Respondents
Percent of Respondents
MMP
0
10
20
30
40
50
60
8.7
15.1
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
29.2
One
20.5 19.6
1,000 or less
21.6
Owatonna
Two
52.1 52.4
Austin
54.6
Owatonna
Three
14.6
22.6 21.2
8.6 8.1
3,001 to 5,000
4.1
Rochester
1,501-3,000
36.9
Rochester
Four
3.2 3.9 4.1
NUMBER OF BATHROOMS
Austin
1,001 to 1,500
22.9
28.2
36.7
53.953.1
0.6 0.7 0.9
More than Four
0.9 0.6 0.6
Ove r 5,000
APPROXIMATE SQUARE FOOTAGE OF LIVING
SPACE
ƒ Majority have
two bathrooms.
9
ƒ Most homes are
between 1,000 and
3,000 square feet.
Key Findings - Home and Lifestyle
Percent of Respondents
Percent of Respondents
MMP
New (<1)
0.2 0.4
2.9
Austin
1 to 5
1.9
11.2
7.8
Owatonna
22.6
20.5
Rochester
16 to 30
8.1
Years
1.4
6 to 15
5.5
18.0
ƒ In general, homes are older.
0
10
20
30
40
50
60
31 to 50
39.1
34.9
31.8
APPROXIMATE AGE OF YOUR HOME
Over 50
21.523
49.4
Key Findings – Home and Lifestyle
Percent of Respondents
10
MMP
36.7
Owatonna
Water Heater
Cycling a.m. or
p.m.
12.5 9.7 10.9
Austin
AC Cycling during
hottest days
46.7
55.1
Rochester
Other
1.6 1.2
1.0
50.7
43.5
63.3
No Participation
ƒ A large percentage do not participate in
conservation load/management programs.
100
90
80
70
60
50
40
30
20
10
0
PARTICIPATE IN THE FOLLOWING ENERGY
CONSERVATION/LOAD MANAGEMENT PROGRAMS
Key Findings - Home and Lifestyle
Percent of Respondents
11
MMP
24.5
Yes
29.3
Austin
38.9
No
58.0
Rochester
68.9
Owatonna
73.4
1.8
3.1
Don't know
2.1
ƒ Between one fourth and 39% have replaced system
in past 5 years.
0
10
20
30
40
50
60
70
80
REPLACED MAIN HEATING SYSTEM IN LAST 5
YEARS
Key Findings - Heating
Percent of Respondents
12
MMP
0.0
10.0
20.0
30.0
40.0
50.0
60.0
20
10
0
50
40
30
80
70
60
100
90
54.7 55
Fireplace
42.0
Austin
Yes
28.6
Owatonna
30.7
Rochester
Austin
Owatonna
Woodstove/Fireplace
Insert
8.4
14.2 15.6
11.5
15.6
No
71.4
Rochester
Natural Gas (All types)
31.5
TYPE OF ADDITIONAL HEATING*
24.8
75.2
HAVE ADDITIONAL HEATING
30.5
25.0
Electric (All types)
28.0
69.3
Key Findings - Heating
Percent of Respondents
Percent of Respondents
13
ƒ A fireplace is the
most common type
and typically heats
one room.
ƒ 25% to 30% have
some type of
supplemental
heating.
MMP
Percent of Respondents
Percent of Respondents
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
10.0
0.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
15.0
Austin
Yes
99.3
Owatonna
100.0
0.7
None
8.5
8.5
Austin
Central
91.5
Owatonna
84.4
Rochester
Rochester
91.5
0.0
0.6
Heat Pum p
0.0
No, Part of My Rent
0.7
TYPE OF CENTRAL AIR CONDITIONING
99.3
PAY FOR CENTRAL AIR CONDITIONING
0.0
14
ƒ Have a central AC
system.
ƒ Pay for air
conditioning.
Key Findings - Air Conditioning
MMP
31.9
Yes
27.8
Austin
43.2
Owatonna
65.9
53.3
Rochester
No
70.2
2.0
3.5
Don't know/No answer
2.2
ƒ A higher percentage of Rochester (43%)
respondents have replaced their system in the last
five years.
0
10
20
30
40
50
60
70
80
REPLACED CENTRAL AIR CONDITIONING IN LAST 5
YEARS
Key Findings - Air Conditioning
Percent of Respondents
15
MMP
24.1%
35.6%
24.5%
2.1%
24.2%
34.6%
25.8%
2.5%
Often (70% of the
time)
Sometimes (40% of
the time)
Rarely (10% of the
time)
Never
8.6%
26.0%
31.5%
20.5%
13.%
Night
0.9%
23.3%
32.9%
28.5%
14.4%
Day
1.9%
20.0%
34.0%
30.0%
14.0%
Evening
Owatonna
4.9%
24.5%
31.8%
24.8%
14.1%
Night
2.9%
32.2%
28.6%
24.5%
11.7%
Day
2.8%
28.5%
32.9%
24.7%
11.1%
Evening
Rochester
ƒ Frequency of Summer use is moderate, mostly in the
evenings.
*Percentage of respondents that have central air conditioning
13.7%
Evening
12.9%
Day
Austin
Always
Frequency
Frequency of Central Air Conditioning Use During the Summer*
Key Findings - Air Conditioning
16
5.9%
35.1%
29.6%
19.2%
10.2%
Night
MMP
85.3%
14.7%
7.9%
24.8%
32.1%
35.1%
89.6%
10.4%
30.2%
54.2%
12.6%
3.0%
Fan Set to
Auto
Fan Set to On
65 to 68
degrees
69 to 72
degrees
73 to 75
degrees
76 degrees or
higher
10.2%
18.7%
41.1%
30.0%
11.7%
88.3%
Spring
5.6
%
16.4
%
46.8
%
31.1
%
12.2
%
87.8
%
Fall
Summer
82.5%
17.5%
4.5%
20.1%
35.5%
39.8%
90.4%
9.6%
34.3%
51.8%
10.0%
3.8%
10.2
%
12.1
%
45.0
%
32.7
%
10.5
%
89.5
%
Fall
3.0%
14.0%
49.3%
33.8%
16.0%
84.0%
Winter
37.3%
31.9%
23.2%
7.6%
21.8%
78.2%
Summer
17
14.3%
18.9%
42.3%
24.5%
17.8%
82.3%
Spring
Rochester
ƒ Most prevalent Winter setting is 69 to 72 degrees
and Summer setting is 76 degrees or higher.
16.1%
14.4%
44.1%
25.4%
10.5%
89.5%
Spring
Owatonna
Winter
*Percentage of respondents that have central heating or air conditioning
Summer
Austin
Thermostat Setting and Temperature For Operating Central Heating or Air Conditioning*
generally set to “auto” in all seasons.
Winter
ƒ Fan
Key Findings - Thermostat Setting
8.3%
16.6%
46.3%
28.8%
16.8%
83.2%
Fall
MMP
Yes
Austin
36.8 35.6 37.1
Owatonna
No
Rochester
60.6 62.9 58.8
1.6
4.1
Don't know/No answer
2.7
ƒ A little over one-third have replaced unit in last
five years.
0
10
20
30
40
50
60
70
80
REPLACED WATER HEATER IN LAST 5 YEARS
Key Findings - Water Heating
Percent of Respondents
18
MMP
45.5
No
Austin
53.1 50.3
34.6 36.9
Owatonna
Rochester
Yes, All Showers
41.3
Yes, Some Showers
13.2 12.3 12.8
ƒ Only about half of households use low-flow
showerheads.
0
10
20
30
40
50
60
70
80
90
USE LOW-FLOW RESTRICTORS OR ENERGYSAVING (LOW-FLOW) SHOWERHEADS
Key Findings - Water Heating
Percent of Respondents
19
MMP
75.2
Austin
79.2
Electricity
82.0
24.6
20.8
Owatonna
Rochester
Natural Gas
18.0
0.2
0.0
Propane/Other Fuel
0.0
ƒ Dryers are overwhelmingly electric.
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
HEATING FUEL FOR CLOTHES DRYER AT THIS
RESIDENCE*
Key Findings - Laundry
Percent of Respondents
20
MMP
46.7
Yes
42.4
Austin
32.9
Owatonna
Rochester
53.3
No
57.6
67.1
ƒ Line drying is more prevalent with Austin
customers.
0
10
20
30
40
50
60
70
80
LINE-DRY CLOTHING
Key Findings - Laundry
Percent of Respondents
21
MMP
None
0.5 0.0 0.0
Austin
66.7
Owatonna
One
64.2 63.1
Rochester
Two
33.2 35.2
30.6
Three or More
2.1 1.8 2.7
ƒ About two-thirds of households have only one
operating refrigerator.
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
NUMBER OF REFRIGERATORS PLUGGED IN AT
THIS RESIDENCE
Key Findings - Refrigerators
Percent of Respondents
22
MMP
25.8%
26.3%
3.0%
9.5%
55.2%
29.5%
2.8%
Very Small (<13cu. ft)
Small (13-16 cu. ft.)
Medium (17-20 cu.ft.)
Large (21-23 cu. Ft.)
Very Large (over 23 cu. Ft)
4.7%
2.0%
Partial Automatic
18.2%
63.6%
18.2%
0.0%
9.1%
27.3%
9.1%
54.5%
0.0%
100.0%
No. 3
1.6%
3.4%
95.0%
4.5%
32.0%
52.2%
10.0%
1.2%
27.8%
72.2%
No. 1
6.6%
33.9%
59.6%
1.1%
16.2%
40.2%
25.1%
17.3%
8.3%
91.7%
No. 2
Owatonna
11.1%
55.5%
33.3%
11.1%
22.2%
11.1%
22.2%
33.3%
0.0%
100.0%
No. 3
ƒ The largest percentage of refrigerators and topbottom models, medium-sized and frost free.
40.6%
5.8%
54.7%
0.5%
13.2%
Manual
92.3%
15.3%
22.3%
Side-by-Side
34.2%
84.6%
77.7%
Top-Bottom
Defrost: Automatic (Frost Free)
Size:
Style:
No. 2
Austin
No. 1
Characteristic
Overview of Refrigerators
Key Findings - Refrigerators
10.2%
24.2%
24.8%
25.0%
2.2%
7.2%
37.1%
6.6%
1.2%
56.3%
0.6%
14.5%
3.8%
95.0%
5.0%
32.2%
35.8%
89.8%
75.0%
53.4%
No. 2
No. 1
23
Rochester
15.4%
61.5%
23.1%
0.0%
7.7%
23.1%
15.4%
53.8%
18.2%
81.8%
No. 3
MMP
90.9
91.6
Refrigerator 1
90.3
Austin
13.6
Owatonna
Rochester
17.6
Refrigerator 2
18.9
2.0
3.2
Refrigerator 3
1.8
ƒMore than 90% indicated that Refrigerator 1 had
been replaced in the last 5 years.
0
10
20
30
40
50
60
70
80
90
100
REFRIGERATORS PURCHASED IN LAST 5 YEARS
Key Findings - Refrigerators
Percent of Respondents
24
MMP
39.8
None
29.8
Austin
45.5
Owatonna
57.7
52.7
Rochester
One
65.1
5.1
1.8
Two or M ore
2.4
ƒ Over half of households have one or more standalone freezers.
10.0
0.0
50.0
40.0
30.0
20.0
100.0
90.0
80.0
70.0
60.0
NUMBER OF STAND-ALONE FREEZERS PLUGGED
IN AT THIS RESIDENCE
Key Findings - Stand-Alone Freezers
Percent of Respondents
25
MMP
31.1%
27.3%
33.0%
37.9%
12.6%
0.6%
Small (11-15 cu. ft.)
Medium (16-20 cu.ft.)
Large (21-25 cu. Ft.)
Very Large (over 25 cu. Ft)
72.1%
75.0%
25.0%
0.0%
45.5%
71.6%
28.4%
1.5%
15.6%
No. 2
87.5%
12.5%
0.0%
4.3%
39.1%
34.8%
21.7%
83.3%
16.7%
Owatonna
69.3%
30.7%
1.1%
14.2%
39.3%
31.8%
13.5%
52.8%
47.2%
No. 1
ƒ Freezer 1 more likely to be upright, but freezer 2 is
more likely to be larger.
Manual
28.9%
13.5%
9.1%
15.9%
Very Small (<10cu. Ft)
38.3%
57.6%
75.0%
55.5%
Chest
18.2%
42.3%
25.0%
44.5%
Upright
Defrost: Automatic (Frost Free)
Size:
Style:
No. 1
No. 2
Austin
No. 1
Characteristic
Overview of Stand-Alone Freezers*
Key Findings - Stand-Alone Freezers
No. 2
26
50.0%
50.0%
0.0%
0.0%
44.4%
33.3%
22.2%
62.5%
37.5%
Rochester
MMP
97.6
97.4
Austin
Freezer 1
95.7
Owatonna
Rochester
3.6
Freezer 2
7.2
2.6
ƒMore than 90% indicated that Freezer 1 had been
replaced in the last 5 years.
0
10
20
30
40
50
60
70
80
90
100
STAND-ALONE FREEZERS PURCHASED IN LAST 5
YEARS
Key Findings - Stand-Alone Freezers
Percent of Respondents
27
MMP
Electric Only
77.7
77.9
70.8
Austin
Propane Only
0.0 0.0 0.0
Rochester
Combination:
Electric and
Gas
4 4.3 3.9
Owatonna
Natural Gas
Only
25.0
18.1
17.8
ƒElectric ranges are prevalent.
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
TYPE OF RANGE/OVEN USED
Key Findings - Food Preparation
Percent of Respondents
Other
0.2 0.0 0.4
28
MMP
0.0
10.0
20.0
30.0
40.0
50.0
0.0
10.0
20.0
30.0
40.0
50.0
30.3
28.2
32.2
34.6
Ow atonna
41.5 41.1
Rochester
4 to 6 tim es
19.2 19.0 20.3
7 or m ore
tim es
9.6 8.6 10.5
20.9
Rochester
Air Dry
20.1
24.3
Other
3.4
0.6 2.0
*Respondents that have dishwashers
Ow atonna
Energy Saver
43.8
Austin
Heated Drying
35.6
Austin
3 or few er
tim es
32.6
42.1 41
DISHWASHER CYCLE MOST OFTEN USED*
Don't Have
38.7
FREQUENCY OF USING DISHWASHER EACH WEEK
29
ƒ Energy saving
cycle used slightly
more than heated
drying.
ƒ At least one-fourth
don’t have a
dishwasher.
Key Findings - Food Preparation
Percent of Respondents
Percent of Respondents
MMP
0.0
10.0
20.0
30.0
40.0
50.0
60.0
0
10
20
30
40
50
38.6
Austin
29.2 28.7
Ow atonna
1 to 3
30.8
16.1
18.8
Rochester
4 to 6
21.2
7 or m ore
13.8 14.5 13.9
All
4.5 5.5 4.9
Austin
9.0 9.8
Ow atonna
Most
12.9
Rochester
Som e
33.5 34.0 34.0
51.6 51.3
1 or 2 Lights
49.0
NUMBER OF LIGHTS TURNED ON DURING THE EVENING
UNTIL BEDTIME
None
34.1
40.3
NUMBER OF ENERGY SAVING OR COMPACT
FLUORESCENT BULBS USED FOR INTERIOR LIGHTING
Key Findings - Lighting
Percent of Respondents
Percent of Respondents
30
ƒ The largest
percentage indicated
that 1 or 2 lights are
turned on in the
evening.
ƒ The majority of
households have at
least one compact
fluorescent bulb.
MMP
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
0.0
10.0
20.0
30.0
40.0
50.0
60.0
18.2
3
Ow atonna
2
Austin
16.6
25.0
4
4.2 4.1 4.3
Rochester
20.5
None
59.6
52.853.4
Austin
1
25.3
17.6 15.7
Ow atonna
2
17.0 16.617.9
3
10.1
5.6
4
1.2 2.1 0.8
Rochester
3.6
5 or m ore
0.0 0.2 0.1
5 or m ore
0.5 0.4 0.8
TOTAL NUMBER OF LOW-FLOW TOILETS INSIDE YOUR
HOME
1
14.5
22.7
55.956.0 56.2
TOTAL NUMBER OF TOILETS INSIDE YOUR HOME
31
ƒ A majority of
households have no
low-flow toilets.
ƒ Two toilets are
common.
Key Findings - Water Usage/Conservation
Percent of Respondents
Percent of Respondents
MMP
32
with more than half using these bulbs. The utilities could expand
this program to continue to increase application of this efficient
technology.
ƒ Lighting application of CFL technology shows good initial results
The percentage of refrigerators and freezers purchased in the
last five years seems unusually high. Even if the data is incorrect,
the opportunity for DSM programs for this technology are limited.
ƒ
conservation measures had been taken. Opportunities exist for the
utilities to gain more participation.
ƒ About half of residential customers indicated that some water
energy/load conservation management and the utilities will need to
do more to promote and educate customers on the value.
ƒOverall, residential customers do not clearly see the benefits of
Recommendations - Residential
MMP
33
Summary of Findings:
Small Commercial & Industrial
Customers
MMP
0
10
20
30
40
50
60
70
80
67.5
One Story
58.6
63.7
27.4
22.5
8.5 6.9
Three Stories
5.9
Austin
Owatonna
Rochester
Number of Stories
Two Stories
33.6
Four + Stories
2.0 0.5 3.2
BUILDING WHERE BUSINESS IS LOCATED
Building and Firmographics
Percent of Respondents
34
The majority of
businesses are located
in one story buildings.
MMP
0.0
10.0
20.0
30.0
40.0
New (<1)
0.0
1.6 2.7
1 to 5
13.513.8
Owatonna
26.4
23.3
31 to 50
Rochester
16 to 30
19.0
16.1
Years
6 to 15
6.8
Austin
15.1
11.9
9.5
22.9
32.0
AGE OF BUILDING WHERE BUSINESS OPERATES
Over 50
19.1
32.733.7
35
In general, buildings
are old.
Building and Firmographics - continued
Percent of Respondents
MMP
Percent of Respondents
63.6 61.5
<5,000
66.4
28.8
Austin
8.8 7.6 9.1
Rochester
25,001 to 250,000
Owatonna
5,001 to 25,000
24.8 27.7
250,000 or more
0.0 1.1 0.6
However, as would be expected,
size varies by type of business.
0
10
20
30
40
50
60
70
80
SQUARE FOOTAGE OF CONDITIONED SPACE OF
BUSINESS
0
5,000
10,000
15,000
20,000
25,000
30,000
Total
9,370
14,350
13,650
Austin
Restaurant
4,950
4,510
4,460
10,620
10,230
6,880
36
Trade
Services
7,790
Rochester
Prof. Services
4,550
7,590
4,710
Owatonna
Retail
7,290
26,530
Manufacturing
16,230
25,500
14,310
SQUARE FOOTAGE OF CONDITIONED SPACE BY
BUSINESS TYPE
The majority of businesses
occupy a conditioned space of
less than 5,000 square feet.
Building and Firmographics - continued
Mean Square Feet
MMP
0
10
20
30
40
50
60
70
80
90
24.7
Yes
19.9
Austin
30
Owatonna
Rochester
75.3
No
80.1
70.0
ONE OR MORE INDIVIDUALS WHOSE MAIN JOB
RESPONSIBILITY IS ENERGY MANAGMENT
Percentage varies by type of
business
Percent of Respondents
0
10
20
30
40
25
Total
30
20
23
Restaurant
29
30
Ow atonna
12
Austin
20
26
Prof. Serv ices
24
36
Retail
33
19
37
Rochester
Trade Serv ices
13
35
ONE OR MORE INDIVIDUALS WITH ENERGY
MANAGEMENT AS MAIN JOB BY BUSINESS TYPE
31
20
Manufacturing
0
A minority of businesses have
energy management.
Building and Firmographics - continued
Percentage Saying "Yes"
MMP
Percent of Respondents
100
90
80
70
60
50
40
30
20
10
0
55.5
Owatonna
61.0
Austin
No
61.1
36.8
36.8
Rochester
Yes, Reduce Use
41.1
2.2
2.2
Yes, Suspend Certain
Operations
3.4
BUSINESS RESPONDS TO PEAK ALERTS
38
The majority of
respondents indicated that
they did not respond to
peak alerts.
Building and Firmographics - continued
MMP
Percent of Respondents
100
90
80
70
60
50
40
30
20
10
0
18.8
22.3
Austin
AC Cycling during
hottest days
22.4
Owatonna
TOU Rates
5.9 3.9 3.4
Rochester
Water Heater
Cycling a.m. or
p.m.
2.6 3.5 3.4
89.5
No Participation
75.7 78.7
PARTICIPATE IN THE FOLLOWING ENERGY
CONSERVATION/LOAD MANAGEMENT PROGRAMS
39
At least three-fourths do
not participate in any of
the three conservation
load/management
programs.
Building and Firmographics - continued
MMP
Percent of Respondents
47.5
38.8
48.0
47.8
Austin
Owatonna
Rochester
AC Cycling during hottest Water Heater Cycling a.m.
days
or p.m.
37.5
47.0
47.0
TOU Rates
34.2
46.0
0
10
20
30
40
50
60
70
80
54.7
51.4
67.0
65.4
Austin
Owatonna
Rochester
AC Cycling during hottest Water Heater Cycling a.m.
days
or p.m.
56.1
71.2
60.2
54.2
40
TOU Rates
65.4
GAVE AN 'EXTREMELY VALUABLE' OR 'VERY
VALUABLE' RATING*
Only a little more than one-third
of Austin respondents and just
under a half of the Owatonna
and Rochester respondents chose
to rate the energy
conservation/load management
programs.
*Includes participants and non-participants. Too few participants gave a
rating to show them separately.
Of those who rated programs,
water heater cycling was rated
most valuable, followed by timeof-use rates and AC cycling
during the hottest days.
0
10
20
30
40
50
GAVE A RATING FOR THE FOLLOWING ENERGY
CONSERVATION/LOAD MANAGEMENT PROGRAMS
Building and Firmographics - continued
Percent of Respondents
MMP
Percent of Respondents
0
10
20
30
40
50
60
70
80
38.3
Austin
Yes
33.6 33.7
Owatonna
56.6
47.0
Rochester
No
50.5
15.8 14.7
Don't know/No answer
9.8
REPLACED MAIN HEATING SYSTEM IN LAST 7
YEARS
Heating - continued
41
Just over a third replaced
their main heating system
in the last seven years.
MMP
Percent of Respondents
21.7
Austin
Yes
22.7
Owatonna
22.6
Rochester
78.3
No
77.3
77.4
While natural gas fueled
additional heating is prevalent,
electric heating has a larger
percentage compared to main
heating systems (particularly in
Rochester).
0
10
20
30
40
50
60
70
80
90
100
HAVE ADDITIONAL HEATING
Heating - continued
0
10
20
30
40
50
60
28.3
18.6
Natural Gas Furnace
30.3
27.9
Austin
Owatonna
Other Natural Gas
42.4 41.3
Rochester
Electric (All types)
27.3 26.1
46.5
TYPE OF ADDITIONAL HEATINGING*
4.3
7.0
42
Fireplace/Woodstove
9.1
Just over one-fifth of businesses
have some type of additional or
supplemental heating.
*Respondents that have additional heating.
Percent of Respondents
MMP
0
10
20
30
40
28.8
Rarely (20%)
30.4
33.3
19.6
24.0
15.2
9.8
23.1
Austin
Owatonna
37.3
25.0
Always (80% or
more)
21.7
Additional heating covered less
than 20% of their total square
footage.
Rochester
Sometimes (20% to Often (50% to 80%)
50%)
32.6
FREQUENCY OF USING ADDITIONAL HEATING*
*Respondents that have additional heating.
Percent of Respondents
Heating - continued
Percent of Respondents
<20%
46.6
57.1
53.7
Austin
20%-40%
17.216.317.6
8.2
Owatonna
8.3
61%-80%
1.7
10.2
Rochester
13.0
41%-60%
20.7
*Respondents that have additional heating.
0
10
20
30
40
50
60
43
AMOUNT OF SQUARE FOOTAGE HEATED BY
ADDITIONAL HEATING*
8.2 7.4
80% +
13.8
A larger percentage of Owatonna
businesses indicate that they use
their additional heating more
than 80% of the time in Winter.
MMP
Percent of Respondents
95.2
Austin
Yes
96.3
Owatonna
94.3
3.7
5.7
Rochester
No, Part of Lease
4.8
More Owatonna businesses
reported having no central air
conditioning. Few businesses
report having heat pump
systems.
0
10
20
30
40
50
60
70
80
90
100
PAY FOR CENTRAL AIR CONDITIONING
Air Conditioning
Percent of Respondents
0
10
20
30
40
50
60
70
14.8
None
25.3
14.9
49.1
Austin
Owatonna
Central
42.3
55.1
28.6
34.7
Rochester
Central (Roof top)
42.3
TYPE OF CENTRAL AIR CONDITIONING
44
Heat Pump
0.7 1.0 1.3
Businesses pay for central air
conditioning.
MMP
Percent of Respondents
0
10
20
30
40
50
60
70
80
48.4
Yes
42.7
Austin
48.7
Owatonna
Rochester
No
43.7 45.7 42.1
11.6
9.1
Don't know/No answer
7.9
REPLACED CENTRAL AIR CONDITIONING IN LAST 7
YEARS
Air Conditioning - continued
45
Just under one-half
replaced their central air
conditioning system in the
last seven years.
MMP
Percent of Respondents
0
10
20
30
40
50
60
70
80
46.5
Yes
36.8
Austin
45.8
Owatonna
44.4
45.8
Rochester
No
48.9
14.5
8.4
Don't know/No answer
9.2
REPLACED WATER HEATER IN LAST 7 YEARS
Water Heating - continued
46
Just under one-half
replaced their water heater
in the last seven years.
MMP
Percent of Respondents
None
77.9 77.3
80.9
Austin
14.9
Owatonna
1 to 5
18.8 20.2
Rochester
6 to 10
2.7 1.0 1.6
11 or more
0.7 1.3 2.7
The majority indicated that less
than 20% had been purchased in
the last 7 years.
0
10
20
30
40
50
60
70
80
90
100
NUMBER OF COMMERCIAL REFRIGERATION UNITS
IN USE AT THIS BUSINESS
Refrigerators - continued
0
10
20
30
40
50
60
70
80
90
<20%
51.6
60.061.5
Austin
20% to 40%
14.312.3
22.6
0.0
7.7
Owatonna
2.9 1.5
61%-80%
0.0
Rochester
41% to 60%
6.5
47
81%+
22.9
19.4
16.9
COMMERCIAL REFRIGERATION UNITS PURCHASED
IN LAST 7 YEARS*
More than three-fourths indicated
they had no commercial
refrigeration units.
*Businesses that have commercial refrigeration units
Percent of Respondents
MMP
Percent of Respondents
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
81.0
Austin
No
84.8
Owatonna
88.3
Rochester
19.0
Yes
15.2
FOOD PERPARATION EQUIPMENT AT THIS
BUSINESS THAT IS USED COMMERCIALLY
Food Preparation
11.7
48
Less than 20% indicated
that they have food
preparation equipment that
is used commercially.
MMP
0.0
10.0
20.0
30.0
40.0
50.0
35.4
None
33.8
43.5
Austin
1 to 10
33.833.2
31.3
23.1
4.9
2.7
5.8
0.7
2.7 3.2
Rochester
51 to 100 101 to 500
Ow atonna
11 to 50
16.8
26.8
NUMBER OF UNITS WITHIN INTERIOR BUSINESS SPACE:
INCANDESCENT (STANDARD BULBS)
About three-fourths of
businesses have T-12
Fluorescent bulbs. The largest
percentage indicate having 11 to
50 bulbs.
Percent of Respondents
Lighting
500+
0.0 1.1 1.2
0.0
10.0
20.0
30.0
40.0
50.0
None
26.0
31.0
25.5
Austin
1 to 10
18.4
16.316.7
10.6 9.8
12.6
5 4.9 6.1
Rochester
49
51 to 100 101 to 500
Ow atonna
11 to 50
39.7
37.537.4
NUMBER OF UNITS WITHIN INTERIOR BUSINESS SPACE:
T-12 FLUORESCENT (STANDARD)
500+
0.7 0.5 1.2
More than half indicated that their
business has some incandescent
bulbs. The largest percentage have
1 to 10 bulbs.
Percent of Respondents
MMP
Percent of Respondents
None
81.779.3
74.8
Austin
1 to 10
8.2
5.6 7.6
1.4 2.2 2.9
0.7 2.2 2.3
Rochester
51 to 100 101 to 500
Ow atonna
11 to 50
10.6 8.7 11.1
500+
0.0 0.0 0.6
Less than 10% of businesses in
all AOR Utilities indicated that
they have T-5 Fluorescent bulbs.
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
NUMBER OF UNITS WITHIN INTERIOR BUSINESS SPACE:
COMPACT FLUORESCENT (CFL)
Lighting - continued
100.0
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
None
90.192.492.4
Ow atonna
Austin
2.1 1.1 0.6
0.0 0.0 0.3
Rochester
50
51 to 100 101 to 500
11 to 50
3.5 3.8 4.1
1 to 10
4.2 2.7 2.6
NUMBER OF UNITS WITHIN INTERIOR BUSINESS SPACE:
T-5 FLUORESCENT
500+
0.0 0.0 0.0
About one-fourth of Rochester and
20% of Austin and Owatonna
businesses have some compact
fluorescent. The largest percentage
have 11 to 50 bulbs.
Percent of Respondents
MMP
Percent of Respondents
None
78.4
73.9
71.6
Austin
1 to 10
5.7 6.5 4.4
8.5
7.1
3.3 3.5
2.8 3.8
5.0
Rochester
51 to 100 101 to 500
Ow atonna
11 to 50
12.111.4
Around 40% of businesses
indicated that they have Exit
Signs. The largest percentage
have 1 to 10 signs.
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
NUMBER OF UNITS WITHIN INTERIOR BUSINESS SPACE:
T-8 FLUORESCENT
Lighting - continued
500+
0.7 1.1 0.3
100.0
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
None
61.7
58.157.1
Ow atonna
Austin
0.0
3.8 2.0
0.7 0.0 0.9
Rochester
51
51 to 100 101 to 500
11 to 50
7.1 7.0 9.0
1 to 10
29.830.630.6
NUMBER OF UNITS WITHIN INTERIOR BUSINESS SPACE:
EXIT SIGNS
Between 20% and 30% of have
some T-8 fluorescent units. The
largest percentage have 11 to 50
bulbs.
Percent of Respondents
500+
0.7 0.5 0.3
MMP
Percent of Respondents
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
<20%
23.121.723.2
2.3
4.6
3.7 4.6 5.5
Austin
Owatonna
20% to 40% 41% to 60%
6.7
4.6 4.3
Rochester
61% to 80%
2.2
81%+
24.622.9
17.7
FLUORESCENT LAMPS UPGRADED TO
ELECTRONIC BALLASTS AT THIS BUSINESS
Lighting - continued
Don't Know
44.044.6
39.6
52
The largest percentage
didn’t know whether their
fluorescent bulbs had been
upgraded to electronic
ballasts or not.
MMP
51.4%
17.6%
15.7%
65.6%
11.3%
5.8%
1 to 5
6 to 10
10 or more
0.8%
3.4%
75.1%
20.7%
Copiers
0.3%
0.3%
47.5%
52.0%
53
Scanners
The table provides an overview of the number of pieces of office
equipment for Rochester businesses. Personal computers have the
highest saturation (85%) followed by printers (83%) and copiers
(79%). About 48% indicated having one or more scanners.
*Percentage of all businesses
15.2%
Personal Computers
17.3%
Printers
Rochester
Overview of Office Equipment*
None
Number of Pieces
Other Equipment - continued
MMP
Austin = 4 Owatonna = 14 RPU = 7
54
Note 25 Respondents - Indicators Only
Summary of Findings:
Large Commercial & Industrial
Customers
MMP
& Storage
Care
„Food Processing - 3
„Shipping Containers
„Pet Food Manufacturer
„Steel Fabrication
„Fitness Equipment
„Metal Products
„Industrial Manufacturing
„Growing Tomatoes
„Sheet Metal Fabricator
„Health
„Warehousing
The types of operations responding
to study are:
Building & Firmographics
„
„
„
„
„
„
„
„
„
„
„
55
Large Retail
Retirement Nursing Care
Laundry
Hotel/Office/Condo
Ice cream and Frozen Desserts
Church - 2
School
Church & School
Ice Arena/Convention Center
Glass Fabrication
Large Grocery
Of these 25 customers all but two
owned their facilities.
MMP
C
u
s
t
o
m
e
r
s
0
1
2
3
4
5
50k 100k
10k 25k
1k 2.5k
Square Footage of Conditioned Space
Building & Firmographics
500k 1000k
56
Half of the
respondents were in
facilities between
25,000 sq. ft. to
100,000 sq. ft.
MMP
C
u
s
t
s
o
m
e
r
0
2
4
6
8
% Hours of Operation
Building & Firmographics
8090%
6070%
1-50%
57
This table
shows that
almost half of
this customer
group operates
24/7 hours per
week.
MMP
7
15
2
Suspend Certain
Operations
Reduce Use
No Response
58
70% of this customer group is responding in some manner to
peak alerts or interruptible rates. There is no correlation to
size of load or type of customer seen in the data.
0
5
10
15
Response to Peak Alerts or Interruptible Rate
Energy & Water Management
MMP
„
„
„
„
„
„
„
High voltage electrical repairs
Low voltage electrical work
HVAC maintenance
Mechanical maintenance
Plumbing maintenance
Full-time energy manager
Part-time energy manager
4
7
11
19
14
Capabilities/Knowledge on Site
24
20
59
Skill levels usually
follow size of
operation. The large
manufacturers have
the highest skill levels.
However it should be
noted that only 4
customers have full
time energy managers
and 7 have part-time.
Energy & Water Management
MMP
$0
$10,000
$20,000
$30,000
$40,000
$50,000
$60,000
0
2
4
6
8
10
Minor
Moderately
Significant
Very
Significant
Significance of Interruption Cost
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Cost of 15-Minute Interruption
60
As illustrated in the 18
responses some customers
consider an outage of minor
importance and not much
value, to others where the
cost can be up to $55,000
from a 15-minute
interruption.
Energy & Water Management
MMP
1. Consolidated billing of
multiple facilities
2. Monthly billing based on a
calendar year
3. Monthly billing based on a
fiscal year
4. Electronic interface for bills,
meter reading, payments,
electronic mail
5. Water reliability-based rates
adjusted depending on your
need for reliable or constant
supply
6. Electricity reliability-based
rates adjusted depending on
your need for reliable or
constant supply
7. Time of use rates at various
time periods during the day
and/or on weekends
8. Real time pricing rate that
varies each hour to allow you to
operate during the periods at
low cost.
9. Direct access to your account
information on the Internet
Billing Services
AOR
AOR
2.95
3.22
3
1
2.83
3
2.84
3.06
5
1
2.11
1
2.83
2.84
8
3
2.16
3
Currently Customer
Mean
Offered
Currently
Value
by Utility Participating Score
Energy Services - cont.
61
For the “Billing Services”
there were no items of high
interest to everyone.
MMP
1
6. Tele-metering to a central
monitoring location off-site
2.2
3.05
3.1
3.05
3.21
Energy evaluation services have some interest and some
people getting these services elsewhere. Assistance in
budgeting and forecasting usage has the highest score of
this group of services.
3
5. Sub-metering for gas
processes
OR
3. Sub-metering for electric
processes
3
5
AOR
2. Assistance in budgeting and
forecasting energy usage
4. Sub-metering for water
processes
1
AOR
1. Graphic interval analysis of
your energy usage pattern
Currently
Mean
Participating Value
Score
3
3.1
Currently
Offered
Energy Evaluation Services
Energy Services - cont.
62
MMP
AOR
12. Total efficiency
assessment covering
energy, productivity and
waste management
3.19
3.15
2
1
2.38
0
2.95
2.80
3.05
The balance of the energy evaluation services show that realtime energy consumption data has some interest as well as
total efficiency assessments. Still these have limited interest.
AOR
1
AOR
10. GeoExchange
(geothermal) heating and
cooling consulting
11. Access to real-time
energy consumption data
1
AOR
8. Metering input for EMS
(energy management
systems)
9. EMS reviews and
assistance
2
AOR
Currently Currently
Mean Value
Offered
Participating Score
7. Process energy audits
Energy Evaluation
Services cont.
Energy Services - cont.
63
MMP
3.11
3.11
3.00
3.63
9. Energy utility provided
environmental consulting
services on generator permitting
10. Energy utility provided
services on lamp recycling
3.30
6. Quarterly newsletters to
provide updates on technologies,
grants, new services, etc.
7. Turn-key engineering services
for installation of efficiency
improvements
8. Energy utility provided power
quality monitoring
3. Energy utility provided
management of energy services
such as fuel procurement, and
boiler or generator operations
4. Technical information on new
technologies related to your
industry
5. Assistance in identifying
suppliers of various technologies
1. Assistance in troubleshooting
and resolving power quality
problems
2. Education/training seminars on
various technologies
Energy Information &
Management Services
1
3
AOR
1
AOR
OR
1
AOR
1
AOR
3
1
AOR
AOR
1
3
AOR
AOR
3
Currently
Participating
AOR
Currently
Offered
Energy Services - cont.
3.63
3
3.11
3.11
3.3
3.1
3.42
3.11
3.33
Mean
Value
Score
3.43
64
Energy Information
Services is the only
grouping of services in
the survey where all
offerings received a 3
or greater average
rating.
MMP
1. Locating customer-owned
underground facilities
(storage tanks, telephone,
water, etc.)
2. Substation maintenance
design, installation and/or
maintenance
3. Infra-red scanning of
electrical systems and
building components
4. Outdoor security lighting
5. Testing equipment for
analysis of power quality
problems
6. Purchase of power quality
equipment from your energy
utility
7. Lease transformers
(includes maintenance and
replacement)
8. Lease small back-up
generators for your
operations to be located on
your site
9. Lease and maintain small
back-up generators on your
site
10. Buy/lease/rent water
heating or HVAC equipment
(includes maintenance and
replacement)
Energy Operations
Services
3.50
3.05
2.6
2.25
2.53
2.40
2.65
7
6
1
0
0
0
0
2
AOR
AOR
AOR
3.53
2.53
1
OR
Mean
Value
Score
3.15
3
Currently
Participating
AOR
Currently
Offered
Energy Services - cont.
65
Energy Operations
services has two
services with high
scores above 3.5
and high
participation.
MMP
1
0
AOR
OR
0
16. Fuel cells from your energy
utility
17. Lighting retrofit and new
construction provided by your
energy utility
18. Power factor correction
services provided by your
energy utility
19. Solar and wind power
projects
2
1
15 Building maintenance and
controls from your energy utility
AOR
0
2.6
3.11
2.94
2.35
2.68
3.35
2.55
0
14. Energy utility provided backup generators for outages
2.74
2
12. Warranty or maintenance
agreements for energy
equipment and appliances
13. Energy utility provided wiring
services within your facilities
Mean
Value
Score
2.94
3
Currently Currently
Offered
Participating
11. Maintenance services on
HVAC owned by your company
Energy Operations Services
cont.
Energy Services - cont.
66
Continuing on the
list of operations
services, customers
see value in
providing back up
generators for
outages.
MMP
12
10
8
6
4
2
0
a
2
1
1
2
-
-
n
n
c
t
t
i
o
h
V
0
4
o
t
e
i
u
t
h
x
c
p
c
l
L
a
H
3
4
8
5
F
O
E
O
H
M
F
500+
F
101-500
T
51-100
T
11-50
Lighting
C
1-10
Technologies
r
67
MMP
1
2
2. Medical equipment
3. Well pump
4
3
1
10
5. Shop tools
6. Irrigation pump
7. Welding equipment
3
5
11. Number of rewound motors
12. Number of variable speed drives
10
7
1
1
Gas
1-5
2
1
Gas
6-10
Gas
10+
Other non-listed equipment included:
•One customer with 6-10 gas paint ovens
•One customer with 6-10 gas engines to run NH4 compressors
•One customer with 10+ electric microwave generators
•One customer with 6-10 35-hour electric compressor motors
4
2
11
5
10. Motors older than 10 years
6
6
7
9. Motors over 50 horsepower
5
24
5
1
15
20
1
Electric
10+
8. Total motors
4
3
1
Electric
6-10
1
4. Fans
1. Kiln
Electric
1-5 units
1
Equipment Type
Technologies
68
Every customer
responding said they
have more than ten
motors at their
facility. Six of these
customers had more
than ten motors over
50 horsepower.
MMP
„
„
69
One of these six also stated they used the generator for
outages and peak shaving. This customer also plans on
purchasing another generator within two years.
They sizes of these units are;
„ 2 units over 100 kW,
„ two units between 51-100 kW
„ one unit between 10-25 kW.
customers had generators that are used for
standby power and emergency lighting when there
are outages.
„Six
Other Technologies
MMP
Nine indicated the percentage of change and it ranged
from 5% to 20% due primarily to increased business.
Two customers indicated a decrease in energy use due
to a lighting retrofit and phasing out an old building.
The balance indicated no change.
„
Only one indicated a decrease in use and gave no
reason.
70
Again two customers indicated a reduction in use but
these were two different customers than the electric
reduction and no reasons were provided
Water Use - 11 expected an increase from 3% to
30%
„
Gas Use - 12 expected an increase in use from 3% to
30%
„
Future Electric Use - 13 expected to increase.
Future Energy & Water Use
MMP
program with the large C&I customers.
ƒ There appears to be an opportunity for an expanded motor
71
that could be expanded or offered as a new service. Further research
would need to be provided.
ƒ For large C&I customers there is interest in some energy services
ƒ There appears to be opportunities for lighting improvements.
•Only a small percentage of commercial and industrial customers
indicated that water conservation measures had been taken.
However, Low-flow showerheads or toilets applications are limited.
•In general, small commercial customers do not clearly see the
benefits of energy/load conservation management while most larger
customers are participating.
Recommendations
MMP
72
All these indicate that AOR Utilities need to do a
better job of promoting the benefits to commercial
and industrial customers of current energy/demand
management programs and there are opportunities
to expand or provide new additional DSM services.
are significant for some large customers and
there appears to be an opportunity to provide backup services
or special rates/service to this group.
ƒ Interruptions
Recommendations - continued
MMP
„
„
„
73
Forecasting energy use by class
„ Growth of air conditioning - How many newer and
more efficient, see change over time
System demand forecast and facility forecasts
DSM potential determination
„ Many old refrigerators out there
„ Program interest and opportunity
Uses of Data
MMP
Thanks!
QUESTIONS
74
End Use Survey Question Forms for Residential, Commercial &
Industrial Customers
RESIDENTIAL CUSTOMER APPLIANCE/EQUIPMENT SURVEY
Instructions: Thank you for your participation. Please check (9) the appropriate box(s) that
corresponds with your answer or write your response clearly in the space
provided. Your answers will remain strictly confidential.
YOUR HOME AND LIFESTYLE
1. Choose the statement that best describes the building where you live.
1 One story single-family house
2 Two-story single-family house
3 Mobile home
4 Other
Apartment/Condo
5 High rise (4+ stories)
6 Low rise (1-3 stories)
7 Townhouse or row house (Neighboring units on one or both sides, but not above or below)
1b. If apartment or condo, please indicate the number of units in your building. ___________
2. Do you own or rent?
1 Own 2
Rent
3. What portion of the year is this home occupied?
2 Summer Only
1 Year Round
3
Winter Only 4
4. What is the approximate age of your home?
2 1-5 years
1 New (less than one year)
5 16-30 years
6 31-50 years
3
7
Other seasons
6-10 years
Over 50 years
4
11-15 years
5. How many rooms are in your home? (Only include areas used as living space, including finished and
conditioned basements). Do NOT include bathrooms and hallways)
1 1 Room
4 4 Rooms
7 7 Rooms
10 10 Rooms
13 13 Rooms
5 5 Rooms
8 8 Rooms
11 11 Rooms
14 14 Rooms
2 2 Rooms
3 3 Rooms
6 6 Rooms
9 9 Rooms
12 12 Rooms
15 15+ Rooms
6. How many bathrooms do you have in your home?
2 2
3 3
1 1
4
4
5
more than 4
7. What is the approximate square footage of the living space of your home? (Do not include
unconditioned garage, attic, or basement space.)
1 Less than 600
4 1501-2000
7 3001-3500
10 5001-7500
2 601-1000
5 2001-2500
8 3501-4000
11 7501-10000
6 2501-3000
9 4001-5000
12 10000+
3 1001-1500
8. Indicate the number or people that live in your home at least half of the year.
Number of People
1
2
3
4
5
6
7
8
9
10
11
12
9. During a typical week, how often are people home on weekdays from 12 noon until 4 pm? How about
from 4 pm until 8 pm? (Check one for each time period)
a. 12 noon until 4pm
b. 4 pm until 8 pm
Never
1
1
One or two
weekdays
2
2
Three or four
weekdays
3
3
Every weekday
4
4
10. Do you have a home-based business?
2 Yes (Describe ___________________________________________________)
1 No
11. Please indicate if you currently participate in the following energy conservation/load management
programs. Also, indicate how valuable they are to you or would be if you do not currently
participate. (Check if participate and check value level for each program type)
a
b
Currently
Participate
1. AC cycling during hottest days
2. Water Heater cycling a.m. or p.m.
3. Other
Specify ____________________
1
1
1
Not at all
Valuable
1
1
1
Not Very
Valuable
Somewhat
Valuable
2
2
2
12. What is the highest education level of the Head of Household?
1 Less than high school graduate
3 Some college
2 High school graduate
4 College graduate
13. What is the age of the Head of Household?
1 Less than 30
3 40-49
2 30-39
4 50-64
14. What is the approximate total household income level?
1 $20,000 per year or less
3 $40,001-$60,000 per year
2 $20,001-$40,000 per year
4 $60,001-$80,000 per year
Very
Valuable
3
3
3
5
4
4
4
Extremely
Valuable
5
5
5
Post college graduate work or more
5
65 or older
5
6
$80,001-$100,000 per year
$100,000 per year or more
HEATING
15. Do you pay to heat your residence?
1 Yes
2
No, it is part of my rent
16. What type of heating system do you use to heat your home? (If there is more than one heating
system, describe the system that provides most of the heat as “Main Heating” and the other
system(s) as “Additional Heating”)
a.
b.
Main Heating
Additional Heating
(Check only
(Check all boxes
one box below)
that apply)
1
1. Natural gas central forced air furnace
1
2
2. Natural gas wall/floor Heater
2
3. Other natural gas system type
3
3
4. Electric resistance/baseboard/ceiling
4
4
5. Electric air source heat pump
5
5
6. Electric geo-thermal heat pump
6
6
7 Electric central forced air furnace
7
7
8. Electric wall/floor heater
8
8
9. Other electric system type
8
9
10. Central boiler
10
10
11. Woodstove/Fireplace Insert
11
11
12. Fireplace
12
12
13. Propane
13
13
14. Other Fuel
14
14
17. Was your main heating system purchased or replaced in the last five years?
2 No
1 Yes
3
Don’t Know
18. How often do you use your additional heating system(s) during the winter months?
1 No additional heating
4 Often (50-80% of the time)
2 Rarely (20% of the time)
5 Always (80% or more)
3 Sometimes (20-50% of the time)
2
19. How many rooms are heated by your additional heating system?
1 All rooms 2 1 room 3 2-3 rooms 4 4-7 rooms 5 8-10 rooms 6 10+ rooms
20. How many portable electric heaters do you use?
0 None
1 One
2 Two
3 Three or more
COOLING
Central Air Conditioner
21. What type of central air conditioner do you use?
1 Central
0 None (SKIP TO Q.25)
2
Heat pump
22. Do you pay for your central air conditioning?
2 No, it is part of my rent
1 Yes
23. Was your central air conditioning unit purchased or replaced within the last five years?
1 Yes
2 No
3 Don’t Know
24. Please indicate how often the central air conditioner is used during the summer. (Choose one
for each time period)
Never
Rarely
Sometimes
Often
Always
(20% of time) (40% of time) (70% of time)
a. Day
1
2
3
4
5
b. Evening
1
2
3
4
5
c. Night
1
2
3
4
5
Room Air Conditioning
25. How many window/wall air conditioners do you use?
0 None (SKIP TO Q.28)
1 1 Unit
2 2 Units
3
3 Units
4
More than 3 units
26. Have you purchased or replaced the window/wall air conditioner that is used most frequently
in the last five years?
1 Yes
2 No
3 Don’t Know
27. Please indicate how often the main room air conditioner is used during the summer. (Choose
one for each time period)
Rarely
Sometimes
Often
Never (20% of time) (40% of time) (70% of time) Always
a. Day
1
2
3
4
5
b. Evening
1
2
3
4
5
c. Night
1
2
3
4
5
THERMOSTAT SETTING
28. When you operate your central heating or air conditioning systems, indicate below what setting you use
for the fan operation as well as the typical temperature setting. (Choose a fan AND temperature setting
for each season)
a. Fan Setting
b. Temperature Setting
Fan Set to
Fan Set to
AUTO
ON
65-68
69-72
73-75
76+
1. Winter
1
2
1
2
3
4
2. Summer
1
2
1
2
3
4
3. Spring
1
2
1
2
3
4
4. Fall
1
2
1
2
3
4
WATER HEATING
29. Do you pay to heat your water?
1 Yes
2 No it is included in my rent
3
30. Which of the following best describes the water heater? (Choose one box below)
1
2
3
Natural Gas
Standard separate tank
Tank with solar collectors
Other system type
4
5
6
7
Electric
Standard separate tank
Tank with solar collectors
Instantaneous (at sink)
Other system type
Propane/Other fuel
8 Any system type
31. Have you purchased or replaced your water heater in the last five years?
1 Yes
2 No
3
Don’t Know
32. Consider the total number of people in your home and then check the total number of baths
and showers taken during a typical week.
<5
6-10
11-15
16-20
21-25
26-30
30+
1
33. Do you use flow restrictors or energy-saving (low flow) showerheads?
1 Yes, all showers
2 Yes, some showers
3
No
LAUNDRY
Clothes Washer
34. Do you have a washing machine? (Do not include coin-operated machines or machines in
apartment common areas)
1 Yes
2 No (SKIP TO Q.35)
35. How many loads of laundry are washed each week in your home using this machine?
<1
0
1
2
3
4
5
6
7
8
9
10
10+
11
Clothes Drying
36. Do you have a clothes dryer? (Do not include coin-operated machines or machines in
apartment common areas)
1 Yes
2 No (SKIP TO Q.39)
37. What is the heating fuel for your clothes dryer?
1 Natural gas
2
Electricity
3
Propane/other fuel
38. Approximately how many loads does your household dry each week using this clothes dryer?
<1
0
1
2
3
4
5
6
7
8
9
10
10+
11
39. Do you line-dry clothing? (If so, choose one answer for each season)
a. 1
yes
b. Summer
c. Winter
2
Never
1
1
Rarely
2
2
Sometimes
3
3
no (SKIP TO Q.40)
Often
4
4
Always
5
5
REFRIGERATORS
40. How many refrigerators do you have plugged in?
0 0 (SKIP TO Q.45)
1 1
2
2
3
3 or more
41. What style best describes the refrigerator(s)? (Check one box for each refrigerator)
a
b
c
Refrigerator 1 Refrigerator 2 Refrigerator 3
Top-Bottom
1
1
1
Side-by-Side
2
2
2
4
42. What size, in cubic feet, best describes the above refrigerator(s)? (Refrigerator information is
usually found on a nameplate just inside the door) (Check one box for each refrigerator)
a
b
c
Refrigerator 1
Refrigerator 2
Refrigerator 3
1
1
Very small (under 13 cubic feet)
1
2
2
Small (13-16 cubic feet)
2
Medium (17-20 cubic feet)
3
3
3
4
4
Large (21-23 cubic feet)
4
Extra Large (over 23 cubic feet)
5
5
5
43. What type of defrost does the above refrigerator(s) have? (Check one box for each refrigerator)
a
b
c
Refrigerator 1 Refrigerator 2 Refrigerator 3
Automatic (frost-free)
1
1
1
Manual
2
2
2
Partial Automatic*
3
3
3
*(These have a frost-free refrigerator and manual defrost freezer)
44. Please check each refrigerator that was purchased in the last five years.
a
b
Refrigerator 1
Refrigerator 2
1
Purchased in last five years
1
c
Refrigerator 3
1
STAND-ALONE FREEZERS
45. How many stand-alone freezers do you have plugged in? (Do not include freezers that are part
of your refrigerator unit)
0
0 (SKIP TO Q.50)
1
1
2
2 or more
46. What style best describes the freezer(s)? (Check one box for each freezer)
a
b
Freezer 1 Freezer 2
Upright
1
1
Chest
2
2
47. What size, in cubic feet, best describes the above freezer(s)? (Freezer information is
usually found on a nameplate just inside the door) (Check one box for each freezer)
a
b
Freezer 1
Freezer 2
1
Very small (under 10 cubic feet)
1
2
Small (11-15 cubic feet)
2
Medium (16-20 cubic feet)
3
3
4
Large (21-25 cubic feet)
4
Extra Large (over 25 cubic feet)
5
5
48. What type of defrost does the above freezer(s) have? (Check one box for each freezer)
a
b
Freezer 1 Freezer 2
Automatic (frost-free)
1
1
Manual
2
2
49. Please check each freezer that was purchased in the last five years.
a
Freezer 1
Purchased in last five years
1
b
Freezer 2
1
5
FOOD PREPARATION
50. What type of range/oven do you use?
1 Combination: electric and gas
2 Propane (bottled gas) only
3
4
51. How often do you use your microwave oven?
1 Never 2 Sometimes 3 Rarely
Natural gas only
Electric only
4
Often
5
5
Other
We don’t have a microwave oven
52. How often do you run your dishwasher each week?
0
1
We do not have or use a dishwasher (SKIP TO Q.53)
2
3
4
5
6
7
53. Which dishwasher cycle do you most often use?
2 Energy Saver
1 Heated Drying
3
8
Air Dry
9
4
10 or more
Other
SPAS, HOT TUBS, and POOLS
54. Do you have a spa or hot tub at your home? (Do not include whirlpool bathtubs)
1 Yes, and I pay to heat it
2 Yes, but I do not pay to heat it
3 No spa or hot tub (SKIP TO Q.59)
55. How is the spa or hot tub heated?
1 Electric heat pump
2 Solar with electric backup
3
4
Natural Gas
Electricity
56. Do you use an insulated cover on your spa or hot tub?
1 Yes
2 No
3
5
6
Propane (bottled gas)
Solar with gas backup
No, but it is located indoors
57. Please indicate how often you use your spa or hot tub in both the summer and winter. Choose one
for each season).
Never
Rarely
Once a month
Once a week
2-4 times a week
5 or more times a week
a. Summer
1
2
3
4
5
6
b. Winter
1
2
3
4
5
6
58. How large is your spa or hot tub?
1 Small (3 people or less)
2 Medium (4-6 people)
3 Large (7 or more people)
59. Do you have a swimming pool?
1 Yes, and I pay for its energy use
2 Yes, but it is in a common area and I do not pay for its energy use
3 No (SKIP TO Q.61)
60. How is the pool heated?
1 Pool is not heated
2 Electric heat pump
3
4
Electricity
Solar cover
5
6
Solar heated
7
Propane (bottled gas)
Natural Gas
6
61. Please indicate the number of hours per day the swimming pool filter operates. (Choose one
for each season).
a. Summer b. Winter
Not operated
1
1
Up to 2 hours
2
2
3-4 hours
3
3
5-6 hours
4
4
7-8 hours
5
5
9-12 hours
6
6
13-23 hours
7
7
24 hours
8
8
LIGHTING
62. Please indicate the number of energy saving or compact fluorescent (CFL) bulbs that are used for
interior lighting?
0
1
2
3
4
5
6
7
8
9
10 or more
63. (SKIP TO Q.63 IF NO CFL BULBS) Which of the following best describes how many of these compact
fluorescent bulbs lights are turned on in the evenings until bedtime?
1
2
3
4
All of the lights
Most of the lights
Some of the lights
1or 2 lights
OTHER APPLIANCES
64. Indicate how many of the following appliances are used in your home.
(Choose no more than one response for each appliance listed)
1
a. Color television
b. Black & white television
c. VCR
d. Stereo system
e Personal computer
f. Humidifier
g. Dehumidifier
h. Well pump
i. Irrigation pump
j. Heated waterbed
k. Aquarium
l. Gas fireplace
m. Attic fan
n. Portable fan
o. Ceiling fan
p. Whole house fan
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
3 or more
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
65. Please indicate how often the following fans are used during the summer.
a. Portable Fan
b. Ceiling fan
c. Whole house fan
Never
1
1
1
Rarely
2
2
2
Sometimes
3
3
3
Often
4
4
4
Always
5
5
5
7
66. How many total hours are your TVs on per day? (Include all TVs in your home)
1 No TVs
3 1-3
5 7-10
7 15-20
9
2 Less than 1
4 4-6
6 11-14
8 21-26
10
27-35
More than 35
67. If you regularly use (3 or more hours per week) any other appliances not mentioned, please
check them below.
Electric Gas
Electric
a. Kiln
1
2
c. Shop tools
1
b. Medical equipment
1
2
d. Welding equipment
1
e. Other
1
2
Describe Other: ____________________________________________________________
OTHER WATER USAGE/CONSERVATION
68. Please indicate total number of toilets in your home, and of these, the total number of low-flow toilets.
(Choose one for each type)
1
a. Total toilets
b. Total low-flow toilets
2
1
1
3
2
2
3
3
4
4
4
4+
5
5
69. Please indicate the total number of showers and bathtubs in your home. If your tub has a shower
head, count it also as a shower. (Check one category for each type)
1
a. Total bathtubs
b. Total showers
1
1
2
3
2
2
3
3
4
4
4
4+
5
5
70. Do you water your lawn with a garden hose? (If so, choose the frequency in each season)
a. 1
yes
b. Spring
c. Summer
2
Rarely
1
1
no (SKIP TO Q.70)
Sometimes
2
2
Often
3
3
71. Do you have a lawn/shrub irrigation system? (If so, choose the level of usage for each
season)
a. 1 yes
2 no (SKIP TO conclusion)
b. Spring
c. Summer
Rarely
1
1
Sometimes
2
2
Often
3
3
72. Write any other comments that you would like provide to us in the space below.
________________________________________________________________________________________
________________________________________________________________________________________
_________________________________________________________________________________
That concludes our survey. Thank you for your time and cooperation. Your answers will be very
helpful in our continuing efforts to better serve you. Please return your completed survey in the
enclosed postage-paid envelope.
8
LARGE COMMERCIAL AND INDUSTRIAL CUSTOMER
EQUIPMENT/APPLIANCE SURVEY
Instructions: Thank you for your participation. Please check (9) the appropriate box(s) that
corresponds with your answer or write your response clearly in the space
provided. Your answers will remain strictly confidential.
BUILDING AND FIRMOGRAPHICS
1. Is the space occupied by this business owned, leased or managed by the business?
1 Owned 2 Leased 2
Managed
2. What portion of the year does this business operate at this site?
1 Year Round
2 Summer Only
3 Winter Only 4
Other seasons
3. What is the approximate square footage of the conditioned space of at this site? (Do not include
unconditioned storage, warehouse, attic, or basement space.)
4 5,001-7,500
7 25,001-50,000
10 250,001-500,000
1 1,000 or less
5 7,501-10,000
8 50,001-100,000
11 500,001-1,000,000
2 1,001-2,500
3 2,501-5,000
6 10,001-25,000
9 100,001-250,000
12 1,000,000+
4. How many full and part-time employees work at this location?
4 51-100
7 251-500
1 10 or less
2 11-50
5 101-250
8 501-1000
10
11
1001-5000
5000+
5. During a typical week, indicate the number hours the business is in operation by the time period and day
type below (Fill in the number of hours for each as appropriate)
a
12:00a.m to 8:00a.m
b
8:00am. to 5:00p.m.
c
5:00p.m. to 9:00 p.m.
d
9:00p.m. to 12:00a.m.
1. Weekdays
2. Weekends
6. Which one of the following best describes the main business activity at this location? (Check one)
2 Restaurant
1 Fast Food
3 Small Grocery
4 Large Grocery (e.g. Kroger, Safeway)
6 Large Retail (e.g., Kmart, Walmart, Best Buy)
5 Small Retail
7 Prof. Services (e.g., doctor, lawyer, accountant)
8 Trade Services (e.g., auto repair, laundry)
10 Communications
9 Warehousing/storage
11 Transportation
12 Construction
14 Banking/Finance/Insurance
13 Real Estate
15 Wholesale-Durables
16 Wholesale-Non-durables
18 Government
17 Food Processing
19 Manufacturing (Describe _________________________________________________________)
20 Other (Describe_________________________________________________________________)
ENERGY AND WATER MANAGEMENT
7. Does this business respond to peak alerts or an interruptible rate?
1 No
2 Yes, reduce use
3
Yes, suspend certain operations
8. Which of the following capabilities or knowledge do you have on site? (Check one answer
for each)
Yes
1
1
1
1
1
1
1
a. High voltage (over 480 volt) electrical repairs
b. Low voltage electrical work
c. HVAC maintenance
d. Mechanical maintenance
e. Plumbing maintenance
f. Full-time energy manager
g. Part-time energy manager
No
2
2
2
2
2
2
2
9. Please indicate if you currently participate in the following energy or water billing services products and
services. Also, indicate how valuable they are to your business or would be if you do not currently
participate. (Check if participate AND check value level for each program type)
a.
b.
Currently
Participate
1. Consolidated billing of multiple
facilities
2. Monthly billing based on a
calendar year
3. Monthly billing based on a fiscal
year
4. Electronic interface for bills, meter
reading, payments, electronic mail,
etc.
5. Water reliability-based rates
adjusted depending on your need
for reliable or constant supply
6. Electricity reliability-based rates
adjusted depending on your need
for reliable or constant supply
7. Time of use rates at various time
periods during the day and/or on
weekends
8. Real time pricing rate that varies
each hour to allow you to operate
during the periods at low cost.
9. Direct access to your account
information on the Internet
Not at all
Valuable
Not Very
Valuable
Somewhat
Valuable
Very
Valuable
Extremely
Valuable
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
10. Please indicate if you currently participate in the following financial services related to your energy
management. Also, indicate how valuable they are to your business or would be if you do not currently
participate. (Check if participate AND check value level for each program type)
a.
b.
Currently
Participate
1. Leasing options for energy
utilization equipment
2. Low or discounted interest rates
for ‘energy efficient structure’
mortgages or new construction
3. Assistance in obtaining funding for
process improvement assessments or feasibility studies
4. Low-cost financing for purchase of
energy efficient equipment
5. “Paid from savings” financing
options for energy improvements
6. Payment of financing for energy
improvement purchases on utility
bills
7. Outage insurance
Not at all
Valuable
Not Very
Valuable
Somewhat
Valuable
Very
Valuable
Extremely
Valuable
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
2
11. Please indicate if you currently participate in the following energy evaluation services. Also, indicate
how valuable they are to your business or would be if you do not currently participate. (Check if
participate AND check value level for each program type)
a.
Currently
Participate
1. Graphic interval analysis of your
energy usage pattern
2. Assistance in budgeting and
forecasting energy usage
3. Sub-metering for electric
processes
4. Sub-metering for water processes
5. Sub-metering for gas processes
6. Tele-metering to a central
monitoring location off-site
7. Process energy audits
8. Metering input for EMS (energy
management systems)
9. EMS reviews and assistance
10. GeoExchange (geothermal)
heating and cooling consulting
11. Access to real-time energy
consumption data
12. Total efficiency assessment
covering energy, productivity and
waste management
b.
Not at all
Valuable
Not Very
Valuable
Somewhat
Valuable
Very
Valuable
Extremely
Valuable
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
1
1
1
1
2
2
2
3
3
3
4
4
4
5
5
5
1
1
1
1
2
2
3
3
4
4
5
5
1
1
1
1
2
2
3
3
4
4
5
5
1
1
2
3
4
5
1
1
2
3
4
5
12. Please indicate if you currently participate in the following energy information and management
services. Also, indicate how valuable they are to your business or would be if you do not currently
participate. (Check if participate AND check value level for each program type)
a.
Currently
Participate
1. Assistance in troubleshooting and
resolving power quality problems
2. Education/training seminars on
various technologies
3. Energy utility provided
management of energy services
such as fuel procurement, and
boiler or generator operations
4. Technical information on new
technologies related to your
industry
5. Assistance in identifying suppliers
of various technologies
6. Quarterly newsletters to provide
updates on technologies, grants,
new services, etc.
7. Turn-key engineering services for
installation of efficiency
improvements
8. Energy utility provided power
quality monitoring
9. Energy utility provided
environmental consulting services
on generator permitting
10. Energy utility provided services
on lamp recycling
b.
Not at all
Valuable
Not Very
Valuable
Somewhat
Valuable
Very
Valuable
Extremely
Valuable
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
3
13. Please indicate if you currently participate in the following energy operations services. Also, indicate
how valuable they are to your business or would be if you do not currently participate. (Check if
participate AND check value level for each program type)
a.
b.
Currently
Participate
1. Locating customer-owned
underground facilities (storage
tanks, telephone, water, etc.)
2. Substation maintenance design,
installation and/or maintenance
3. Infra-red scanning of electrical
systems and building components
4. Outdoor security lighting
5. Testing equipment for analysis of
power quality problems
6. Purchase of power quality
equipment from your energy
utility
7. Lease transformers (includes
maintenance and replacement)
8. Lease small back-up generators
for your operations to be located
on your site
9. Lease and maintain small back-up
generators on your site
10. Buy/lease/rent water heating or
HVAC equipment (includes
maintenance and replacement)
11. Maintenance services on HVAC
owned by your company
12. Warranty or maintenance
agreements for energy
equipment and appliances
13. Energy utility provided wiring
services within your facilities
14. Energy utility provided back-up
generators for outages
15 Building maintenance and
controls from your energy utility
16. Fuel cells from your energy utility
17. Lighting retrofit and new
construction provided by your
energy utility
18. Power factor correction services
provided by your energy utility
19. Solar and wind power projects
Not at all
Valuable
Not Very
Valuable
Somewhat
Valuable
Very
Valuable
Extremely
Valuable
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
1
1
2
2
3
3
4
4
5
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
2
3
4
5
1
1
1
1
2
2
3
3
4
4
5
5
1
1
2
3
4
5
1
1
2
3
4
5
14. Do you have an electric generator(s) on-site?
1 Yes
2
No (SKIP TO Q.16)
15. What is the size of the largest electric generator you currently have?
1 <10kW
2 10-25KW
3 26-50KW
4 51-100KW
5
over 100kW
15a. How do you use existing generators (e.g., outages, peak demand, self-generation,
other, etc,)?
_____________________________________________________________________________________
_____________________________________________________________________________________
16. Do you plan to purchase an electric generator on in the next two years?
1 Yes
2 No (SKIP TO Q.18)
4
17. What would be the largest electric generator that you expect to purchase?
1 <10kW
2 10-25KW
3 26-50KW
4 51-100KW 5 over 100kW
17a. How would you use these new generators (e.g., outages, peak demand, self-generation,
other, etc,)?
_____________________________________________________________________________________
_____________________________________________________________________________________
18. What would you estimate the cost (in dollars) to be of a 15-minute power interruption to your company at
this site? $__________________
19. How significant would this cost of the 15-minute power interruption be to your business?
2 moderately significant
3 very significant
1 minor
20. Do you currently have an energy management practices plan?
2 No (SKIP TO Q.21)
1 Yes
20a. Briefly describe measures implemented?
_____________________________________________________________________________________
_____________________________________________________________________________________
_____________________________________________________________________________________
20b. Briefly describe measures planned in the next two years (if any)?
_____________________________________________________________________________________
_____________________________________________________________________________________
_____________________________________________________________________________________
21. Are there any other products and services that you would like your energy utility to offer?
1 Yes
2 No (SKIP TO Q.22)
21a. Briefly describe them?
_____________________________________________________________________________________
_____________________________________________________________________________________
_____________________________________________________________________________________
_______________________________________________________________________________________________
5
LIGHTING
22. Please indicate the number of units that you have for each type of light bulbs shown below. (Check
one box for each type)
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.
k.
l.
m.
Incandescent (standard bulbs)
T-12 Fluorescent (standard)
T-12 Fluorescent (VHO or HO 1.5 inch)
Compact Fluorescent (CFL)
T-5 Fluorescent
T-8 Fluorescent
F-40 Fluorescent
F-34 Fluorescent
Metal halide lamps
Halogen lamps
Occupancy sensors
Exit signs
Other
none
0
0
0
0
0
0
0
0
0
0
0
0
0
1-10
1
1
1
1
1
1
1
1
1
1
1
1
1
11-50
2
2
2
2
2
2
2
2
2
2
2
2
2
51-100
3
3
3
3
3
3
3
3
3
3
3
3
3
101-500
4
4
4
4
4
4
4
4
4
4
4
4
4
500+
5
5
5
5
5
5
5
5
5
5
5
5
5
Describe Other: ____________________________________________________________
23. What percentage of your fluorescent lamps have been upgraded to electronic ballasts?
2 20%-40%
3 40%-60%
4 60%-80%
5 80%+
6
1 <20%
Don’t know
24. Indicate the number of exterior lights and controls that you use? (Choose all that apply)
a. No outdoor lighting or do not pay (SKIP TO Q.25)
b. Motion sensors
c. Photo electric eye
d. Timers
e. Manual on/off switches
f. Flood/spot lights
1-2
1
1
1
1
1
3-4
2
2
2
2
2
5-7
3
3
3
3
3
8-10
4
4
4
4
4
11+
5
5
5
5
5
PROCESSING EQUIPMENT
25. Indicate how many of the following kinds of equipment are used at this business site.
(Choose one response for each type and fuel listed)
Equipment Type
1. Kiln
2. Medical equipment
3. Well pump
4. Fans
5. Shop tools
6. Irrigation pump
7. Welding equipment
8. Total motors
9. Motors over 50 horsepower
10. Motors older than 10 years
11. Number of rewound motors
12. Number of variable speed drives
13. Other
1-5
1
1
1
1
1
1
1
1
1
1
1
1
1
a. Electric
6-10
10+
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
1-5
1
1
b. Gas
6-10
2
2
10+
3
3
1
2
3
1
2
3
Describe Other: ____________________________________________________________
6
26. Indicate how many of the following kinds of office equipment are used at this business.
(Choose one response for each type listed)
1-5
1
1
1
1
a. Printers
b. Personal computers
c. Copiers
d. Scanners
6-10
2
2
2
2
11 -25
3
3
3
3
26-50
4
4
4
4
50+
5
5
5
5
27. Do you use steam or hot water for processes other than comfort heating at this site?
1 Yes
2 No (SKIP TO Q.28)
27a. Briefly describe for what purposes used?
_____________________________________________________________________________________
_____________________________________________________________________________________
_____________________________________________________________________________________
28. Do you use refrigeration for processes other than comfort cooling at this site?
1 Yes
2 No (SKIP TO Q.29)
28a. Briefly describe for what purposes used?
_____________________________________________________________________________________
_____________________________________________________________________________________
_____________________________________________________________________________________
OTHER WATER USAGE/CONSERVATION
29. Please indicate total number of toilets, and of those, the total number of low-flow toilets inside your
business. (Choose one for each type)
0
a. Total toilets
b. Total low-flow toilets
0
0
1
1
1
2
2
2
3
3
3
4
4
4
4+
5
5
30. Please indicate the total number of showers and bathtubs inside your business. If the tub has a shower
head, count it also as a shower. (Check one category for each type)
0
a. Total bathtubs
b. Total showers
0
0
1
1
1
2
2
2
3
3
3
4
4
4
4+
5
5
31. Does your business water a lawn area with a garden hose? (If so, choose the frequency in each season)
a. 1 yes
2 no (SKIP TO Q.32)
b. Spring
c. Summer
Rarely
1
1
Sometimes
2
2
Often
3
3
32. Is there a lawn/shrub irrigation system that the business pays for the usage? (If so, choose the level of
usage for each season)
a. 1 yes
2 no (SKIP TO Q.33)
b. Spring
c. Summer
Rarely
1
1
Sometimes
2
2
Often
3
3
7
THE FUTURE
33. Thinking about your use of electricity, natural gas and water at this business site during the next five
years, would you expect usage to remain the same, increase or decrease? (In the table below, check the
appropriate box for each in column (1). If an increase or decrease is checked, estimate the
percentage change in column (2) and the main reason(s) for the change in column (3).
Expected
Change
(1)
a. Electricity Usage
Remain the same
Increase
Decrease
b. Natural Gas Usage
Remain the same
Increase
Decrease
c. Water Usage
Remain the same
Increase
Decrease
Estimate
Percentage
Change
(2)
Main reason(s) for change if increase or decrease
(3)
1
2
3
1
2
3
1
2
3
34. Write any other comments that you would like provide to us in the space below.
________________________________________________________________________________________
________________________________________________________________________________________
_________________________________________________________________________________
_________________________________________________________________________________
That concludes our survey. Thank you for your time and cooperation. Your answers will be very
helpful in our continuing efforts to better serve you. Please return your completed survey in the
postage-paid return envelope or see letter for further instructions.
(OPTIONAL): To help us better serve you, please provide the following optional information:
Name_______________________________________ Title _________________________________________
Company____________________________________ Business Phone:_______________________________
Address: ____________________________________ Business Fax: _________________________________
____________________________________ Email: _______________________________________
____________________________________
8
COMMERCIAL CUSTOMER APPLIANCE/EQUIPMENT SURVEY
Instructions: Thank you for your participation. Please check (9) the appropriate box(s) that
corresponds with your answer or write your response clearly in the space
provided. Your answers will remain strictly confidential.
BUILDING AND FIRMOGRAPHICS
1. Choose the statement that best describes the building where this business is located.
1 One story
2 Two-story
3 Three-story
4 Four+ stories
2. Does this business occupy all or part of the building?
1 All 2
Part
3. Is the space occupied by this business owned, leased or managed by the business?
1 Owned
2 Leased
2
Managed
4. What portion of the year does this business operate?
2 Summer Only
1 Year Round
5. What is the approximate age of the building?
2 1-5 years
1 New (less than one year)
5 16-30 years
6 31-50 years
3
Winter Only 4
3
7
Other seasons
6-10 years
4
Over 50 years
11-15 years
6. What is the approximate square footage of the conditioned space of this business? (Do not include
unconditioned storage/warehouse, attic, or basement space.)
4 5,001-7500
7 25,001-50,000
10 250,001-500,000
1 1,000 or less
5 7,501-10000
8 50,001-100,000
11 500,001-1,000,000
2 1,001-2,500
3 2,501-5,000
6 10,001-25000
9 100,001-250,000
12 1,000,000+
7. How many full and part-time employees work at this location?
4 51-100
7 251-500
1 10 or less
2 11-50
5 101-250
8 501-1000
10
11
1001-5000
5000+
8. During a typical week, indicate the number hours the business is in operation by the time period and day
type below (Fill in the number of hours for each as appropriate)
a
12:00a.m to 8:00a.m
b
8:00am. to 5:00p.m.
c
5:00p.m. to 9:00 p.m.
d
9:00p.m. to 12:00a.m.
1. Weekdays
2. Weekends
9. Does this business have at least one individual whose main job responsibility is energy
management?
1
Yes
2
No
10. Do you have an on-going relationship with the following? (Answer for each)
a. Electrical contractor
b. HVAC contractor
c. Plumbing contractor
Yes
1
1
1
No
2
2
2
11. Does this business respond to peak alerts from RPU?
1 No
2 Yes, reduce use
3
Yes, suspend certain operations
12. Please indicate if you currently participate in the following energy conservation/load management
programs. Also, indicate how valuable they are to your business or would be if you do not currently
participate. (Check if participate and check value level for each program type)
a.
b.
Currently
Participate
1. AC cycling during hottest days
2. Water Heater cycling a.m. or p.m.
3. Time-of-use rates at various time
periods during the day and/or on
weekends
1
1
1
Not at all
Valuable
1
1
1
Not Very
Valuable
2
2
2
Somewhat
Valuable
3
3
3
Very
Valuable
4
4
4
Extremely
Valuable
5
5
5
13. Which one of the following best describes the main business activity at this location? (Check one)
1 Fast Food
2 Restaurant
3 Small Grocery
4 Large Grocery (e.g. Kroger, Safeway)
5 Small Retail
6 Large Retail (e.g., Kmart, Walmart, Best Buy)
8 Trade Services (e.g., auto repair, laundry)
7 Prof. Services (e.g., doctor, lawyer, accountant)
9 Warehousing/storage
10 Communications
12 Construction
11 Transportation
13 Wholesale-Durables
14 Wholesale-Non-durables
16 Real Estate
15 Banking/Finance/Insurance
17 Government
18 Manufacturing (Describe _________________________________________________________)
19 Other (Describe ________________________________________________________________)
HEATING
14. Do you pay to heat this business?
1 Yes
2
No, it is part of the lease
15. What type of heating system do you use to heat this business? (If there is more than one heating
system, describe the system that provides most of the heat as “Main Heating” and the other
system(s) as “Additional Heating”)
a.
b.
Main Heating
Additional Heating
(Check only
(Check all boxes
one box below)
that apply)
1
1. Natural gas central forced air furnace
1
2
2. Natural gas wall/floor heater
2
3. Other natural gas system type
3
3
4. Electric resistance/baseboard/ceiling
4
4
5. Electric air source heat pump
5
5
6. Electric geo-thermal heat pump
6
6
7 Electric central forced air furnace
7
7
8. Electric wall/floor heater
8
8
9. Other electric system type
9
9
10. Central boiler
10
10
11. Woodstove/Fireplace Insert
11
11
12. Fireplace
12
12
13. Propane
13
13
14. Other Fuel
14
14
16. Was the main heating system purchased or replaced in the last seven years?
2 No
1 Yes
3
Don’t know
2
17. How often do you use your additional heating system(s) during the winter months?
4 Often (50-80% of the time)
1 No additional heating
2 Rarely (20% of the time)
5 Always (80% or more)
3 Sometimes (20-50% of the time)
18. How much of your total square footage is heated by your additional heating system?
2 20%-40%
3 40%-60%
4 60%-80%
5 80%+
1 <20%
19. How many portable electric heaters are used?
1 1-5
0 None
2
6-10
3
10 or more
COOLING
Central Air Conditioner
20. What type of central air conditioner does this business have?
0 None (SKIP TO Q.24)
1 Central
2 Central (roof top)
3
Heat pump
21. Do you pay for your central air conditioning?
1 Yes
2 No, it is part of the lease
22. Was the central air conditioning unit purchased or replaced within the last seven years?
1 Yes
2 No
3 Don’t know
23. Please indicate how often the central air conditioner is used during the summer. (Choose one
for each time period)
Never
a. Day
b. Evening
c. Night
1
1
1
Rarely
(20% of time)
2
2
2
Sometimes
(40% of time)
3
3
3
Often
(70% of time)
4
4
4
Room Air Conditioning
24. How many window/wall air conditioners do you use?
0 None (SKIP TO Q.27)
1 1 Unit
2 2 Units
3
Always
5
5
5
3 Units
4
More than 3 units
25. Have you purchased or replaced the window/wall air conditioner that is used most frequently
in the last seven years?
2 No
3 Don’t know
1 Yes
26. Please indicate how often the main room air conditioner is used during the summer. (Choose
one for each time period)
Never
a. Day
b. Evening
c. Night
1
1
1
Rarely
(20% of time)
2
2
2
Sometimes
(40% of time)
3
3
3
Often
(70% of time)
4
4
4
Always
5
5
5
WATER HEATING
27. Do you pay to heat water at this business?
1 Yes
2 No it is included the lease
28. Which of the following best describes the water heater? (Choose one box below)
Electric
Propane/Other fuel
Natural Gas
4 Standard separate tank
7 Any system type
1 Standard separate tank
5 Tank with solar collectors
2 Tank with solar collectors
3 Other system type
6 Instantaneous water heater (at sink)
7 Other system type
3
29. Have you purchased or replaced the water heater in the last seven years?
1 Yes
2 No
3
Don’t know
30. Compared to an average residence, how much hot water would you estimate this business uses at this
location?
1 Less
2 About the same
3 A little more
4 Considerably more
5 Many times more
31. What is the average temperature of the hot water?
1 <140° F)
2 140° F-212° F (boiling)
3
Over 212° F
32. Do you use flow restrictors or energy-saving (low flow) showerheads?
1 Yes, all showers
2 Yes, some showers
3
No
LAUNDRY
Clothes Washer
33. Does this business have a washing machine?
1 Yes, residential type
2 Yes, commercial type
34. How many washing machines?
1
2
3
4
5
6
7
8
3
9
10
No (SKIP TO Q.36)
10+
11
35. How many loads of laundry are washed each week in all machines at this business?
<1
1
2
3 4 5
6 7 8 9 10
10+
0
11
Clothes Drying
36. Does this business have a clothes dryer?
1 Yes, residential type
2 Yes, commercial type
3
No (SKIP TO Q.40)
37. How many dryers?
1
2
3
4
5
6
7
8
9
10
10+
11
38. What is the heating fuel for the dryer(s) at this business?
2 Electricity
1 Natural gas
3
Propane/other fuel
39. Approximately how many loads are dried each week in all dryers at this business?
<1
0
1
2
3
4
5
6
7
8
9
10
10+
11
REFRIGERATORS
40. How many “residential-type” refrigerators do you have plugged in at this business?
0 0 (SKIP TO Q.44)
1 1
2 2
3 3 or more
41. What style best describes the refrigerator(s)? (Check one box for each refrigerator)
Top-Bottom
Side-by-Side
a
Refrigerator 1
1
2
b
Refrigerator 2
1
2
c
Refrigerator 3
1
2
4
42. What size, in cubic feet, best describes the above refrigerator(s)? (Refrigerator information is
usually found on a nameplate just inside the door) (Check one box for each refrigerator)
a
Refrigerator 1
1
2
3
4
5
Very small (under 13 cubic feet)
Small (13-16 cubic feet)
Medium (17-20 cubic feet)
Large (21-23 cubic feet)
Extra Large (over 23 cubic feet)
b
Refrigerator 2
1
2
3
4
5
c
Refrigerator 3
1
2
3
4
5
43. What type of defrost does the above refrigerator(s) have? (Check one box for each refrigerator)
a
b
c
Refrigerator 1 Refrigerator 2 Refrigerator 3
Automatic (frost-free)
1
1
1
Manual
2
2
2
Partial Automatic*
3
3
3
*(These have a frost-free refrigerator and manual defrost freezer)
44. How many units of commercial refrigeration do you have in use?
1 1-5
2 6-10
0 0 (SKIP TO Q.46)
3
10+
45. Please check the percentage of total commercial units purchased in the last seven years.
<20%
1
Purchased in last seven years
20%-40%
2
40%-60%
3
60%-80%
4
80%+
5
STAND-ALONE FREEZERS
46. How many “residential type” stand-alone freezers do you have plugged in at this business? (Do not
include freezers that are part of your refrigerator unit)
0 0 (SKIP TO Q.51)
1 1
2 2 or more
47. What style best describes the freezer(s)? (Check one box for each freezer)
Upright
Chest
a
Freezer 1
1
2
b
Freezer 2
1
2
48. What size, in cubic feet, best describes the above freezer(s)? (Freezer information is
usually found on a nameplate just inside the door) (Check one box for each freezer)
a
b
Freezer 1
Freezer 2
1
Very small (under 10 cubic feet)
1
2
Small (11-15 cubic feet)
2
Medium (16-20 cubic feet)
3
3
4
Large (21-25 cubic feet)
4
Extra Large (over 25 cubic feet)
5
5
Specify size ________________
49. What type of defrost does the above freezer(s) have? (Check one box for each freezer)
Automatic (frost-free)
Manual
a
Freezer 1
1
2
b
Freezer 2
1
2
5
50. Please check each freezer that was purchased in the last seven years.
a
Freezer 1
Purchased in last seven years
1
b
Freezer 2
1
51. How many units of commercial freezers do you have in use?
0 0 (SKIP TO Q.53)
1 1-5
2 6-10
3
10+
52. Please check the percentage of total commercial units purchased in the last seven years.
<20%
1
Purchased in last seven years
20%-40%
2
40%-60%
3
60%-80%
4
80%+
5
FOOD PREPARATION
53. Does this business have any food preparation equipment that is used commercially?
2 No (SKIP TO Q.56)
1 Yes
54. Please indicate the number of units that you have for each type of equipment below. (Check one box for
each type)
a. Combination stove/range: electric and gas
b. Electric stove/range
c. Natural gas stove/range
d. Propane stove/range
e. Other stove/range
f. Microwave oven
g. Fryers
h. Griddles
i. Warmers
j. Dishwasher
k. Commercial dish rinsing unit
l. Commercial food sprayers
none
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5+
6
6
6
6
6
6
6
6
6
6
6
6
55. Please indicate the average number of hours per week that each type of unit is operated (Check one
box for each type)
a. Combination stove/range: electric and gas
b. Electric stove/range
c. Natural gas stove/range
d. Propane stove/range
e. Other stove/range
f. Microwave oven
g. Fryers
h. Griddles
i. Warmers
j. Dishwasher
k. Commercial dish rinsing unit
l. Commercial food sprayers
<20
1
1
1
1
1
1
1
1
1
1
1
1
20-40
2
2
2
2
2
2
2
2
2
2
2
2
40-60
3
3
3
3
3
3
3
3
3
3
3
3
60-80
4
4
4
4
4
4
4
4
4
4
4
4
80+
5
5
5
5
5
5
5
5
5
5
5
5
6
LIGHTING
56. Please indicate the number of units that you have for each type of light bulbs shown below within
your interior business space. (Check one box for each type)
none
0
0
0
0
0
0
0
a. Incandescent (standard bulbs)
b. T-12 Fluorescent (standard)
c. Compact Fluorescent (CFL)
d. T-5 Fluorescent
e. T-8 Fluorescent
f. Exit signs
g. Other
1-10
1
1
1
1
1
1
1
11-50
2
2
2
2
2
2
2
51-100
3
3
3
3
3
3
3
101-500
4
4
4
4
4
4
4
57. What percentage of your fluorescent lamps have been upgraded to electronic ballasts?
1 <20%
2 20%-40%
3 40%-60%
4 60%-80%
5 80%+
6
500+
5
5
5
5
5
5
5
Don’t know
58. Indicated the number of exterior lights and controls do you use? (Choose all that apply)
a. No outdoor lighting or do not pay (SKIP TO Q.59)
1-2
1
1
1
1
1
b. Motion sensors
c. Photo electric eye
d. Timers
e. Manual on/off switches
f. Flood/spot lights
3-4
2
2
2
2
2
5-7
3
3
3
3
3
8-10
4
4
4
4
4
11+
5
5
5
5
5
OTHER WATER USAGE/CONSERVATION
59. Please indicate total number of toilets, and of those, the total number of low-flow toilets inside your
business. (Choose one for each type)
0
a. Total toilets
b. Total low-flow toilets
0
0
1
1
1
2
2
2
3
3
3
4
4
4
4+
5
5
60. Please indicate the total number of showers and bathtubs inside your business. If the tub has a shower
head, count it also as a shower. (Check one category for each type)
0
a. Total bathtubs
b. Total showers
0
0
1
1
1
2
2
2
3
3
3
4
4
4
4+
5
5
61. Does your business water a lawn area with a garden hose? (If so, choose the frequency in each season)
a. 1 yes
2 no (SKIP TO Q.62)
b. Spring
c. Summer
Rarely
1
1
Sometimes
2
2
Often
3
3
62. Is their a lawn/shrub irrigation system that the business pays for the usage? (If so, choose the level of
usage for each season)
a. 1 yes
2 no (SKIP TO Q.63)
b. Spring
c. Summer
Rarely
1
1
Sometimes
2
2
Often
3
3
7
OTHER EQUIPMENT
63. Indicate how many of the following kinds of office equipment are used at this business.
(Choose one response for each type listed)
1-5
1
1
1
1
a. Printers
b. Personal computers
c. Copiers
d. Scanners
6-10
2
2
2
2
10 or more
3
3
3
3
64. Indicate how many of the following kinds of other equipment are used at this business.
(Choose one response for each type listed)
1. Kilns
2. Medical equipment
3. Well pumps
4. Fans
5. Shop tools
6. Irrigation pumps
7. Welding equipment
8. Motors
9. Variable speed drives
10. Other
1-5
1
1
1
1
1
1
1
1
1
1
a. Electric
6-10 10+
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
1-5
1
1
b. Gas
6-10 10+
2
3
2
3
1
2
3
1
2
3
Describe Other: ____________________________________________________________
65. Write any other comments that you would like provide to us in the space below.
________________________________________________________________________________________
________________________________________________________________________________________
_________________________________________________________________________________
_________________________________________________________________________________
That concludes our survey. Thank you for your time and cooperation. Your answers will be very
helpful in our continuing efforts to better serve you. Please return your completed survey in the
enclosed postage-paid envelope.
(OPTIONAL): To help us better serve you, please provide the following optional information:
Name_______________________________________ Title _________________________________________
Company____________________________________ Business Phone:_______________________________
Address: ____________________________________ Business Fax: _________________________________
____________________________________ Email: _______________________________________
____________________________________
8
“Next Level” Triad Report
Version 1.0, 30-Dec-04
Triad Conservation Improvement Programs
Plan for the “Next Level”
Prepared by: JD Crowley, Joe Green, Patty Hanson, Kelly Lady, Mike Smith,
Roger Warehime, Stephanie Yrjo
Page 1 of 8
Version 1.0, 30-Dec-04
Executive Summary
To date, the main thrust of CIP programs has been to use rebates to encourage customers to
purchase more efficient equipment. As high efficiency equipment becomes standard in the
market, the effectiveness of rebate programs declines. The Triad, therefore, seeks to transform
its CIP programs so that they remain effective while at the same time drive toward our vision of
the future utility industry. This vision includes demand/response pricing, distributed generation,
increased renewable energy, and opportunities to provide non-traditional utility services.
The general strategy is to continuously improve the TRIAD CIP programs by focusing on: 1)
cost effectiveness, 2) community involvement and development, 3) effective communications.
Having a written plan assures that all Triad members have the same understanding of the
direction of future programs and provides a framework under which progress can be measured.
Stipulating that the plan be updated and revised at least twice annually acknowledges the fact
that conditions are continually changing and that achieving the “Next Level” is an on-going
process.
The tactical portions of the plan are divided into near term (1-3 months), moderate term (3-6
months) and longer term (6-12 months) plans. There are also sections to capture non-CIP plans,
tabled topics, and topics that were considered but not included in the plan.
The near term tactical plans include launching the Residential/Small Commercial Audit Program
and making the following modifications to the residential Conserve & Save Program:
x Eliminate refrigerator and dishwasher rebates, effective June 30, 2005.
x Eliminate CFL rebates, effective March 31, 2005. Use special promotions to promote
CFLs, rather than an on-going rebate program.
x Eliminate the rebate for 13 SEER air conditioners, effective June 30, 2005.
x Eliminate rebates for 92% efficient furnaces and all water heaters for new
construction, effective June 30, 2005.
Moderate term tactical plans include:
x Builder programs,
x SNAP green-pricing program,
x Commercial & Residential Education through Community Ed,
x A strategy for improved communications,
x Re-evaluation of the Retail Support Coordinator position.
Longer term tactical plans include:
x Improved relationships with and management of trade allies,
x Evaluating evaporative coolers,
x Researching advanced metering & special billing,
x Researching residential demand controllers.
Page 2 of 8
Version 1.0, 30-Dec-04
Introduction
CIP programs to date have focused primarily on achieving energy savings by encouraging the
conversion to more efficient lighting, appliances, and equipment. The chief strategy has been to
reduce market barriers, primarily in the form of a rebate paid to the customer in order to reduce
the premium associated with higher efficiency products.
While these programs have been successful, the Triad believes that the time frame for which
these programs will continue to be effective is limited. In large part due to CIP programs &
government regulations, certain high efficiency equipment has become standard in the market.
With this market transformation is the realization that CIP rebates will be paid to people who
would have purchased the higher efficiency equipment without any incentives (“free riders”);
thus, the program will have spent money without affecting change.
The vision of the future for the utility industry includes demand/response pricing, distributed
generation, increased renewable energy opportunities, and an opportunity to provide additional,
non-traditional services. The Triad’s CIP strategy should be to continually transform the existing
programs and create new programs in order to drive toward this vision of the future.
Such a transformation will not come easily. For one, it will require a cultural shift from
administering programs to developing the skills necessary to create new, innovative ways of
conducting business. Additionally, the Triad will be out ahead of most other utilities in the state
and nation; thus, there will be little opportunity to implement programs that have already been
proven elsewhere.
The purpose of this document is to lay out a general plan for getting to the Next Level. Having a
written plan assures that all Triad members have the same understanding of the direction of
future programs. It also provides a framework under which progress can be measured. It is
intended to be a “living document” and will be updated at least twice annually.
Primary Objective
Transform CIP activities so that they drive toward our vision of the future.
Vision of the Future
The Triad will be nationally recognized for its innovation, customer satisfaction, and leadership
in the areas of demand/response pricing, distributed energy, renewable energy, and energy
related services.
Page 3 of 8
Version 1.0, 30-Dec-04
Strategy
As municipal utilities, our mission is to enrich the quality of life in our communities by
delivering reasonably priced, reliable, safe, customer-focused utility services. Among our
guiding principles are Stewardship and Financial Soundness.
By Stewardship we mean we are committed to protecting the assets and natural resources
entrusted to us, while taking responsibility for educating our communities about the efficient use
of energy and water.
By Financial Soundness we mean we are dedicated to controlling cost and risk, achieving
adequate revenue for future investment, maximizing the utilization of capital, and making
decisions with the long-term financial interests of our communities in mind.
With our mission and guiding principles in mind, our strategy is one of continuously improving
the value of our CIP offerings by focusing on:
x
x
x
Cost Effectiveness
Community Involvement and Development
Effective Communications
Goals
x
x
x
x
x
x
Improve the overall cost-effectiveness of our electric CIP program as measured by the
Elecben model. (Specific numbers to be determined).
Establish baseline cost-effectiveness of our gas CIP programs using Bencost.
Launch at least 3 new CIP programs in 2005. Most likely candidates are:
o Audit Program
o SNAP Program
o Builder Program
Energy Solutions margin of $34,000 on sales of $340,000
Launch Community Ed Programs in all three communities.
Strengthen relationships and/or partnering with other groups such as MMUA, APPA,
SMMPA, and trade allies.
This document provides the overall summary of all plans currently under consideration. Each
specific program will have a detailed plan created before it is approved and put into action.
Specific actions and milestones are tracked on a continuously updated Action Log.
Page 4 of 8
Version 1.0, 30-Dec-04
Near Term Tactical CIP Plans (Jan – March 2005)
x
Residential Conserve and Save
o Dishwasher Rebates: Most dishwashers on the market today are Energy Star.
Rebates will be discontinued effective June 30, 2005
o Refrigerator Rebates: The energy savings between Energy Star and non-Energy
Star models is small. Rebates will be discontinued effective June 30, 2005
o Central Air Conditioners: The minimum SEER manufacturers will be allowed to
produce in 2006 will be 13. We will raise the baseline for energy savings from 10
to 13 effective January 2006. The rebate for 13 SEER will be eliminated,
effective June 30, 2005. The $300 rebate for 14 SEER will continue through
2005. As of January 1 2006, the rebate for 14 SEER will be reduced to $200; the
rebate will be increased by $50 for each additional SEER (example $250 for 15
SEER).
o Geothermal: Comment to be added to rebate application stating that for water-towater GX without ARI approval, data must be provided from the manufacturer at
the ARI test conditions.
o Clothes Washers: No changes in 2005; re-evaluate fall of 2005 for 2006.
o CFL: Eliminate rebates effective March 31, 2005. Will be removed from the
large Conserve & Save Rebate form. CFL promotion after March will be through
various special promotions throughout the rest of the year.
o Furnace Fan Motors: Increase awareness. (Patty)
o Custom Electric: Roger to develop standard formulas for determining rebate
amounts. Formulas will not be published.
o Boilers: No Changes
o Furnaces: Effective June 30, 2005 there will be no rebate for 92% eff. for new
construction. Rebates for retrofit will remain $100 for 92% and $150 for 95%.
Rebate for 94% for new construction will be $50.
o Water Heaters: Effective June 30, 2005 there will be no water heater rebate for
new construction. For retrofit, rebate will remain $75 for .63 EF and greater.
o Custom Gas: Same as custom electric.
o Attic Insulation: Eliminate the requirement that beginning R Value must be R10
or less. Rebate determined by the net R Value added to get to at least R38.
o Load Management Requirement: OPU’s proposal to stipulate on rebate form that
OPU customers need to be participating in load management to receive a rebate
was evaluated and a decision was made to not make this a requirement. Other
means of promotion will be used instead.
x
Residential, Commercial, and Industrial Audit Program
o Greg Earnst will be our primary auditor.
o Carbon Copy Forms will be created for residential audits, so that the report can be
left with the customer when the audit is finished.
o A Triad template has been designed for commercial and industrial audits.
o Residential customers will be charged $25 for an audit. They will receive
approximately $25 worth of materials, or receive a blower test and furnace test.
For an additional $25, they can receive both the materials and the tests.
x
Commercial Rebate Programs
o We will primarily follow SMMPA on changes they make.
Page 5 of 8
Version 1.0, 30-Dec-04
Moderate Term Tactical CIP Plans (April –June 2005)
x
Builder Programs - The plan is for a packaged program that encourages builders to use
energy efficient equipment and practices. May include rebates to builders, but also
information and exposure that may help them market themselves and their homes as
being environmentally responsible. May go as far as achieving Energy Star Home or
HERS ratings.
The target launch date for the program is May 2005. Before the end of 2004, each utility
will meet with builders in their area to hold an informal focus group to determine how the
needs of the builders and the utility can both be met.
RPU to meet with Aquila to see if they will share in the program so that the gas side is
represented in Rochester.
x
SNAP – This is a green-pricing program that encourages the development of small, local
solar-electric electricity through a market based approach. OPU would like to launch by
Earth Day (April 22 2005). There is concern that this may not be sufficient time,
especially at RPU. Depending on the results of the NOD process at RPU, it may be
decided to pilot this program at OPU in 2005, and have RPU and AU follow in 2006.
Another option is to launch in all three cities in October to coincide with the national
Solar Tour.
x
Commercial & Residential Education through Community Ed – The title of the
residential education program is “Home Energy Audits”, and the title of the commercial
program is “Where Do You Use Your Energy?” Carmel will develop the curriculum and
teach the courses. A pilot course is scheduled for 2-Feb-05 in Austin and 9-Feb-05 in
Owatonna. Courses to include a participant survey to gauge success and gather feedback
for future education course.
x
Improved Communication - Comments in customer satisfaction surveys indicate
customers do not feel they are kept well enough advised of our programs. Kelly and Julie
will develop a plan to improve communications. Ideas under consideration include
developing a media plan for newsletters & having some section of the newsletters that are
common to all three utilities. An issue to be addressed for this to be successful is the fact
that AU & OPU publish a monthly newsletter, while RPU’s is quarterly.
Another objective is to determine a method of effectively communicating our DSM
achievements to the communities without inundating them.
x
Retail Support Coordinator – This position was vital when the Conserve & Save
Program was first introduced. Now that the trade allies know about the programs, the
time requirements are not as great and there may be an advantage to handling the
interaction with trade allies by each individual utility.
Related to this is developing a relationship directly with MEEA rather than through
SMMPA. Additionally, a trade ally plan must be developed.
Page 6 of 8
Version 1.0, 30-Dec-04
Longer Term Tactical CIP Plans (June – December 2005)
x
Evaporative Coolers: JD will investigate this technology as an alternative to DX
refrigeration air conditioning. Find where the technology has been proven to work in our
climate.
x
Advanced Metering & Special Billing for Key Accounts: Kelly will research
availability and cost of equipment, software, etc.
x
Residential Demand Controller: Roger will research the cost of the equipment, etc. as
well as try to learn how customers have been enticed to participate in a pilot program.
x
Gas Radiant Garage Heaters: Joe to research and make recommendation for rebate.
x
CSR “Audit-mation” Program:
x
Tankless Water Heaters
x
Air Source Heat Pumps
x
Trade Ally Communication & Yearly Meeting
Non-CIP Tactical Plans
x
x
x
Appliance Service Plan – Explore subcontracting Aquila’s Service Guard program.
Issues to address are competing with local appliance stores. Joe to learn more about
Aquila’s program and determine if OPU or AU management will be concerned with
using Aquila.
Surge Protection – Determine if new technology is available that allows whole house
protection of sensitive appliances such as TV’s and computers. (Needs Owner)
Focus Groups – Will be held in all 3 cities biannually (April & October). Stephanie is
primary champion.
Page 7 of 8
Version 1.0, 30-Dec-04
Tabled Topics (to be considered sometime in the Future)
x
Financing for Commercial Lighting Projects – Greater participation by small
commercial customers could be realized by providing 0% financing to qualifying
businesses in lieu of a rebate. Loans would be structured such that the loan payment
amount is approximately the same as the energy bill savings. The interest being covered
by the utility would be recorded and filed as CIP expense.
Concerns to be addressed include:
o Will SMMPA reimbursements still be available
o Conflict with Energy Solutions financing programs.
o Billing and administration concerns; Mike Smith recommends that this would
better be handled as turnkey projects through Energy Solutions.
x
x
x
x
x
x
Programs targeted specifically at multi-family dwellings.
Rain Harvester
On-site Generation
GIS Maps
Using the return side of the Mayo district heating line for GX
Laundry ozonation for commercial launders.
Topics Considered but not Included in the Plan
x
x
House Doctor - This would have been a method to promote the energy audit program.
One concern raised was that the name would not play well in Rochester which has a large
medical community.
Utility Bill Round-up – It was decided that this program is counter to the Low Income
aspect of our CIP plan in that it pays for energy use rather than promoting the reduction
of energy use.
Page 8 of 8
Task Force Recommendations
Phase II Task Force Meeting
Tuesday, October 26, 2004
12:00pm – 2:00pm
RPU Training Room
Meeting Minutes
I.
Greetings and Introductions
Mary Tompkins, RPU Manager of Customer Service, welcomed the group and
especially thanked the Task Force members for attending.
II.
Summary of End Use Survey and Cost Benefit Analysis
Kiah Harris from Burns & McDonnell explained the outline of the meeting. He will
go through the summary of the End Use Survey and answer questions. Following
his presentation, each Task Force member will have 5 minutes to give their
responses to the seven questions given to them in their packets. Kiah also
explained that the process and future of the Task Force on a going forward basis
is questionable at this point.
Kiah began his presentation with the explanation of appliance and equipment
inventory, or opportunities, in Rochester. One Task Force member expressed his
objection of the term inventory and from here on, the term would be referred to
as opportunities.
A comparison of Residential and Commercial estimated demand and energy
impacts were discussed. On the Residential side, a comparison was made
between the conversion to Energy Star appliances and the conversion to gas
appliances. The Commercial side compared efficiency conversions to those
converted to gas. There was a lot less opportunity on the Commercial side when
converting to gas. Residential showed the opposite with more savings when
converted to gas.
Kiah then reviewed the Benefit/Cost Analysis for Residential and Commercial
while comparing Participant to Societal, or those that don’t participate but are
affected.
Florence Sandok, Task Force member, added that customers were not asked
energy efficiency questions on the Commercial survey. There are other solutions
besides appliances. She gave the example that Mayo has some lights that turn
on when people enter the room and shut off when they exit.
Florence also expressed the idea that global warming may “skew” things – i.e. air
conditioning and natural disasters. Insurance companies are now taking this into
account with increased values of appliances.
Stephanie Yrjo, RPU Commercial Account Representative, further explained that
the Cost/Benefit Analysis took specific motors and looked at the spectrum. We
will look at costs and refine the numbers at a later date.
Keith Butcher, Manager of External Affairs – Center for Energy and Environment,
supported these assumptions.
III.
Sharing of Task Force Ideas and Recommendations
*****
Some questions to consider in anticipation of the last Task Force meeting on October 26,
2004….
1. What pricing conventions could RPU develop to make energy conservation efforts more
effective?
2. What do you think is the largest hindrance to customer participation in programs? What role
could RPU play in removing that hindrance?
3. Rank the importance of RPU's conservation programs (1 being most important, 5 being least
important).
x Pricing signals
______
x Incentives
______
x Education
______
x Promotion
______
x Other (please specify) ______
4. In your opinion, what is the best way for RPU to encourage participation in renewable energy
programs?
x Offer the customer a choice where they pay a premium to purchase renewable energy.
x Subsidize (build into rate structure) some or all of the cost of a renewable program.
5. In your opinion, what is the most effective way for RPU to administer its conservation
programs?
x By customer choice – promoting rebates, special rates, education, etc.
x By building into rates – all customers participate in conservation through the rate structures
and/or required programs.
6. Please suggest any conservation programs not discussed at Task Force meetings that you feel
would be of value for RPU to research.
7. Would you be willing to promote RPU’s programs (e.g., energy efficient lighting for homes)
through community groups or committees with which you are involved?
*****
Task Force Member 1
#1 Dual meters offering – peak vs. non-peak. Energy calculator on website
would be good to have.
#3 Education is important and ongoing. Incentives are a good way to get
people to act.
#5 Customer Choice
#6 Transfer coal on rail vs. trucks
#7 Yes – I would be willing to serve on a community group.
Task Force Member 2
#2 Pre and post-inspections for small dollar amount rebates make the biggest
hindrances – the hassle factor.
#4 Encourage renewable energy participation – the big one is wind.
Incentives will come naturally for wind as turbines are built and the cost drops
below other power.
#5 Customer Choice.
#6 Air handling units waste energy. Do commissioning. Vending misers are a
good savings.
Task Force Member 3
#1 Money saving on bills. Anything that can be credited on a bill (example:
timers for A/C).
#2 The biggest hindrance is cutting out the UPC symbol for the rebate and
mailing it in. Instead, just bring in a coupon. Make things easier.
#3 Education. Start with educating the elementary kids and they will educate
the parents. Kids put great pressure on parents. Incentives is number 2 and
promotion is number 3.
#4 Customer Choice.
#5 Customer Choice.
#6 Onsite exchange of working light bulbs for CFL’s. This would be very little
hassle. Turn off the lights! This is especially important in big buildings. Include
store coupons in bills that customers could take with them to purchase CFL’s
and other energy efficient products. Lobby Congress for tax credits to
providers of alternative energy choices. In lieu of off-peak storage capability
and technology, manufacture hydrogen and oxygen for on-peak demand.
Task Force Member 4
This Task Force member would have liked to be involved from the
beginning and been able to set the number of meetings. She also mentioned
she had good ideas on how to structure the group and whether we want to
continue its existence.
#1 Price incentives - Schedule rates on amounts of use and time of use.
#2 People don’t know about the reward. Example: Paul Wellstone
commercial. Do fun ads like his. Do more education and advertising.
#4 Subsidize the renewable rate program. This should include the WHOLE
cost including health costs and externalities like pollution, etc. Penalize those
not participating. Education is the key.
#5 Build into rates. All customers participate in conservation through the rate
structures and/or required programs. Penalize those customers that don’t
participate.
#6 She wants to see more task forces.
How much has RPU paid consultants? Should hire a knowledgeable
energy consultant to design the best program for a customized conservation
program for the Rochester community. Teach Community Ed, tree planting,
installing wind towers, student education programs, partner with builders, and
install efficient home lighting systems.
#7 She would be willing to promote programs. She wants to be involved in
the fine tuning. Keep it simple. Continue the process as we have just begun.
Rebates for buying compact fluorescent light bulbs should be paid out where
the light bulb is bought.
ADDITIONAL THOUGHTS: Send staff to green festival conferences. Have a
tour of energy efficient homes in Rochester. City – wide contests for best
energy efficient ideas with energy efficient award.
Task Force Member 5
This task force member explained that the rebates did not incent him to buy
certain appliances. What is the motivation? Why buy a $700 refrigerator if you
don’t have $700?
RPU bill – Why is it that way? Why is it as high as it is? Can someone come
to the house to say why it is so high? Be more proactive. Does RPU have a
home auditor? (Stephanie confirmed that RPU can do this for a fee of
approximately $50). $50 fee would be a roadblock in having that done.
Task Force Member 6
He sees comparable things. To capture the life cycle, it would take 20 to 25
years.
Partner with vendors for instant rebates.
Partner with builders and building/mechanical codes. Example is gas piping –
the cost is high to put that in for a range.
Cost to conversion – minimum vs. maximum.
Pay 100% of difference or change the codes.
#3 Incentives is number 1. 70% of those that get a high efficiency furnace are
free riders. The builder would have put them in anyway. The builder puts in a
92% efficient furnace to meet code and the customer gets the rebate.
Promotions is number 2. This includes education. Educate the kids and
start young. Discontinue the bill inserts – most are discarded without being
read.
#4 Customer Choice. Right now, it does not make financial sense.
#5 Build into the rates. Build the infrastructure into the rates.
#6 Work your partnerships. Work with vendor installers including appliance
manufacturers.
Distributive generation. Larger companies are doing this out west. Partner
with Mayo and IBM to do this. Incentives for this.
Energy Committee for Rochester Schools – Rory is involved with this
group. The idea is to identify where you are wasting money. Who will manage
the lights, remove refrigerators and heaters out of the classrooms, and
removal of other teacher conveniences. Help facilities manage their energy
and identify opportunities with an “audit for energy conservation”.
Develop software program for auditing?
#7 Yes – he is willing to promote RPU programs.
Task Force Member 7
#1 Variable rates for peak – dual meters.
#2 Largest hindrance is cost effectiveness
#3 Incentives
#4 Subsidize/build into rates.
#5 Build into the rates – it will be easier.
#6 Night rates
Even out peak demand – energy storage.
How will we find more energy? Any power Ok – even nuclear which has
no pollution and is cheap.
#7 Yes-if cost effective.
Task Force Member 8
#1 How much you use and when.
#2 The biggest hindrance is the lack of incentive. Change the rate structure to
make customers more aware/ pay more attention. Residential participation is
better than the commercial side. Put a greater emphasis on the commercial
customer, where there is more potential for energy savings.
#3
1. Price
2. Incentives
3. Education/Promotion (Should be together)
#4 Wind is getting more competitive. Subsidize some or all of the cost. We
need availability of transmission facilities for wind to get to the grid.
#5 The most effective way is to build into the rates. He doesn’t want to
subsidize someone else’s power.
#6 Ground source heat pumps – work with developers to put in a community
look. This is cheaper that each putting their own in. Partner with sewage
treatment for heating. Educate sales people on advantages like energy
savings of upgrading appliances.
#7 Yes, he is willing to promote RPU programs.
Task Force Member 9
The only complaint that others had about RPU was the severe tree trimming
on the boulevard.
#1 According to this Task Force member, Big G is not supporting the
purchase of the Energy Star ranges.
Did not like the hydrant fee.
Otherwise no complaints – RPU is #1.
#7 Yes, she is willing to promote RPU programs.
IV.
x
x
x
x
x
x
x
x
x
x
Wrap Up
Florence suggested a poll of those who wanted to continue on the task
force. Mary Tompkins took the poll and the majority (7-1) wanted to
continue.
Task force members would have liked to decide how many meetings and
how they would have been structured, ongoing or not. They wanted to be
involved from the beginning and to have more involvement.
Florence informed the group that this is a public utility and if the
community wants a task force, they should be able to have one.
Kiah intercepted that everyone has a representative on the Board.
Rory also supported this idea that RPU should make the decisions
because of the level of expertise.
Florence would still like to collaborate as partners.
Bill explained that he had been involved with SLP pollution discussions
and that RPU has become more open to community groups. He thinks we
should keep on with the community task force. He is pleased with the
forthcoming of RPU and the opportunity to get involved. Both would
benefit from an ongoing citizens committee. He also suggested having
terms assigned so others can get involved. Bill said this would not be
unique in a city – other city and county departments have citizen task
forces.
Mary Tompkins confirmed that she would bring all this information back for
discussion as the majority is interested in further participation of “citizen’s
advisory groups”.
Kiah summarized the process of RPU at this point. The suggestions will
be put into a financial model to see the impact on the rates. This will be
done over the next month or so.
Stephanie inserted the fact that RPU is looking at conservation programs
with Owatonna and Austin. RPU will definitely take the suggestions into
account.
x
x
x
Mary also informed the group that next year RPU is looking at doing prepayment metering. This would be able to track usage and has been very
successful in other cities.
Kiah reminded the task force members to also send us their comments
after the meeting too.
Larry Koshire, RPU General Manager, closed the meeting thanking
everyone for their participation.
Flipchart notes:
x Straw Pole: Majority interested in further participation. Citizen Advisory
Groups.
x TOU rates
x Rebates – hassle free
x Customer choice – flexibility
Residential & Commercial End Use Information
Estimated Residential Demand Savings
Note: RPU summer peak is about 4pm
Air conditioner demand going to SEER 12
MWh saved =
7,087
Assume two thirds of energy used in July and August
Energy for u
J ly or August peak= 2338.86312 MWh per month
Assume half of the energy saved during 8 hours
Energy saved during 8 hours = 1169.43156 MWh
Energy saved per hour per day
4.71544984 MWh
Demand on peak =
4.71544984 MW
Refrigerators
MWh saved =
1,252
Saved per day=
3
Assume half of energy used during 8 hours=
Energy per hour
Average Demand on peak
Demand reductions per ac
are .6 to 1.2kW depending
on if the same size or
reduced size is installed.
Based on the diversity
on the RPU system, the
average natural demand
reduction would be .2 to .4kW.
1.714685
0.214336 MWh
0.214336 MW
Freezers
MWh saved=
98
Assume averaged across the day
Ave MW=
0.011242 MW
Compact Flourescent
Energy savings based on 4 hours per day
Not coincident with RPU peak, therefore, no demand savings
Washing Machine
Assume same diversity as refrigerators
MWh saved =
13,973
Saved per day=
38.28084 MWh
Assume half of energy used during 8 hours=
Energy per hour
Average Demand on peak
19.14042
2.392552 MWh
2.392552 MW
Dishwasher
Not coincident with RPU peak
Water Heater
MWh used=
21,048
Average per day=
57.6661 MWh
Majority of energy is used in morning between 5 to 7 and evening from 7 to 10
Assume half is during this period
Average for rest of hours per hour =
1.517529 MW
Dryer
Assume same use as washing machine
MWh used=
30,190
Used per day=
82.71312 MWh
Half of energy in 8 hour period
41.3565616
Energy per hour
5.16957021 MWh
Ave demand on peak
5.16957021 MW
Blower motor
From Ben cost study Average energy reduction =
Average demand reduction =
Number of gas furnaces =
Number of electric furnaces =
Max Energy savings MWh
570 kWh
0.19 kW
35867
552
36419
20758.83
Summary demand reductions due to efficiencies
Demand Reductions (MW
Appliance
Maximum
Air Conditioners
4.7
Rerigerators
0.22
Freezers
0.011
Washing Machine
2.35
7.281
Conversion to gas appliances
Water Heaters
1.52
Dryers
5.2
6.72
Total
14.001
Load Management
Residential
Total Central AC units
36064
Current Partners
8461
Reductions per AC kW
0.98
Estimated current reductions kW
8292
Estimated maximum reductions kW
35343
Estimated max red when SEER 12
25245
(assumes .7kW per point)
Total Water Heaters
Current Partners
Reductions per AC kW
0.68
Estimated current reductions kW
4375
905
615
Commercial
1825
568
20484
2618
13176
1231
15214
38705
9792
36419
788
3035
30342
585
4375
30704
Energy Star or other EfficiencyConversions
Central Air more than
5 yrs
Room Air more than
5 yrs
Refrigerator more than
5 yrs
Freezer more than
5 yrs
No Compact FL
Washing Machine
Dishwasher-heated drying
HVAC Blower
Other Options
Electric heat-Main
Electric auxiliary heat
Dryer
Spa/Hot tub
Water Heater
Range/Oven
Appliance summary
Estimated Residential Energy Savings
(No. of customers)
(No. of customers)
(No. of customers)
(No. of customers)
(No. of customers)
(No. of customers)
(No. of customers)
(No. of units)
(No. of units)
(No. of units)
(No. of customers)
(No. of customers)
(No. of customers)
(No. of units)
995
1680
4811
256
30,190
983
21,048
7,860
Estimated
Energy Savings
Each (kWh)
Total (MWh)
346
7,087
58
152
95
1,252
80
98
124
1,887
361
13,973
103
1,009
570
20,759
Total Usage
Each (kWh)
Total (MWh)
43174
34,021
Cornhusker Power/Neb web sites
Cornhusker Power/Neb web sites
Cornhusker Power/Neb web sites
Cornhusker Power/Neb web sites
energyguide.com web site
calculator
calculator
calculator
calculator
calculator
calculator Includes dryer savings
calculator
Bencost study
Source for savings
Maximum
Not on summer peak
Not on summer peak
5.2
minimal demand
1.5
Not applicable to DSM
Estimated Demand Savings
Coincident with RPU
MW
4.7
0.1
0.2
0.0
0.0
2.4
0.0
6.9 Ben cost assumed .19kW per mot
Commercial Demand Side Management Energy Reduction Estimates
Rochester Public Utilities
Assumptions
There are a number of assumptions included in the DSM measure energy reduction
estimates for commercial customers. These include:
x The survey population of 2,145 customers consists of small commercial
properties. Most would have building areas of approximately 5,000 square feet or
less. A larger customer in this group might include a 50,000 square office
building.
x RPU commercial customers account for 50% of the SMMPA commercial
customers’ energy use.
x RPU commercial customers account for 50% of the SMMPA commercial
customers’ floor space (i.e., 50% of 67,210,000 sqft or 33,605,000 sqft).
x Use data from the US Department of Energy – 2004 Building Energy Databook
when needed.
x The DSM measures will have 100% penetration. In other words all customers
that are candidates for a given DSM measure will implement the measure.
References
References and calculation tools used include:
x End-use Survey of RPU Commercial Customers: A survey sent to 2,145 of
RPU’s commercial customers. Used to determine quantities customers and
appliances.
x eQUEST: A computer simulation program that is a full implementation of the
widely recognized DOE 2.2 calculation engine. It can perform hourly
calculations for an entire year and incorporates local weather data.
x US Department of Energy – 2004 Buildings Energy Databook:. This reference
includes over 100 pages of data tables dealing directly with buildings and their
energy use.
x Energy Star homepage: Web site with a variety of reference material and
calculation tools for various technologies. Estimates that involved use of these
calculation tools includes room air conditioners, freezers, washing machines,
dishwashers, computers, printers, and copiers.
x SMMPA Integrated Resource Plan 2003-2018: In particular Table VII-8,
“SMMPA Sales Profile”, which has an end-use breakdown of electricity use for
commercial customers. The metric used is the Energy Use Indices (EUI) which
has the units of kWh/yr/sqft.
Approach
The approach used to determine the potential energy savings for RPU’s commercial
customers included three basic steps. These include:
1. Identify the appliances and energy using systems that account for the majority of
overall electric consumption.
2. Use the end-use survey to determine the number of customers, or quantity of
energy using devices identified in step 1. In some cases the DOE – 2004
Buildings Energy Databook.
3. Use engineering calculations to determine the energy savings for the devices and
quantities identified in steps 1 and 2 respectively.
1) Selecting Appliances and Energy Using Systems
The appliances and systems in the commercial customer electrical energy reduction
estimates include:
x Central air Conditioning (AC) units more than 7 years old
x Room AC units more than 7 years old
x Refrigerators more than 7 years old
x Freezers more than 7 years old
x Use of incandescent lamps instead of compact fluorescents
x Washing machines
x Dishwashers with heated drying
x Non-electronic ballast fluorescent light fixtures
x Variable speed drives (VSD) on 3 HP AC unit fans
x Computers
x Printers
x Copiers
In addition estimates were provided of the total consumption of a number of electric
appliances and systems that could be switched to natural gas. This group includes:
x Electric heat
x Dryers
x Range or oven
x Water heater
2) Determining Quantities
The end-use survey was the main source for determining the number of customers or
quantity of appliances and systems. In most cases the number was derived my
multiplying the percentage of positive respondents by the sample population size of 2,145
customers. Assumptions were used when the number could not be directly found. For
instance, an average of 6 AC units was used if the customer answered positive to the item
“more than 3 room AC units”. In other cases the survey questions asked if the customer
had one or more units of an item. Examples of assumptions used in these cases are 10
computers per customer, 3 printers per customer and 2 copiers per customer. The
quantities used for the estimates can be found in Table ES-1.
3) Engineering Calculations
Engineering calculations included the use of hourly computer simulation programs,
Energy Star EXCEL calculation templates, and device specific calculations. Examples of
this work follow.
Central Air Conditioning Units
This estimate is based on the results of computer energy models using the eQUEST
program. The models included two office buildings with areas of 5,000 and 45,000
square feet, and two retail buildings with areas of 5,000 and 45,000 square feet. There
were a total of eight simulations. The first simulation for each model had an AC system
having an EER of 8.5, then with an EER
of 9.7. An EER of 8.5 is typical for an
older unit, while the EER of 9.7
represents a new, high efficiency unit.
The results were used to determine the
percent reduction in cooling power
consumption expected with the newer
units.
Results from the end-use survey
indicate that 1,825 of the customer
population have central AC systems
and that 935 have been replaced within
the last 7 years. This leaves 936 customers (or 43.7% of the total population) with units
older than 7 years. If 43.7% of the population can reduce their cooling power
consumption by 14%, then the total reduction across the entire population is 6.11% (i.e.,
43.7% * 14%).
Central AC Savings Estimate
eQUEST (DOE 2.2) simulation output for generic facilties in Rochester, MN
Large Office
Small Office
Small Retail
Large Retail
EER
~ 45,000 sqft
~ 5000 sq ft
~ 5000 sq ft
~ 45,000 sqft
Base Cool (kWh)
48,230
95,630
6,840
12,980
8.5
Retrofit Cool (kWh)
41,540
82,370
5,800
11,180
9.7
Difference in Cool
6,690
13,260
1,040
1,800
% Difference in Cool
13.9%
13.9%
15.2%
13.9%
assume average reduction of 14% of cooling use by replacing older central AC systems
Table VII-8 of the SMMPA Integrated Resource Plan 2003-2018 (IRP) indicates that the
EUI for cooling for commercial customers is 1.8 kWh/sqft/year for the entire population
of 67,210,000 square feet. Assuming a 6.11% reduction in this EUI, and assuming RPU
represents 50% of the SMMPA population
Savings (kWh/yr) = 50% * 67,210,000 sqft * 1.8 kWh/sqft/yr * 6.1%
= 3,697,016 kWh/yr
Savings per customer (kWh/yr/customer) = 3,697,016 kWh/yr / 936 customers
= 3,948 kWh/yr/customer
Commercial lighting
References used for lighting estimates include Table VII-8 of the SMMPA IRP and tables
from the DOE 2004 Buildings Energy Databook. These include Table 5.9.1, “2001 Total
Lighting Technology Electricity Consumption by Sector” and Table 5.9.10, “Typical
Efficacies and Lifetime of Lamps”.
Table VII-8 lists an EUI of 4.2 kWh/yr/sqft for SMMPA commercial customers. The
overall distribution of lighting energy use for buildings in the United States is listed in
Table 5.9.1. The following table includes the commercial sector portion of Table 5.9.1.
The right hand column lists the estimated breakdown of the SMMPA lighting EUI based
on these percentages (i.e., Est EUI for incandescent = 26% * 4.2 kWh/yr/sqft = 1.11
kWh/yr/sqft).
Excerpt from Table 5.9.1
Commercial Sector
Lighting Type
Incandescent
Standard
Halogen
Fluorescent
T5
T8
T12
Compact
Miscellaneous
HID
Mercury Vapor
Metal Halide
HP Sodium
LP Sodium
Total
Estimated
Breakdown
Percent
(10^9
of RPU
kWh/year)
of Use
Lighting
EUI
103
21
26%
5%
1.11
0.23
0
50
157
13
0
0%
13%
40%
3%
0%
0.00
0.53
1.69
0.14
0.00
7
34
6
0
391
2%
9%
1%
0%
100%
0.07
0.36
0.06
0.00
4.20
Table 5.9.10 lists the efficacy for various lighting technologies. Efficacy is the ratio of
light output to electric energy input (lumens/watt). A post retrofit EUI for a given
lighting type can be estimated by taking the product of the existing EUI and the ratio of
the old to new efficacy.
EUIretrofit = EUIexisting * (old efficacy/retrofit efficacy)
Replacing incandescent lamps with compact fluorescents gives the following results.
EUIcfl = (1.11 kWh/yr/sqft) * [(15 lumens/watt)/(65 lumens/watt)]
= 0.26 kWh/yr/sqft
There were 1,386 respondents with incandescent lights. The savings resulting from
retrofitting incandescent to compact fluorescents is calculated as follows:
Savings (kWh) = (cust. w/ incan)/(population) * area * (EUIexisting – EUIretrofit) * %area
= (1,386/2145) * (33,605,000 sqft) * [(1.1 – 0.26) kWh/yr/sqft] * 30%
= 5,565,000 kWh/yr
Savings per customer (kWh/cust) = Savings / Cust. with incan.
= (5,565,000 kWh/yr) / (1,386 customers)
= 4,015 kWh/yr
Excerpt from Table 5.9.10
Typical Efficacies and Lifetimes of Lamps
Current Technology
Incandescent
Torchiere Halogen
Tungsten-Halogen
Mercury Vapor
Fluorescent
Compact Fluorescent
Metal-Halide
High-Pressure Sodium
Low-Pressure Sodium
Efficacy
(lumens/watt)
Typical Rated
Lifetime (hours)
6-24
2-14
18-33
25-50
50-100
50-80
50-115
40-140
120-180
750-2,000
2,000
2,000-4,000
24,000+
7,500-24,000
10,000-20,000
6,000-20,000
16,000-24,000
12,000-18,000
There were 1,587 customers with older fluorescent fixtures. Savings by retrofitting these
fixtures with T-8 lamps and electronic ballasts is found in similar manner using the
existing EUI of 1.69 kWh/yr/sqft, an existing efficacy of 55 lumens/watt and a retrofit
efficacy of 85 lumens/watt and lighting area of just over 87%. The results follow:
Savings = 15,522,000 kWh/yr
Savings per customer = 9,489 kWh/yr/customer
Variable Speed Drives on 3 HP AC Unit Fans
There will be a variety of AC unit fans sizes in the commercial population. This analysis
assumes an average size of 3 HP. The amount of energy consumed by a motor is a
function of the loading of the motor and the run hours. A 3 HP motor, at a 70% motor
load and running 24 hours a day would consume 13,723 kWh/year.
Energy used (kWh/yr) = HP * .746 kW/HP * % load * run time (hrs/yr)
= (3 HP) * (.746 kW/HP) * (70%) * (8,760 hrs/yr)
= 13,723 kWh/yr
A variable speed drive (VSD) can easily reduce the power consumption of an AC unit fan
by 40%. The annual energy savings by installing a VSD on these fans is 5,489 kWh/yr.
Savings using VSD (kWh/yr) = Energy used (kWh/yr) * % reduction using VSD
= (13,723 kWh/yr) * (40%)
= 5,489 kWh/yr
Statistical Relationship Photovoltaic Generation & Electric Utility
Demand in Minnesota (1996 – 2002)
STATISTICAL RELATIONSHIP BETWEEN PHOTOVOLTAIC GENERATION AND
ELECTRIC UTILITY DEMAND IN MINNESOTA (1996-2002)
Mike Taylor
Minnesota Department of Commerce State Energy Office
85 7th Place East, Suite 500
Saint Paul, MN 55101
[email protected]
ABSTRACT
Photovoltaics have an intuitively positive relationship with
summer peak electricity demand periods. This study
compared photovoltaic output with electric utility demand
under various scenarios to determine photovoltaic capacity
performance during periods of high electricity demand and
certain months and times of day.
Three fixed-tilt and fixed-azimuth photovoltaic installations
in the Minneapolis-St. Paul metropolitan area (Minnesota)
were analyzed, comparing their electricity output’s
relationship to Xcel Energy’s electrical demand from 1996
to 2002 using hourly output and coincident utility load data.
Using electric utility accreditation standards, two of the sites
had capacity values ranging from 24% to 44% from June to
September in the late afternoon, while the third site was
lower due to shading of the panels. When the data were
filtered for electrical demand exceeding 99% of annual
peak, one of the sites produced at 62% of capacity, while the
other two were less, again, likely due to shading.
1.
Fig. 1: Minnetonka (MTK) site picture (photo: SEPA).
Fig. 2: Rosemount (RMT) site picture (photo: SEPA).
PHOTOVOLTAIC INSTALLATIONS
1.1 Site Descriptions
Seventeen two to three kilowatt (kW) photovoltaic (PV)
systems were installed in 1996 under Xcel Energy’s (then
Northern States Power) Solar Advantage Program in
conjunction with the Solar Electric Power Association
(SEPA). Three of the systems, located in Minnetonka
(MTK), Rosemount (RMT), and White Bear Lake (WBL),
were outfitted with data logging equipment (Figures 1, 2,
and 3).
Fig. 3: White Bear Lake (WBL) site picture (photo: SEPA).
All three sites used ASE 50-volt, 285 watt panels and had
fixed-tilt angles flush with the roof (Table 1). A solar
pathfinder diagram was not available for the sites to
determine the exact amount of shading. Elevation from
ground level was not calculated but a comparative ranking
would place them in order of lowest to highest as WBL,
MTK, and RMT. Subjectively, the amount of shading from
lowest to highest was RMT, WBL, and MTK.
TABLE 1: INSTALLATION SPECIFICATIONS
Site
Azimuth
Tilt
Inverter (kW)
MTK
179o
39.8o
Trace 4.0
RMT
180o
33.7o
Omnion 2.5
22.6o
Trace 4.0
WBL
180o
Source: Solar Electric Power Association, 2003 (1) (2).
1.2 Data Description
Averaged hourly Xcel Energy system electric load data for
Minnesota was obtained from the Mid-Continent Area
Power Pool (MAPP) and converted to a percentage of peak
for each year (demand data for each year divided by peak
demand number for that particular year) (3).
Fifteen minute photovoltaic site information was obtained
from the SEPA website and data were filtered for hours
corresponding to the Xcel Energy demand data by hour to
provide a “snapshot” of photovoltaic performance from
August 1996 to October 2002, sans September 2002, for
which data was unavailable (1). Data was only available for
the RMT site from August 1996 to December 2000 (2).
1.3 Calculating Total System Ratings
The direct current (DC) panel rating using standard test
conditions (STC) was 2.85 kW for MTK and WBL and 2.28
kW for RMT. The peak DC output seen over the six year
period for MTK was 2.68 kW and for WBL was 2.56 kW
(RMT unavailable) or 6% and 10% less than STC rating
respectively. Irradiance did exceed STC of 1000 watts/m2
during the studied time period.
While photovoltaic panels themselves have a DC rating
based on an industry accepted standard, photovoltaic
systems do not have one for alternating-current (AC) rating.
There are various methods for calculating an AC system
rating, including the PVUSA Test Condition (PTC) and the
Solar Electric Power Association (SEPA) derating methods
(4) (5).
Under the PTC method, the combined DC rating of the solar
panels in an array is derated for the normal operating
conditions, as well as efficiency losses in the wiring and the
inverter. Under the SEPA method, an AC rating is
calculated using a regression analysis at modified PTC
conditions. The PTC and SEPA methods were low in five
of six cases when actual peak AC data was examined (Table
2). The PTC calculation was the closest to the actual peak
AC values recorded. However, only roughly 1% of the data
exceeded the SEPA rating.
TABLE 2: SYSTEM AC RATINGS (kW)
Site
DC
Peak
PTC
SEPA
Rating
AC
Rating
Rating
MTK
2.85
2.49
2.40
2.10
RMT
2.28
2.08
1.90
1.80
WBL
2.85
2.36
2.40
2.10
Determining the appropriate AC capacity is important in
calculating the percentage of peak capacity. Dividing a 1.5
kW output during a peak demand period by 2.49 kW results
in 60% of peak rating. Dividing it by 2.10 kW results in
71% of peak rating. The percentages, although in-exact,
provide an easy to read format.
Unless noted, in the interest of a conservative analysis, the
actual peak exhibited was used to determine the percentage
of peak. For reference, the use of the PTC or SEPA ratings
would increase the percentages roughly 3% to 10%.
2.
PHOTOVOLTAIC PERFORMANCE
2.1 Average Annual Electricity Generation
The sites generated varying amounts of electricity in total
over the study period and on an annual basis, but RMT was
0.57 kW (DC rating) smaller than MTK and WBL and had
two less years of data. When the electricity generation is
standardized on the DC system rating, RMT generated
1,042 kWh per DC kW, with MTK and WBL generating 3%
and 16% less respectively (Table 3). When standardized,
based on the peak AC current measured during the study
period, WBL was again lower than MTK and RMT.
TABLE 3: ANNUAL ELECTRICITY GENERATION
Site
Total
Annual
DC Annual
AC Annual
(kWh) (kWh/yr) (kWh/kW/yr) (kWh/kW/yr)
MTK
17,800
2,892
1,015
1,161
RMT
10,501
2,376
1,042
1,142
WBL
15,468
2,508
880
1,062
A previous study by the author calculated that 3% of
electricity generation was compromised by snow loading on
the WBL site, which has the lowest tilt angle of the three
sites, and did not as readily shed snow (6). Site visits on
March 8, 2001 showed the WBL site with snow on much of
the roof and panels and the MTK site completely free of
snow (Figures 4 and 5).
Fig. 4: White Bear Lake (WBL) site on March 8, 2001.
The peak demand day for 2000 occurred on August 15
around 5 pm (Figure 7). Demand exceeded 95% of peak
from 12 pm to 9 pm, a shift toward the evening that would
tend to decrease the relationship between photovoltaic
generation and demand. However, the photovoltaic sites did
not exhibit a bell curve, as clouds affected MTK and RMT
production during the noon hour. No AC electricity output
was recorded for the WBL site, which was either not
generating, the data logging equipment was malfunctioning,
or both. The WBL site was recording erratic solar
irradiance, indicating a data collection problem.
100%
% peak
75%
Fig. 5: Minnetonka (MTK) site on March 8, 2001.
50%
Demand
MTK
RMT
25%
2.2 Visual Relationship to Electricity Demand
0%
The data can be looked at visually to provide a picture of the
photovoltaic and electric demand relationship. The two
peak demand days for 1999 and 2000 were selected to
illustrate a sunny and a cloudy day.
The peak demand day for 1999 occurred on July 29 and the
photovoltaic production was continuous and uninterrupted
(Figure 6). MTK, RMT, and WBL peaked around noon,
while the peak demand for the year occurred around 4 pm.
Demand exceeded 95% of that year’s peak from 10 am to 7
pm, so the sites’ electricity production was valuable the
majority of the day.
100%
% peak
75%
50%
Demand
MTK
RMT
WBL
25%
0%
0
4
8
12
hour
16
20
Fig. 6: Photovoltaic production and Xcel Energy electric
demand on July 29, 1999.
0
4
8
12
16
20
hour
Fig. 7: Photovoltaic production and Xcel Energy electric
demand on August 15, 2000.
These two scenarios are diametric snapshots of how
photovoltaic production and electric demand interact. The
next section calculates the statistical relationship over longer
time periods.
2.3 Statistical Relationship to Electricity Demand
The statistical relationship between photovoltaic generation
and electric demand can be studied under various scenarios
to determine photovoltaic capacity performance during
periods of high electricity demand and certain months and
times of day.
The photovoltaic systems have azimuths facing due south,
which optimizes annual electricity production. The WBL
site has the lowest tilt angle of the three sites, in theory,
optimizing it for summer electricity production, when the
sun is higher in the sky. Xcel Energy’s annual peak demand
hour typically occurs in July around 4 pm so it is not
expected that these sites are sited for optimal performance in
relationship to electric demand. The systems’ peak capacity
performance during high demand periods could be increased
if they were on active tracking mechanisms or if the system
azimuths were directed more westerly. The latter case
would decrease overall annual electricity production
however.
2.3.1 General Capacity Performance
During daylight hours the systems’ performance was 7% to
12% of peak capacity, which increased during Xcel
Energy’s general summer peak demand of June to
September from 9 am to 9 pm, to 19% to 32% of peak
(Table 5) (7). As would be expected, the noon hour window
of 11 am to 1 pm from June to August exhibited very high
peak percentages of 65% to 69%. All three sites performed
very similarly during the noon hour summer analysis,
indicating a robust data set across the three sites. When the
data were filtered for a typical afternoon electric utility
demand peak of June to August at 4 pm, the percent of peak
ranged from 18% to 44%.
TABLE 4: PHOTOVOLTAIC PERFORMANCE DURING
VARIOUS PHYSICAL AND TIME SCENARIOS (KW)
Site
Daylight
Jun-Sep,
Jun-Aug,
Jun-Aug,
hours
9am-9pm 11am-1pm
4 pm
MTK
0.22 kW
0.48 kW
1.65 kW
0.44 kW
RMT
0.25 kW
0.66 kW
1.43 kW
0.88 kW
WBL
0.17 kW
0.69 kW
1.52 kW
1.05 kW
TABLE 5: PHOTOVOLTAIC PERFORMANCE DURING
VARIOUS PHYSICAL AND TIME SCENARIOS (%)
Site
Daylight
Jun-Sep,
Jun-Aug,
Jun-Aug,
hours
9am-9pm 11am-1pm
4pm
MTK
9%
19%
66%
18%
RMT
12%
32%
69%
42%
WBL
7%
29%
65%
44%
The MTK site dropped off appreciably during the June to
August at 4 pm analysis, which may be indicative of late
afternoon shading of the panels.
2.3.2 MAPP Capacity Performance
The MAPP organization accredits the rated capacity of
various electricity generating technologies, including
renewable technologies (8). Electric utilities need to have
enough generating capacity to meet their anticipated
demand each year and the sum of all of their purchased and
owned capacity is counted toward this requirement.
Firm capacity generators, such as a natural gas power plant,
have accredited capacities near their nameplate capacity.
Renewable energy technologies, being variable in their
output, have a specific MAPP protocol that involves
calculating the median value of the generating technology’s
performance over a historical 4-hour peak electrical demand
“window” by month for a particular electric utility over a
ten year period. For example, Xcel Energy’s historical peak
demand window in August is from 3 pm to 6 pm.
During the MAPP accredited 4-hour window from June to
September, the three sites studied ranged from a low of 8%
for MTK during August to a high of 44% for RMT during
July (Table 7). The four-hour window moves an additional
hour into the evening in August, decreasing the capacity
value for the photovoltaic systems, which are optimized
around solar noon. For reference, the current MAPP
accredited capacity value for wind turbines in Minnesota is
roughly 10% to 15%.
TABLE 6: PHOTOVOLTAIC PERFORMANCE UNDER
MAPP ACCREDITATION METHOD (KW)
Site
June
July
August
September
2-5 pm
2-5 pm
3-6 pm
2-5 pm
MTK
0.44 kW
0.50 kW
0.19 kW
0.30 kW
RMT
0.75 kW
0.92 kW
0.51 kW
0.78 kW
WBL
0.97 kW
0.95 kW
0.57 kW
0.73 kW
TABLE 7: PHOTOVOLTAIC PERFORMANCE UNDER
MAPP ACCREDITATION METHOD (%)
Site
June
July
August
September
2-5 pm
2-5 pm
3-6 pm
2-5 pm
MTK
18%
20%
8%
12%
RMT
36%
44%
24%
38%
WBL
41%
40%
24%
31%
2.3.3 High Electric Demand Capacity Performance
A previous study determined that the actual peak demand
for a day may or may not fall within the 4-hour accreditation
window (6). An alternative measure of the relationship is to
filter the data for demand thresholds that exceed 90%, 95%,
and 99% of peak for each year. This pairs up photovoltaic
generation with specific time periods of high demand.
The percent of peak ranged from 20% to 51% at 90% of
demand and 21% to 54% and 19% to 62% at 95% and 99%
of demand respectively. The RMT site consistently
increased its percentage across the increasing demand
thresholds, while the WBL site decreased performance with
each threshold. The WBL site had the lowest elevation
from ground-level and the lowest tilt angle, which may be
indicative of shading during evening hours but not to the
extent of the MTK site, which performed poorly relative to
the other two sites.
TABLE 8: PHOTOVOLTAIC PERFORMANCE DURING
PERIODS OF HIGH ELECTRIC UTILITY DEMAND
(KW)
Site
Demand >
Demand >
Demand >
90%
95%
99%
MTK
0.44 kW
0.49 kW
0.44 kW
RMT
1.03 kW
1.06 kW
1.28 kW
WBL
0.90 kW
0.81 kW
0.55 kW
TABLE 9: PHOTOVOLTAIC PERFORMANCE DURING
PERIODS OF HIGH ELECTRIC UTILITY DEMAND (%)
Location
Demand >
Demand >
Demand >
90%
95%
99%
MTK
18%
20%
18%
RMT
50%
51%
62%
WBL
38%
34%
23%
Electric utility demand exceeded 90% of annual peak when
no measurable irradiance was occurring about 7% of the
time, i.e. at night. Filtering the data for high demand
periods during daylight hours only adds roughly 1% to 6%
to the peak capacity values listed in Tables 7 and 9.
The RMT site is clearly the highest performer under all
measurements of annual electricity generation and its
electricity output’s relationship to electric utility demand.
Depending on the method of filtering, RMT produced a low
of 24% capacity during August from 3 pm to 6 pm and a
high of 62% when filtered for periods when electric demand
exceeded 99% of annual peak.
MTK, while producing an equivalent amount of electricity
to RMT on an annual basis, has lower peak capacity values
than either RMT or WBL. This is likely due to shading
during evening hours.
WBL, while producing less electricity than MTK and RMT
on an annual basis, doesn’t appear to be as affected by late
afternoon shading in terms of peak capacity values.
However, when the data is filtered for periods of demand
greater than 90%, WBL actually decreases, but it is unclear
why since all other data analysis produced similar results to
RMT.
3.
CONCLUSION
These photovoltaic sites were located in a metropolitan area
with some degree of shading and technical difficulties that
affected the annual electricity generation performance and
the relationship with electric demand to some degree. They
do represent real-world operational data however and in this
conservative analysis one of the sites showed strong results
across all measures of performance.
The RMT site had the least degree of shading and the fewest
operational issues, producing the most annual electricity on
a standardized basis (1042 kWh/kW/yr), the highest peak
capacity using the MAPP accreditation method (24% to
44% from June to September), and the highest peak capacity
at 90%, 95%, and 99% of annual peak demand (50%, 51%,
and 62% respectively). The RMT site’s performance under
the alternative demand analysis to the MAPP accreditation
method was significantly higher and may be a better method
for calculating photovoltaic generating capacity during
periods of high electrical demand.
Further investigation is needed to determine the economic
benefits of a traditional net metering arrangement versus a
time-of-day payment option that would increase the value of
electricity generation during periods of peak demand.
4.
ACKNOWLEDGEMENTS
The author wishes to thank the Minnesota Department of
Commerce State Energy Office.
5.
REFERENCES
(1) Solar Electric Power Association, 2003, Photovoltaic
data summary and analysis, Minnetonka and White
Bear Lake sites, Washington, D.C, Available:
www.solarelectricpower.org
(2) Solar Electric Power Association, 2001, Photovoltaic
data summary and analysis, Rosemount site,
Washington, D.C, Available:
www.solarelectricpower.org
(3) Mid-Continent Area Power Pool, Xcel Energy Hourly
Demand 1996-2002, Saint Paul, MN
(4) Northern States Power Company. Year unknown. Solar
Advantage Green Pricing Program. Minneapolis, MN.
Available: www.solarelectricpower.org
(5) Solar Electric Power Association, 2001, Residential PV
Systems Cost Report Washington, D.C., December
Available: www.solarelectricpower.org
(6) Taylor, Mike, 2002, A performance, cost/benefit, and
policy analysis of photovoltaic technologies in
Minnesota, University of Minnesota Master’s Thesis,
Minneapolis, MN
(7) Xcel Energy, 2002, Annual filing of cogeneration and
small power production tariffs of Northern States
Power Company, Minneapolis, MN, December 31
(8) Mid-Continent Area Power Pool, 2001, MAPP
Reliability Handbook, Accreditation Subcommittee,
Section 3, Saint Paul, MN, Jan
Appendix V – Financial Forecast Details
30 Year Plan Model
Major Assumptions
Power Supply Assumptions
• RPU’s power supply requirements are met in the following order
o Hydro
o SMMPA (up to CROD level)
o Coal-fired generation
o CT generation, subject to market price check of lower of market price or
90% of average CT Price.
o Market purchases.
• Starting in 2005 1% of RPU’s non-CROD power supply must come from
renewable sources. The renewable requirement increases by 1% per year until
2014 when it reaches 10% where remains steady. Until 2010, 0.5% of the
renewable requirement must come from biomass resources, 1.0% of renewable
requirement thereafter. The Lake Zumbro Hydro is considered a renewable
resource. The renewable energy beyond the Hydro production will be purchased.
• Silver Lake Plant (SLP) Units 1-3 are retired after 2015. SLP Unit 4 remains
available throughout the forecast period.
• The amount of SLP capacity committed to Mayo steam supply grows over time
from 5 mW’s in 2005 to 15 mW’s in 2009 staying at that level throughout the
forecast period. The contract officially ends in April, 2022 but is expected to be
extended at that time.
• The amount of SLP committed to MMPA changes from 100 mW’s to 50 mW’s in
November, 2005, from 50 mW’s to 25 mW’s in November, 2010, and ends
completely after October, 2015.
• CT#1 is retired after 2015.
• The Lake Zumbro Hydro facility remains available throughout the 30 year period.
• 95% of the Btu requirements for baseload generation are assumed to be provided
by coal with the remaining 5% from natural gas; except in the All-Gas scenarios
where 100% is provided by natural gas
Assumptions & Methods: Page 1 of 4
Major Assumptions (continued)
•
Generation dispatch is based on an hourly projection of self-generation
requirements. Dispatch order is assumed as follows, subject to the market price
check on the peaking units:
Self-Generation Demand Requirement
Generation dispatch assumption
Below 75% of smallest baseload capacity
Peaking units, the most efficient (newest)
unit
first
Above 75% of smallest baseload unit
Smallest baseload unit (SLP) first
capacity.
followed by peaking units up to 75% of
next largest baseload unit (RPU’s 50MW
share of a new coal plant when it is
projected)
Above that point larger baseload unit is
dispatched up to its capacity replacing
smaller baseload unit and peaking units.
Above that point peaking units are added
to larger baseload unit up to point where
75% of next baseload unit (SLP) is
reached.
Above that point next baseload unit (SLP)
is dispatched replacing peaking units up to
its capacity. Larger baseload unit remains
dispatched at capacity throughout this
range.
Above that point peaking units are
dispatched until their capacity is reached.
All baseload units remain dispatched at
capacity throughout this range.
Above that point market purchases are
made.
NOTE REGARDING PRICE CHECK:
Assumptions & Methods: Page 2 of 4
A price check is always done on peaking
units and if market price is less than 110%
of average peaking unit production price,
market purchases will replace peaking
unit capacity in the dispatch order.
Major Assumptions (continued)
Capital Expenditure Assumptions
• Every 50 mW’s of new load requires a new distribution substation. A second
transformer is also added to the substation between 50 mW increments. The cost
of a substation including the second transformer is $4,250,000 in today’s dollars.
• Every 5 mW’s of new load requires a new distribution feeder at a cost of
$400,000 in today’s dollars
• The average cost to install a new service is $1,450 in today’s dollars.
• Other capital spending (trucks, facilities, computer eqpt/software, etc.) is assumed
to cost $100/customer in today’s dollars.
• Internal costs such as labor, equipment, and overheads, add 25% to the external
costs of a capital project, excluding the large projects such as generation
additions, emissions control equipment, and transmission lines where it is
assumed that a vendor will build the facility.
Number of Employees / Labor Expense
• Number of Operations employees is forecasted in proportion to the number of
customers, 2.1 employees / 1,000 customers (2003 actual ratio)
• Number of Power Production employees is forecasted in proportion to installed
kW’s of generation with a weighting of 1 for RPU-operated coal-fired generation
and a weighting of .05 for combustion turbine generation, which results in ~ .5
employees / weighted kW of generation (2003 actual ratio). However, when SLP
Units 1-3 are retired, employee levels are held steady. Two additional power
production employees are added in 2009 related to emissions control equipment
additions.
• Number of Administration employees is forecasted in proportion to operating
revenue, .33 employees / $1M operating revenue, indexed for rate increases (2003
actual ratio). In addition to operating revenues driving employee forecasts, one
employee is added in 2006 and two in 2007 under the Aggressive DSM scenario
to handle the additional DSM programs that are likely to be required.
• Annual wage inflation of 4%, annual payroll tax/benefits inflation of 5%.
Other Operating & Maintenance Expense Assumptions
• Other operating and maintenance expense, except for expenses related to
transmission lines, will begin at 2004 levels and grow by inflation over the 30
year forecast term, unless specific inputs are made for significant changes, such as
when new generation or emissions control facilities are added.
• Operating and maintenance expenses related to transmission lines will grow in
proportion to the miles of transmission line installed, adjusted for inflation and a
travel factor.
• Distribution system O&M and customer services/accounts O&M are indexed for
customer base increases in addition to inflationary increases.
Assumptions & Methods: Page 3 of 4
Major Assumptions (continued)
Steam Sales
• The contract runs from 11/2005 through 04/2022. However the steam sales
forecast has been extended through all years of the forecast period under the
assumption that the contract will be renewed when it expires.
Wholesale Sales
• The amount of SLP capacity sold to MMPA changes from 100 mW’s to 50 mW’s
in November, 2005, from 50 mW’s to 25 mW’s in November, 2010, and ends
completely after October, 2015. Additional spot market sales are forecast out of
SLP, CT#2, and the new coal unit. Assumptions vary by generating unit as to
how much of available output is assumed to be sold at wholesale.
Retail Sales & Revenue
• System losses are 2.5% across the entire forecast period
• Any forecasted rate increase is assumed to take effect at the beginning of the year.
Debt Service Assumptions
• All large capital projects such new generation facilities, new transmission lines
and significant environmental control equipment will be debt financed.
• All new debt issued during the 30 forecast period will be at a rate of 6.5% and
will be issued for a term that matches the economic life of the asset, not to exceed
30 years.
Reserve Requirement Assumptions
• 5.5% of retail revenues are available to finance capital projects.
• Debt-financed projects are excluded from the calculation of reserve requirements
but debt principal payments are included.
Balance Sheet Assumptions
• Accounts Receivable balances grow in proportion to retail revenues
• Accounts Payable balances grow in proportion to operating expenses
• O&M Supplies Inventory balances grow in proportion to operating expenses
• Coal Inventory balances grow/shrink in proportion to tons of coal burned
• Due to City balances (ILOT, Sewer Rev) grow in proportion to number of
customers.
Assumptions & Methods: Page 4 of 4
Rochester Public Utilities
Financial Model Results
Scenario: No DSM
Scenario Description: Recommended expansion plan from Part IV with the forecast unaffected by demand side management
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2005
$
2006
$
2007
$
98,169
20,818
118,988
$
70,091
29,430
99,521
$
2008
$
100,761
21,317
122,078
$
71,632
30,854
102,485
$
2009
$
104,752
20,881
125,633
$
73,036
32,029
105,065
$
2010
$
94,278
19,210
113,488
$
108,387
21,455
129,842
$
74,851
34,667
109,518
$
$
69,738
27,169
96,907
$
16,581
(2,597)
667
14,651 $
19,467
(2,325)
677
17,818 $
19,593
(2,242)
731
18,082 $
20,568
(2,848)
795
18,515 $
20,324
(4,871)
808
16,261 $
(7,983)
(8,404)
(8,630)
(9,109)
(9,567)
2011
$
112,362
25,334
137,696
$
79,946
37,187
117,132
$
2012
$
117,636
23,306
140,942
$
79,455
38,685
118,140
20,563
(4,897)
492
16,158 $
(10,069)
$
2013
$
123,509
24,016
147,525
$
81,351
40,606
121,958
22,802
(4,723)
445
18,524 $
(10,597)
$
2014
$
129,063
24,726
153,789
$
82,946
42,979
125,925
25,567
(4,554)
442
21,456 $
(11,186)
$
2015
$
133,798
25,473
159,270
$
84,886
45,864
130,750
27,864
(4,426)
510
23,948 $
(11,749)
$
2016
$
140,081
26,258
166,339
$
87,147
49,193
136,340
28,521
(8,773)
1,024
20,773 $
(12,365)
$
2017
$
147,007
20,612
167,619
$
84,930
51,498
136,428
29,998
(7,278)
1,030
23,750 $
(13,013)
$
2018
$
153,692
20,672
174,365
$
87,655
53,560
141,215
31,191
(7,857)
637
23,970 $
(13,730)
$
2019
$
162,412
21,359
183,771
$
90,687
56,807
147,494
33,149
(7,589)
717
26,277 $
(14,429)
$
$
171,790
22,034
193,823
$
94,233
61,121
155,353
36,277
(15,388)
1,515
22,404 $
38,470
(12,919)
1,465
27,016
(15,178)
(15,982)
$
6,668
$
9,414
$
9,453
$
9,406
$
6,693
$
6,089
$
7,927
$
10,270
$
12,199
$
8,408
$
10,737
$
10,241
$
11,848
$
7,226
$
11,034
$
14,217
$
12,940
$
14,825
$
16,521
$
19,030
$
17,349
$
14,951
$
14,276
$
14,755
$
18,766
$
48,504
$
19,127
$
22,672
$
24,382
$
75,105
6,668
(11,265)
(1,681)
5,000
9,414
(5,769)
(1,760)
-
$
(1,277) $
$
12,940
10,364
2,576
$
3.0%
$
$
$
$
$
3,937
12,315
16,252
5,000
4,183
48,369
5.4
1,885
14,825
10,393
4,432
9,453
(5,922)
(1,835)
$
1,696
$
16,521
10,744
5,777
1.0%
$
$
$
$
$
9,406
(15,686)
(2,211)
11,000
$
2,509
$
19,030
12,077
6,954
0.0%
4,759
7,063
11,822
$
4,187
46,610
6.5
$
$
$
$
6,693
(40,651)
(2,724)
35,000
$
4,183
44,775
6.6
$
$
$
$
7,927
(5,585)
(3,017)
-
$
(1,681) $
(2,398) $
$
17,349
13,887
3,462
14,951
12,675
2,276
1.0%
4,950
7,422
12,373
6,089
(5,621)
(2,866)
-
$
1.0%
4,014
11,000
7,758
22,772
$
11,000
5,189
53,564
5.7
$
$
$
$
$
1.0%
4,791
11,000
24,000
8,920
48,711
$
35,000
7,868
85,840
3.9
$
$
$
$
10,270
(6,606)
(3,185)
-
(675) $
14,276
12,933
1,343
$
2.0%
5,047
8,477
13,524
$
7,867
82,975
3.8
$
$
$
$
5,793
9,067
14,860
7,866
79,957
4.2
479
14,755
13,214
1,541
12,199
(4,830)
(3,358)
$
4,011
$
18,766
14,212
4,554
2.0%
$
$
$
$
$
8,408
(37,300)
(4,270)
62,900
$
29,738
$
48,504
16,401
32,103
2.0%
6,127
9,560
15,687
$
7,872
76,772
4.6
$
$
$
$
4,835
9,619
14,454
7,875
73,415
5.0
10,737
(36,297)
(3,817)
$
$
1.0%
$
$
$
$
$
10,241
(2,661)
(4,035)
-
(29,377) $
19,127
17,036
2,090
$
2.0%
5,955
31,450
11,164
48,568
$
62,900
12,695
132,045
3.2
$
$
$
$
5,880
31,450
11,610
48,940
12,001
128,228
4.0
3,545
22,672
16,012
6,660
11,848
(5,873)
(4,265)
$
1,711
$
24,382
16,864
7,519
2.0%
$
$
$
$
$
5,836
11,303
17,139
12,007
124,193
3.8
7,226
(62,765)
(4,738)
111,000
$
50,723
$
75,105
20,381
54,724
2.0%
$
$
$
$
$
7,314
12,238
19,552
12,013
119,928
4.1
11,034
(60,028)
(5,028)
$
(54,022)
$
21,083
21,283
(200)
3.0%
$
$
$
$
$
3.0%
7,659
55,500
14,268
77,427
$
111,000
19,461
226,191
2.7
$
$
$
$
6,430
55,500
14,497
76,428
19,461
221,162
3.2
Page 1 of 2
Rochester Public Utilities
Financial Model Results
Scenario: No DSM
Scenario Description: Recommended expansion p
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2021
2020
$
$
2022
$
180,997
40,874
221,871
$
108,329
69,763
178,092
$
2023
$
185,962
40,591
226,553
$
111,895
72,707
184,601
$
2024
$
194,701
40,146
234,847
$
115,885
76,094
191,979
$
2025
$
206,240
40,120
246,360
$
120,746
80,070
200,817
$
2026
$
217,636
40,247
257,883
$
125,823
84,284
210,107
$
2027
$
230,209
40,556
270,765
$
131,700
88,566
220,265
$
2028
$
243,394
40,798
284,192
$
137,151
92,337
229,489
$
2029
$
257,947
40,999
298,946
$
144,166
96,865
241,031
$
2030
$
272,333
40,943
313,276
$
151,536
101,300
252,836
$
2031
$
285,002
41,218
326,221
$
159,937
105,474
265,410
$
2032
$
301,388
41,613
343,001
$
169,473
111,029
280,502
$
2033
$
318,716
42,318
361,034
$
179,602
116,064
295,665
$
2034
$
176,752
40,750
217,502
$
337,042
42,507
379,549
$
190,986
121,312
312,297
$
$
352,962
42,943
395,905
$
105,357
66,660
172,017
$
202,818
127,639
330,457
$
45,485
(13,957)
675
32,203 $
43,779
(13,628)
769
30,920 $
41,951
(13,243)
835
29,544 $
42,867
(12,864)
832
30,836 $
45,544
(12,512)
863
33,894 $
47,776
(15,892)
1,271
33,156 $
50,500
(14,290)
1,215
37,424 $
54,703
(14,457)
786
41,032 $
57,916
(13,954)
845
44,806 $
60,440
(13,384)
957
48,013 $
60,810
(12,775)
1,005
49,040 $
62,499
(12,209)
1,044
51,334 $
65,368
(11,758)
1,157
54,768 $
67,251
(11,117)
1,230
57,365 $
65,448
(10,560)
1,186
56,074
(16,451)
(16,851)
(17,320)
(18,228)
(19,223)
(20,192)
(21,262)
(22,378)
(23,611)
(24,813)
(26,102)
(27,478)
(28,926)
(30,450)
(32,054)
$
15,752
$
14,069
$
12,224
$
12,608
$
14,672
$
12,964
$
16,162
$
18,654
$
21,195
$
23,200
$
22,938
$
23,856
$
25,842
$
26,915
$
24,019
$
21,083
$
23,209
$
27,269
$
27,559
$
27,107
$
29,592
$
53,880
$
25,887
$
25,731
$
29,730
$
33,099
$
32,879
$
35,682
$
40,287
$
40,502
15,752
(8,287)
(5,338)
$
2,126
$
23,209
19,729
3,480
14,069
(4,345)
(5,664)
$
4,060
$
27,269
20,761
6,508
0.0%
$
$
$
$
$
12,224
(5,918)
(6,016)
$
290
$
27,559
21,574
5,985
0.0%
7,792
14,097
21,889
$
19,461
215,824
3.3
$
$
$
$
12,608
(6,674)
(6,386)
$
$
0.0%
7,878
14,760
22,638
$
19,458
210,160
3.3
$
$
$
$
14,672
(5,401)
(6,785)
-
(452) $
27,107
22,391
4,716
$
2.0%
9,108
15,777
24,885
$
19,460
204,143
3.2
$
$
$
$
2,485
29,592
24,109
5,483
12,964
(33,913)
(7,818)
53,056
$
24,288
$
53,880
26,876
27,005
3.0%
9,439
16,578
26,017
$
19,459
197,757
3.3
$
$
$
$
16,162
(35,852)
(8,304)
-
$
19,463
190,971
3.5
$
$
$
$
21,195
(8,828)
(8,369)
-
$
(27,993) $
(156) $
3,999
$
25,887
27,519
(1,631) $
25,731
26,631
(899) $
29,730
28,406
1,324
3.0%
3.0%
3.0%
8,159
16,961
25,121
18,654
(9,991)
(8,819)
-
9,803
26,528
18,872
55,203
$
53,056
23,525
236,209
3.0
$
$
$
$
11,680
26,528
20,226
58,434
$
23,525
227,905
3.4
$
$
$
$
23,200
(10,946)
(8,885)
$
3,369
$
33,099
30,132
2,967
3.0%
11,162
20,286
31,448
$
23,524
219,086
3.4
$
$
$
$
22,938
(13,725)
(9,433)
$
$
3.0%
9,840
20,829
30,669
$
22,526
210,718
3.7
$
$
$
$
23,856
(13,499)
(7,554)
-
(221) $
32,879
30,725
2,154
$
2.0%
11,669
22,309
33,977
$
22,525
201,833
3.9
$
$
$
$
2,803
35,682
32,194
3,489
25,842
(13,192)
(8,045)
$
4,605
$
40,287
34,428
5,859
3.0%
13,683
23,891
37,575
$
22,523
192,400
3.9
$
$
$
$
26,915
(18,132)
(8,568)
$
216
$
40,502
35,869
4,633
3.0%
13,248
24,838
38,086
$
20,060
184,846
4.5
$
$
$
$
24,019
(18,012)
(9,125)
$
(3,118)
$
37,384
37,047
337
3.0%
12,132
25,650
37,782
$
20,060
176,801
4.7
$
$
$
$
2.0%
16,074
27,945
44,019
$
20,060
168,233
4.9
$
$
$
$
16,228
29,237
45,465
20,060
159,108
4.9
Page 2 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Aggressive DSM, Coal & Gas Mix
Scenario Description: Recommended plan adjusted by using the aggressive demand side management results with SLP operating on coal and adjustments to the new resources
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2005
$
2006
$
2007
$
95,224
20,615
115,839
$
68,037
29,754
97,792
$
2008
$
97,875
21,131
119,006
$
69,126
31,486
100,612
$
2009
$
100,695
20,668
121,363
$
69,873
32,895
102,768
$
2010
$
105,144
21,261
126,405
$
71,030
35,516
106,546
$
2011
$
107,968
25,151
133,118
$
75,337
38,069
113,406
$
2012
$
93,770
19,117
112,887
$
110,973
23,169
134,141
$
74,480
39,755
114,235
$
$
69,442
27,338
96,780
$
16,107
(2,601)
664
14,170 $
18,047
(2,345)
670
16,373 $
18,395
(2,249)
714
16,859 $
18,594
(2,858)
750
16,487 $
19,859
(4,882)
749
15,727 $
19,713
(4,916)
445
15,241 $
19,907
(4,780)
410
15,538 $
(7,937)
(8,056)
(8,403)
(8,773)
(9,114)
(9,497)
(9,906)
2013
$
115,520
23,906
139,426
$
75,818
41,593
117,411
$
2014
$
118,623
24,643
143,265
$
76,986
43,567
120,553
22,015
(4,612)
405
17,808 $
(10,364)
$
2015
$
123,366
25,417
148,784
$
78,372
45,558
123,930
22,712
(4,442)
414
18,684 $
(10,799)
$
2016
$
128,300
26,226
154,526
$
79,895
47,618
127,513
24,854
(4,254)
446
21,045 $
(11,287)
$
2017
$
135,891
20,683
156,574
$
78,679
49,178
127,857
27,013
(4,046)
521
23,488 $
(11,796)
$
2018
$
141,730
20,927
162,657
$
80,456
52,621
133,077
28,717
(8,668)
1,054
21,104 $
(12,440)
$
2019
$
145,470
21,671
167,141
$
81,165
55,240
136,405
29,581
(7,112)
1,028
23,497 $
(13,041)
$
$
149,169
22,446
171,616
$
83,004
57,597
140,601
30,736
(7,747)
553
23,541 $
(13,390)
31,015
(7,510)
598
24,102
(13,736)
$
6,233
$
8,317
$
8,457
$
7,713
$
6,612
$
5,744
$
5,631
$
7,444
$
7,885
$
9,759
$
11,691
$
8,664
$
10,456
$
10,151
$
10,367
$
14,217
$
12,734
$
14,600
$
15,613
$
16,973
$
15,534
$
13,696
$
13,259
$
13,339
$
13,839
$
15,443
$
18,742
$
50,487
$
17,034
$
19,249
6,233
(11,036)
(1,681)
5,000
8,317
(4,691)
(1,760)
-
$
(1,484) $
$
12,734
10,118
2,615
$
3.0%
$
$
$
$
$
3,802
12,279
16,080
5,000
4,183
48,369
5.3
1,867
14,600
10,116
4,485
8,457
(5,608)
(1,835)
$
1,013
$
15,613
10,406
5,207
2.0%
$
$
$
$
$
7,713
(15,143)
(2,211)
11,000
$
1,359
$
16,973
11,533
5,440
1.0%
4,089
6,886
10,976
$
4,187
46,610
6.1
$
$
$
$
6,612
(40,327)
(2,724)
35,000
$
4,183
44,775
6.3
$
$
$
$
5,631
(3,051)
(3,017)
-
$
(1,438) $
(1,838) $
$
15,534
13,060
2,475
13,696
11,518
2,178
1.0%
4,659
7,355
12,013
5,744
(4,717)
(2,866)
-
$
3.0%
3,640
11,000
7,671
22,311
$
11,000
5,189
53,564
5.3
$
$
$
$
$
1.0%
4,391
11,000
24,000
8,829
48,219
$
35,000
7,868
85,840
3.8
$
$
$
$
7,444
(4,179)
(3,185)
-
(437) $
13,259
11,828
1,431
$
1.0%
4,347
8,305
12,652
$
7,867
82,975
3.7
$
$
$
$
3,892
8,560
12,452
7,866
79,957
3.8
80
13,339
12,415
925
7,885
(4,027)
(3,358)
$
499
$
13,839
13,196
643
2.0%
$
$
$
$
$
9,759
(4,613)
(3,542)
$
1,604
$
15,443
14,008
1,435
1.0%
4,147
9,035
13,181
$
7,872
76,772
4.1
$
$
$
$
4,201
9,475
13,676
7,875
73,415
4.2
11,691
(5,350)
(3,042)
$
3,299
$
18,742
15,298
3,444
2.0%
$
$
$
$
$
8,664
(39,677)
(3,981)
66,740
$
31,745
$
50,487
17,398
33,089
2.0%
4,477
10,000
14,477
$
7,878
69,873
4.6
$
$
$
$
5,000
10,617
15,617
7,184
66,831
5.4
10,456
(39,702)
(4,208)
$
(33,454) $
2,215
$
17,034
17,363
(329) $
19,249
16,224
3,025
3.0%
$
$
$
$
$
6,882
33,370
12,474
52,725
66,740
12,301
129,590
3.3
10,151
(4,544)
(3,392)
-
2.0%
$
$
$
$
$
6,946
33,370
13,012
53,328
12,307
125,382
4.0
10,367
(6,031)
(3,595)
$
740
$
19,989
16,964
3,025
0.0%
$
$
$
$
$
0.0%
5,829
12,411
18,240
$
11,255
121,990
4.1
$
$
$
$
6,999
13,317
20,315
11,255
118,394
4.2
Page 1 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Aggressive DSM, Coal & Gas Mix
Scenario Description: Recommended plan adjuste
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2021
2020
$
$
154,931
23,254
178,184
$
85,190
60,453
145,643
$
$
2022
$
160,308
24,063
184,371
$
87,633
63,535
151,168
32,541
(7,295)
628
25,875 $
(14,485)
$
2023
$
169,477
24,902
194,380
$
90,856
66,245
157,101
33,202
(7,077)
673
26,799 $
(15,215)
$
2024
$
177,433
25,728
203,160
$
94,450
70,283
164,733
37,279
(6,774)
732
31,237 $
(16,013)
$
2025
$
188,115
26,546
214,661
$
98,729
74,893
173,622
38,428
(11,104)
1,207
28,530 $
(16,854)
$
2026
$
194,648
35,261
229,909
$
105,134
79,699
184,833
41,040
(9,556)
1,198
32,682 $
(17,791)
$
2027
$
203,787
35,789
239,576
$
109,618
83,199
192,817
45,076
(9,972)
775
35,880 $
(18,688)
$
2028
$
215,550
36,437
251,987
$
114,733
86,161
200,894
46,759
(9,595)
852
38,016 $
(19,668)
$
2029
$
228,425
37,150
265,575
$
120,492
91,086
211,578
$
2030
$
238,814
37,650
276,465
$
125,399
97,478
222,877
$
2031
$
250,151
38,201
288,352
$
132,017
101,393
233,410
$
2032
$
264,376
38,886
303,262
$
139,321
106,224
245,545
$
2033
$
276,698
39,824
316,522
$
147,249
110,972
258,221
$
2034
$
292,436
40,577
333,012
$
156,456
117,289
273,746
$
$
309,069
41,486
350,555
$
166,210
122,825
289,035
51,093
(13,215)
1,307
39,185 $
53,997
(11,633)
1,324
43,688 $
53,587
(11,975)
983
42,595 $
54,942
(11,467)
1,027
44,503 $
57,717
(10,943)
1,043
47,818 $
58,301
(10,596)
1,069
48,774 $
59,267
(10,262)
1,104
50,109 $
(20,711)
(21,852)
(22,964)
(24,182)
(25,441)
(26,767)
(28,161)
61,520
(9,773)
1,123
52,870
(29,628)
$
11,390
$
11,584
$
15,223
$
11,676
$
14,891
$
17,192
$
18,348
$
18,474
$
21,836
$
19,631
$
20,322
$
22,376
$
22,007
$
21,948
$
23,242
$
19,989
$
21,246
$
22,962
$
25,124
$
54,104
$
24,557
$
26,360
$
29,598
$
56,217
$
30,713
$
33,821
$
33,650
$
34,871
$
35,326
$
37,176
11,390
(6,321)
(3,812)
$
1,257
$
21,246
17,824
3,421
11,584
(5,828)
(4,039)
$
1,717
$
22,962
19,047
3,916
1.0%
$
$
$
$
$
15,223
(8,777)
(4,285)
$
2,161
$
25,124
20,110
5,013
1.0%
7,061
13,940
21,001
$
11,255
114,582
4.4
$
$
$
$
11,676
(40,826)
(5,277)
63,407
$
28,980
$
54,104
22,485
31,619
3.0%
6,742
14,490
21,232
$
11,252
110,543
4.5
$
$
$
$
14,891
(38,834)
(5,604)
$
$
2.0%
8,704
15,715
24,418
$
11,254
106,258
4.9
$
$
$
$
17,192
(9,443)
(5,946)
-
(29,547) $
24,557
23,700
857
$
3.0%
9,073
31,704
17,320
58,097
$
63,407
16,108
164,388
3.5
$
$
$
$
1,803
26,360
23,393
2,967
18,348
(8,801)
(6,309)
$
3,238
$
29,598
24,871
4,727
1.0%
7,818
31,704
17,712
57,233
$
16,112
158,784
4.1
$
$
$
$
18,474
(40,258)
(7,341)
55,744
$
26,619
$
56,217
27,136
29,081
2.0%
9,005
18,040
27,045
$
16,112
152,838
4.1
$
$
$
$
21,836
(40,546)
(6,794)
$
$
3.0%
9,517
19,011
28,528
$
16,111
146,529
4.3
$
$
$
$
19,631
(9,314)
(7,208)
-
(25,504) $
30,713
28,016
2,697
$
3.0%
10,767
27,872
20,930
59,569
$
55,744
20,380
194,932
3.6
$
$
$
$
3,109
33,821
28,293
5,528
20,322
(12,846)
(7,647)
$
$
2.0%
11,366
27,872
22,015
61,253
$
19,381
188,138
4.2
$
$
$
$
22,376
(15,503)
(5,652)
-
(171) $
33,650
29,247
4,403
$
2.0%
9,554
21,775
31,329
$
19,380
180,930
4.1
$
$
$
$
1,222
34,871
30,269
4,603
22,007
(15,533)
(6,019)
$
454
$
35,326
31,426
3,900
3.0%
11,858
23,440
35,298
$
19,378
173,283
4.2
$
$
$
$
21,948
(13,687)
(6,410)
$
1,850
$
37,176
33,662
3,514
2.0%
13,780
25,052
38,832
$
16,915
167,632
5.0
$
$
$
$
23,242
(17,012)
(6,827)
$
$
3.0%
13,265
26,035
39,300
$
16,915
161,612
5.1
$
$
$
$
(597)
36,579
35,699
880
3.0%
11,596
26,754
38,350
$
16,915
155,202
5.2
$
$
$
$
14,038
28,691
42,729
16,915
148,375
5.4
Page 2 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Aggressive DSM, All Gas
Scenario Description: Recommended plan adjusted by using the aggressive demand side management results with SLP operating on natural gas and the coal unit replaced with gas-fired capacity
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2005
$
$
109,247
19,619
128,866
$
86,254
27,019
113,272
$
2006
$
2007
$
110,941
20,866
131,806
$
82,792
29,418
112,209
$
2008
$
112,900
21,386
134,286
$
84,298
31,155
115,453
$
2009
$
115,002
20,929
135,932
$
84,451
32,569
117,020
$
2010
$
118,918
21,526
140,445
$
86,019
34,698
120,717
$
2011
$
122,112
25,428
147,540
$
92,626
37,245
129,872
$
2012
$
124,268
23,330
147,598
$
88,749
38,889
127,637
$
2013
$
129,360
24,072
153,432
$
90,565
40,706
131,271
$
2014
$
131,519
24,809
156,328
$
92,205
42,634
134,839
$
2015
$
134,097
25,582
159,679
$
94,111
44,564
138,674
$
2016
$
138,092
26,392
164,484
$
96,432
46,578
143,010
15,594
(3,201)
627
13,019 $
19,597
(3,007)
615
17,204 $
18,832
(2,926)
684
16,591 $
18,911
(3,549)
736
16,098 $
19,728
(4,388)
768
16,109 $
17,668
(4,354)
479
13,792 $
19,961
(4,251)
460
16,169 $
22,161
(4,120)
507
18,548 $
21,489
(3,987)
557
18,059 $
21,004
(3,840)
583
17,747 $
(7,937)
(8,056)
(8,198)
(8,351)
(8,675)
(9,040)
(9,199)
(9,624)
(9,784)
(9,976)
$
2017
$
144,843
20,717
165,560
$
89,337
48,029
137,366
21,474
(3,675)
580
18,379 $
(10,426)
$
2018
$
149,585
20,959
170,545
$
91,648
51,427
143,075
28,194
(8,298)
1,071
20,968 $
(10,995)
$
2019
$
153,533
21,703
175,236
$
92,947
54,011
146,958
27,470
(6,743)
1,057
21,785 $
(11,526)
$
$
159,011
22,483
181,495
$
95,425
56,348
151,772
28,278
(7,379)
566
21,465 $
(11,835)
29,722
(7,142)
599
23,179
(12,444)
$
5,083
$
9,149
$
8,393
$
7,748
$
7,433
$
4,753
$
6,970
$
8,925
$
8,276
$
7,771
$
7,952
$
9,973
$
10,258
$
9,630
$
10,735
$
14,217
$
10,302
$
13,385
$
14,872
$
16,800
$
16,994
$
14,458
$
15,722
$
17,588
$
18,989
$
19,298
$
18,764
$
51,582
$
17,851
$
19,319
5,083
(22,515)
(1,484)
15,000
9,149
(4,516)
(1,550)
-
$
(3,916) $
3,083
$
10,302
11,180
(878) $
13,385
10,472
2,913
20.0%
$
$
$
$
$
3,802
10,000
12,529
26,330
15,000
4,636
58,566
4.8
8,393
(5,294)
(1,612)
$
1,487
$
14,872
10,758
4,114
2.0%
$
$
$
$
$
7,748
(14,847)
(1,973)
11,000
$
1,928
$
16,800
11,745
5,055
0.0%
4,089
6,886
10,976
$
4,640
57,016
5.9
$
$
$
$
7,433
(20,000)
(2,239)
15,000
$
195
$
16,994
12,231
4,764
0.0%
4,659
7,355
12,013
$
4,636
55,404
5.8
$
$
$
$
4,753
(4,940)
(2,349)
$
(2,536) $
$
14,458
11,978
2,480
2.0%
3,640
11,000
7,671
22,311
$
11,000
5,642
64,431
4.9
$
$
$
$
6,970
(3,238)
(2,468)
-
$
1.0%
4,391
11,000
4,000
8,329
27,719
$
15,000
6,789
77,193
4.3
$
$
$
$
1,264
15,722
12,115
3,607
8,925
(4,460)
(2,599)
$
1,865
$
17,588
12,755
4,833
0.0%
4,347
8,305
12,652
$
6,788
74,843
4.0
$
$
$
$
3,892
8,560
12,452
6,788
72,376
4.4
8,276
(4,140)
(2,734)
$
1,401
$
18,989
13,590
5,399
2.0%
$
$
$
$
$
7,771
(4,585)
(2,877)
$
309
$
19,298
14,610
4,688
0.0%
4,147
9,035
13,181
$
6,794
69,777
4.8
$
$
$
$
4,201
9,475
13,676
6,796
67,043
4.7
7,952
(5,456)
(3,030)
$
$
0.0%
$
$
$
$
$
9,973
(39,926)
(3,969)
66,740
(534) $
18,764
15,957
2,807
$
1.0%
4,477
10,000
14,477
$
6,800
64,165
4.7
$
$
$
$
5,000
10,617
15,617
6,801
61,135
4.9
32,818
51,582
17,723
33,859
10,258
(39,795)
(4,194)
$
$
2.0%
$
$
$
$
$
6,882
33,370
12,474
52,725
66,740
11,918
123,907
3.4
9,630
(4,784)
(3,378)
-
(33,731) $
17,851
17,690
160
$
1.0%
$
$
$
$
$
6,946
33,370
13,012
53,328
11,924
119,712
3.9
1,468
19,319
16,551
2,768
10,735
(6,450)
(3,580)
$
705
$
20,024
17,304
2,720
0.0%
$
$
$
$
$
1.0%
5,829
12,411
18,240
$
10,872
116,334
4.0
$
$
$
$
6,999
13,317
20,315
10,872
112,754
4.2
Page 1 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Aggressive DSM, All Gas
Scenario Description: Recommended plan adjuste
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2021
2020
$
$
165,153
23,292
188,444
$
98,375
59,167
157,542
$
$
2022
$
172,577
24,105
196,682
$
101,624
62,229
163,853
30,902
(6,928)
627
24,601 $
(13,123)
$
2023
$
178,905
24,939
203,844
$
105,840
64,872
170,712
32,829
(6,711)
685
26,803 $
(13,784)
$
2024
$
189,139
25,769
214,908
$
110,732
68,601
179,334
33,132
(6,410)
727
27,448 $
(14,507)
$
2025
$
200,527
26,589
227,116
$
116,714
72,887
189,601
35,575
(7,978)
904
28,501 $
(15,269)
$
2026
$
209,544
27,411
236,956
$
121,946
76,242
198,188
37,515
(7,222)
927
31,220 $
(16,118)
$
2027
$
221,534
28,327
249,862
$
128,405
79,716
208,121
38,767
(7,193)
793
32,367 $
(16,930)
$
2028
$
234,322
29,320
263,642
$
135,472
82,626
218,099
41,741
(6,851)
849
35,739 $
(17,819)
$
2029
$
248,318
30,382
278,700
$
143,381
87,505
230,886
45,543
(10,507)
1,272
36,309 $
(18,763)
$
2030
$
262,157
31,443
293,600
$
150,938
93,890
244,828
47,814
(8,964)
1,247
40,098 $
(19,796)
$
2031
$
277,294
32,550
309,844
$
160,197
97,811
258,008
48,772
(9,347)
873
40,299 $
(20,805)
$
2032
$
293,062
33,701
326,763
$
169,974
102,616
272,590
51,836
(8,882)
930
43,884 $
(21,907)
$
2033
$
309,729
34,941
344,670
$
180,136
107,339
287,475
54,173
(8,405)
984
46,753 $
(23,049)
$
2034
$
324,167
36,185
360,351
$
191,835
113,589
305,424
57,195
(8,107)
1,082
50,170 $
(24,249)
$
$
339,279
37,512
376,791
$
204,074
119,051
323,125
54,927
(7,826)
1,189
48,291 $
(25,513)
53,666
(7,394)
1,193
47,465
(26,842)
$
11,478
$
13,019
$
12,941
$
13,233
$
15,102
$
15,437
$
17,920
$
17,546
$
20,301
$
19,494
$
21,977
$
23,704
$
25,921
$
22,778
$
20,623
$
20,024
$
21,129
$
23,852
$
23,864
$
35,526
$
25,352
$
26,739
$
29,021
$
54,506
$
27,361
$
29,991
$
31,099
$
33,534
$
37,532
$
40,539
11,478
(6,577)
(3,796)
$
1,105
$
21,129
18,156
2,973
13,019
(6,274)
(4,021)
$
2,723
$
23,852
19,381
4,471
1.0%
$
$
$
$
$
12,941
(8,662)
(4,267)
$
12
$
23,864
20,245
3,620
2.0%
7,061
13,940
21,001
$
10,872
108,958
4.3
$
$
$
$
13,233
(22,054)
(4,816)
25,300
$
11,662
$
35,526
21,603
13,924
1.0%
6,742
14,490
21,232
$
10,869
104,937
4.6
$
$
$
$
15,102
(20,163)
(5,113)
$
$
3.0%
8,704
15,715
24,418
$
10,871
100,670
4.7
$
$
$
$
15,437
(8,628)
(5,423)
-
(10,174) $
25,352
22,945
2,408
$
3.0%
9,073
12,650
16,844
38,567
$
25,300
12,807
121,154
4.2
$
$
$
$
1,387
26,739
23,509
3,230
17,920
(9,885)
(5,753)
$
2,282
$
29,021
25,053
3,968
2.0%
7,818
12,650
17,236
37,704
$
12,811
116,041
4.6
$
$
$
$
17,546
(41,057)
(6,748)
55,744
$
25,485
$
54,506
27,357
27,149
3.0%
9,005
18,040
27,045
$
12,811
110,617
4.7
$
$
$
$
20,301
(41,284)
(6,162)
$
(27,145) $
2,630
$
27,361
28,258
(897) $
29,991
28,602
1,389
3.0%
9,517
19,011
28,528
$
12,810
104,865
5.0
$
$
$
$
19,494
(10,328)
(6,536)
-
3.0%
10,767
27,872
20,930
59,569
$
55,744
17,079
153,861
3.9
$
$
$
$
21,977
(13,938)
(6,931)
$
1,108
$
31,099
29,654
1,445
3.0%
11,366
27,872
22,015
61,253
$
16,080
147,698
4.7
$
$
$
$
23,704
(16,380)
(4,889)
$
2,435
$
33,534
30,766
2,769
3.0%
9,554
21,775
31,329
$
16,079
141,163
4.5
$
$
$
$
25,921
(16,716)
(5,207)
$
3,998
$
37,532
32,079
5,453
3.0%
11,858
23,440
35,298
$
16,077
134,232
4.8
$
$
$
$
22,778
(14,226)
(5,545)
$
3,007
$
40,539
34,460
6,079
3.0%
13,780
25,052
38,832
$
13,614
129,343
6.0
$
$
$
$
20,623
(17,486)
(5,906)
$
(2,769)
$
37,770
36,324
1,446
2.0%
13,265
26,035
39,300
$
13,614
124,136
6.2
$
$
$
$
2.0%
11,596
26,754
38,350
$
13,614
118,591
6.1
$
$
$
$
14,038
28,691
42,729
13,614
112,685
6.1
Page 2 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Normal DSM, Coal & Gas Mix
Scenario Description: Recommended plan adjusted by using the normal demand side management forecast with SLP operating on coal and adjustments to the new resources.
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2005
$
2006
$
2007
$
93,491
20,865
114,357
$
68,104
29,413
97,517
$
2008
$
95,323
21,378
116,702
$
69,292
30,688
99,980
$
2009
$
99,323
20,920
120,243
$
70,186
31,815
102,001
$
2010
$
104,010
21,510
125,520
$
71,500
34,413
105,913
$
2011
$
108,272
25,402
133,673
$
76,034
36,930
112,964
$
2012
$
93,770
19,211
112,981
$
111,604
23,412
135,015
$
75,345
38,605
113,950
$
$
69,442
27,177
96,619
$
16,362
(2,601)
668
14,429 $
16,840
(2,345)
665
15,160 $
16,722
(2,248)
676
15,150 $
18,242
(2,856)
687
16,074 $
19,608
(4,879)
681
15,409 $
20,709
(4,913)
390
16,187 $
21,065
(4,777)
391
16,679 $
(7,937)
(7,870)
(8,025)
(8,404)
(8,757)
(9,162)
(9,585)
2013
$
115,257
24,141
139,398
$
76,820
40,409
117,228
$
2014
$
121,041
24,879
145,920
$
78,201
42,366
120,567
22,170
(4,610)
413
17,972 $
(10,047)
$
2015
$
127,358
25,649
153,008
$
79,659
45,300
124,959
25,353
(4,439)
468
21,382 $
(10,501)
$
2016
$
131,403
26,447
157,850
$
81,279
48,176
129,455
28,049
(8,802)
993
20,240 $
(10,997)
$
2017
$
135,062
20,784
155,846
$
79,160
50,217
129,377
28,395
(7,258)
1,012
22,150 $
(11,516)
$
2018
$
138,038
20,877
158,915
$
80,691
52,835
133,527
26,469
(7,820)
542
19,191 $
(11,842)
$
2019
$
144,448
21,630
166,078
$
82,517
54,456
136,973
25,389
(7,643)
510
18,255 $
(12,105)
$
$
149,533
22,400
171,933
$
84,445
57,120
141,566
29,104
(7,364)
486
22,226 $
(12,734)
30,367
(7,163)
497
23,701
(13,383)
$
6,492
$
7,289
$
7,124
$
7,670
$
6,652
$
7,025
$
7,094
$
7,925
$
10,881
$
9,243
$
10,634
$
7,349
$
6,150
$
9,492
$
10,319
$
14,217
$
12,981
$
14,000
$
13,701
$
14,778
$
13,250
$
12,387
$
13,257
$
13,831
$
16,892
$
48,332
$
18,109
$
17,474
$
15,988
$
15,908
6,492
(11,048)
(1,681)
5,000
7,289
(4,510)
(1,760)
-
$
(1,236) $
$
12,981
10,182
2,799
$
3.0%
$
$
$
$
$
3,802
12,279
16,080
5,000
4,183
48,369
5.4
1,019
14,000
10,191
3,809
7,124
(5,589)
(1,835)
$
$
0.0%
$
$
$
$
$
7,670
(15,382)
(2,211)
11,000
(300) $
13,701
10,453
3,248
$
0.0%
4,091
6,886
10,977
$
4,187
46,610
5.8
$
$
$
$
1,077
14,778
11,568
3,210
6,652
(40,456)
(2,724)
35,000
$
(1,528) $
$
13,250
13,088
162
2.0%
4,710
7,368
12,078
$
4,183
44,775
5.9
$
$
$
$
7,025
(5,023)
(2,866)
-
$
3.0%
3,722
11,000
7,692
22,414
$
11,000
5,189
53,564
5.2
$
$
$
$
7,094
(3,207)
(3,017)
-
(864) $
12,387
11,576
811
$
2.0%
4,480
11,000
24,000
8,851
48,331
$
35,000
7,868
85,840
3.8
$
$
$
$
870
13,257
11,999
1,258
7,925
(4,166)
(3,185)
$
574
$
13,831
12,745
1,086
1.0%
4,473
8,337
12,810
$
7,867
82,975
3.8
$
$
$
$
4,000
8,586
12,587
7,866
79,957
3.9
10,881
(4,463)
(3,358)
$
3,061
$
16,892
13,915
2,977
1.0%
$
$
$
$
$
9,243
(36,433)
(4,270)
62,900
$
31,440
$
48,332
16,451
31,882
3.0%
4,235
9,054
13,289
$
7,872
76,772
4.1
$
$
$
$
4,327
9,504
13,831
7,875
73,415
4.6
10,634
(37,040)
(3,817)
$
$
3.0%
$
$
$
$
$
7,349
(3,950)
(4,035)
-
(30,223) $
18,109
16,860
1,249
$
1.0%
4,901
31,450
10,898
47,249
$
62,900
12,695
132,045
3.1
$
$
$
$
6,424
31,450
11,796
49,670
12,001
128,228
3.8
6,150
(3,371)
(4,265)
-
(635) $
17,474
15,077
2,396
$
0.0%
$
$
$
$
$
6,918
11,641
18,560
12,007
124,193
3.4
9,492
(6,118)
(3,453)
-
(1,486) $
15,988
15,616
371
$
0.0%
$
$
$
$
$
5,460
11,752
17,212
12,013
119,928
3.4
10,319
(5,828)
(3,660)
-
(79) $
15,908
16,304
(396) $
2.0%
$
$
$
$
$
831
16,739
17,140
(401)
1.0%
6,782
12,671
19,453
$
10,961
116,476
4.0
$
$
$
$
6,670
13,216
19,886
10,961
112,816
4.2
Page 1 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Normal DSM, Coal & Gas Mix
Scenario Description: Recommended plan adjuste
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2021
2020
$
$
158,311
23,210
181,520
$
86,934
59,981
146,915
$
$
2022
$
166,813
24,015
190,828
$
89,766
63,326
153,092
34,606
(6,946)
571
28,231 $
(14,106)
$
2023
$
174,644
24,815
199,459
$
93,185
67,051
160,236
37,736
(10,997)
1,088
27,828 $
(14,795)
$
2024
$
179,088
34,067
213,155
$
100,022
72,220
172,242
39,223
(9,495)
1,120
30,848 $
(15,571)
$
2025
$
186,186
34,226
220,412
$
103,673
75,370
179,043
40,913
(9,978)
746
31,682 $
(15,973)
$
2026
$
196,281
34,679
230,960
$
107,611
79,812
187,422
41,369
(9,599)
834
32,604 $
(16,861)
$
2027
$
207,513
35,295
242,809
$
112,404
84,048
196,452
$
2028
$
215,130
35,940
251,070
$
117,090
87,403
204,493
$
2029
$
227,982
36,578
264,560
$
122,764
91,793
214,557
$
2030
$
240,460
37,089
277,549
$
128,637
96,072
224,709
$
2031
$
251,876
37,673
289,549
$
135,699
100,071
235,770
$
2032
$
266,201
38,412
304,613
$
143,429
105,462
248,891
43,538
(13,095)
1,269
31,712 $
46,357
(11,581)
1,280
36,056 $
46,577
(11,795)
864
35,646 $
50,003
(11,375)
864
39,492 $
52,840
(10,893)
921
42,868 $
53,779
(10,373)
929
44,335 $
(17,693)
(18,622)
(19,599)
(20,679)
(21,710)
(22,861)
$
2033
$
281,342
39,393
320,735
$
151,743
110,402
262,145
55,723
(9,910)
946
46,759 $
(24,052)
$
2034
$
297,345
40,137
337,482
$
161,315
115,741
277,057
58,590
(9,579)
1,059
50,070 $
(25,305)
$
$
311,209
41,042
352,250
$
171,407
121,356
292,762
60,425
(9,099)
1,178
52,505 $
(26,623)
59,488
(8,598)
1,189
52,079
(28,010)
$
14,125
$
13,033
$
15,277
$
15,709
$
15,743
$
14,019
$
17,434
$
16,047
$
18,813
$
21,158
$
21,474
$
22,707
$
24,765
$
25,882
$
24,069
$
16,739
$
20,764
$
50,685
$
22,880
$
26,127
$
28,625
$
54,679
$
29,400
$
27,369
$
29,350
$
31,159
$
29,856
$
32,250
$
37,310
$
40,061
14,125
(6,220)
(3,881)
$
4,025
$
20,764
18,506
2,258
13,033
(38,075)
(4,804)
59,767
$
29,921
$
50,685
20,937
29,748
3.0%
$
$
$
$
$
15,277
(37,982)
(5,100)
$
$
3.0%
6,652
13,817
20,468
$
10,961
108,935
4.6
$
$
$
$
15,709
(7,052)
(5,411)
-
(27,805) $
22,880
21,468
1,413
$
2.0%
8,248
29,884
15,653
53,785
$
59,767
15,534
163,898
3.5
$
$
$
$
3,247
26,127
21,383
4,744
15,743
(7,499)
(5,746)
$
2,498
$
28,625
22,706
5,919
0.0%
8,759
29,884
16,469
55,112
$
15,537
158,798
4.0
$
$
$
$
14,019
(34,309)
(6,712)
53,056
$
26,054
$
54,679
25,372
29,307
1.0%
7,321
16,026
23,347
$
15,535
153,388
3.9
$
$
$
$
17,434
(35,588)
(7,125)
$
$
3.0%
8,944
17,228
26,172
$
15,539
147,642
4.0
$
$
$
$
16,047
(10,515)
(7,564)
-
(25,279) $
29,400
26,293
3,107
$
3.0%
9,005
26,528
18,695
54,228
$
53,056
19,602
193,986
3.3
$
$
$
$
18,813
(9,800)
(7,032)
-
(2,031) $
27,369
25,408
1,960
$
1.0%
10,351
26,528
19,901
56,779
$
19,601
186,861
3.7
$
$
$
$
1,981
29,350
27,097
2,253
21,158
(11,888)
(7,461)
$
1,809
$
31,159
28,658
2,501
3.0%
10,797
20,234
31,031
$
19,601
179,297
3.6
$
$
$
$
21,474
(14,861)
(7,916)
$
(1,303) $
$
29,856
28,976
880
3.0%
9,441
20,769
30,210
$
18,602
172,266
4.0
$
$
$
$
22,707
(14,374)
(5,939)
-
$
2.0%
11,215
22,234
33,449
$
18,601
164,805
4.2
$
$
$
$
2,394
32,250
30,156
2,094
24,765
(13,380)
(6,325)
$
5,060
$
37,310
32,243
5,067
3.0%
13,347
23,851
37,198
$
18,599
156,888
4.3
$
$
$
$
25,882
(16,395)
(6,736)
$
2,751
$
40,061
34,178
5,883
3.0%
12,774
24,761
37,535
$
16,137
150,949
5.1
$
$
$
$
24,069
(18,928)
(7,174)
$
(2,033)
$
38,028
35,411
2,617
3.0%
11,137
25,428
36,565
$
16,137
144,625
5.3
$
$
$
$
2.0%
13,509
27,283
40,792
$
16,137
137,888
5.5
$
$
$
$
15,685
29,145
44,831
16,137
130,715
5.6
Page 2 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Normal DSM, All Gas
Scenario Description: Recommenced plan adjusted by using the normal demand side management forecast with SLP operating on natural gas and the coal unit replaced with gas-fired capacity
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2005
$
$
110,157
19,625
129,782
$
86,254
26,837
113,091
$
2006
$
2007
$
109,830
20,861
130,690
$
82,862
29,112
111,974
$
2008
$
111,982
21,378
133,360
$
84,475
30,538
115,013
$
2009
$
114,393
20,922
135,315
$
84,786
31,640
116,425
$
2010
$
116,302
21,510
137,812
$
86,525
33,744
120,268
$
2011
$
121,067
25,411
146,478
$
93,377
36,264
129,641
$
2012
$
124,793
23,309
148,102
$
89,704
37,926
127,630
$
2013
$
128,878
24,043
152,920
$
91,682
39,715
131,397
$
2014
$
132,718
24,778
157,496
$
93,567
41,641
135,208
$
2015
$
135,577
25,542
161,119
$
95,591
43,458
139,048
16,691
(3,201)
642
14,133 $
18,716
(3,007)
638
16,347 $
18,347
(2,924)
695
16,118 $
18,890
(3,546)
741
16,084 $
17,544
(4,385)
747
13,905 $
16,838
(4,351)
418
12,904 $
20,472
(4,248)
388
16,612 $
21,523
(4,117)
430
17,835 $
22,287
(3,984)
473
18,776 $
(7,937)
(7,870)
(8,025)
(8,199)
(8,335)
(8,720)
(9,123)
(9,563)
(9,995)
$
2016
$
141,267
26,348
167,615
$
98,056
45,254
143,310
22,071
(3,828)
505
18,748 $
(10,212)
$
2017
$
146,653
20,677
167,330
$
91,065
48,017
139,082
24,305
(3,632)
514
21,188 $
(10,694)
$
2018
$
152,883
20,923
173,806
$
93,321
51,748
145,069
28,248
(8,297)
1,015
20,966 $
(11,272)
$
2019
$
156,845
21,663
178,508
$
94,498
53,787
148,286
28,737
(6,790)
1,042
22,989 $
(11,810)
$
$
160,758
22,430
183,188
$
97,127
56,421
153,548
30,222
(7,350)
601
23,473 $
(12,121)
29,640
(7,154)
652
23,139
(12,427)
$
6,196
$
8,476
$
8,093
$
7,885
$
5,570
$
4,184
$
7,489
$
8,272
$
8,781
$
8,536
$
10,494
$
9,695
$
11,179
$
11,352
$
10,712
$
14,217
$
11,306
$
13,944
$
15,039
$
16,965
$
15,423
$
11,998
$
13,485
$
14,725
$
16,312
$
16,847
$
16,930
$
49,733
$
18,708
$
20,737
6,196
(22,624)
(1,484)
15,000
8,476
(4,288)
(1,550)
-
$
(2,911) $
$
11,306
11,221
85
$
21.0%
$
$
$
$
$
3,802
10,000
12,529
26,330
15,000
4,636
58,566
5.0
2,638
13,944
10,530
3,414
8,093
(5,385)
(1,612)
$
1,095
$
15,039
10,826
4,214
0.0%
$
$
$
$
$
7,885
(14,987)
(1,973)
11,000
$
1,926
$
16,965
11,823
5,142
0.0%
4,091
6,886
10,977
$
4,640
57,016
5.7
$
$
$
$
5,570
(19,873)
(2,239)
15,000
$
4,636
55,404
5.7
$
$
$
$
7,489
(3,534)
(2,468)
-
$
(1,542) $
(3,426) $
1,487
$
15,423
12,287
3,136
11,998
12,036
(38) $
13,485
12,245
1,240
0.0%
4,710
7,368
12,078
4,184
(5,261)
(2,349)
-
$
0.0%
3,722
11,000
7,692
22,414
$
11,000
5,642
64,431
4.9
$
$
$
$
2.0%
4,480
11,000
4,000
8,351
27,831
$
15,000
6,789
77,193
4.0
$
$
$
$
8,272
(4,433)
(2,599)
$
1,240
$
14,725
12,979
1,746
1.0%
4,473
8,337
12,810
$
6,788
74,843
3.8
$
$
$
$
4,000
8,586
12,587
6,788
72,376
4.4
8,781
(4,460)
(2,734)
$
1,587
$
16,312
13,926
2,386
1.0%
$
$
$
$
$
8,536
(5,124)
(2,877)
$
535
$
16,847
14,935
1,912
1.0%
4,235
9,054
13,289
$
6,794
69,777
4.6
$
$
$
$
4,327
9,504
13,831
6,796
67,043
4.8
10,494
(7,381)
(3,030)
$
84
$
16,930
15,819
1,112
0.0%
$
$
$
$
$
9,695
(39,664)
(3,969)
66,740
$
32,802
$
49,733
17,405
32,328
2.0%
4,901
10,112
15,013
$
6,800
64,165
4.9
$
$
$
$
6,424
11,010
17,434
6,801
61,135
5.3
11,179
(38,009)
(4,194)
$
$
1.0%
$
$
$
$
$
6,918
33,370
12,476
52,764
66,740
11,918
123,907
3.4
11,352
(5,946)
(3,378)
-
(31,024) $
18,708
17,890
818
$
2.0%
$
$
$
$
$
5,460
33,370
12,586
51,417
11,924
119,712
4.0
2,028
20,737
16,631
4,105
10,712
(5,777)
(3,580)
$
1,354
$
22,091
17,469
4,622
0.0%
$
$
$
$
$
0.0%
6,782
12,671
19,453
$
10,872
116,334
4.2
$
$
$
$
6,670
13,216
19,886
10,872
112,754
4.2
Page 1 of 2
Rochester Public Utilities
Financial Model Results
Scenario: Normal DSM, All Gas
Scenario Description: Recommenced plan adjuste
All dollar values in $1,000s
Year
1 Sales of Electricity - Retail
2 Other Revenues
3 Total Operating Revenues
4
5 Power Supply Costs
6 Net Other Operating Expenses
7 Total Operating Expenses
8
9 Operating Income
10 Interest Expense, Incl AFUDC
11 Interest and Other Income
12 Income B4 Transfer/Cap Contribution
13
14 Net Transfers & Contributions In (Out)
15
16 Change in Net Assets
17
18
19
20 01/01 Cash Balance
21
22 Change in Net Assets
23 Operating & Capital Activity
24 Bond Principle Payments
25 Bond Sale Proceeds
26
27 Net Changes in Cash
28
29 12/31 Cash Balance
30 Reserve Minimum
31 Excess (Deficit) from Minimum
32
33 Rate Change
34
35 Breakdown of Capital Expenditures
36 Distribution System Expansions
37 Transmission Line Additions
38 Peaking Generation Additions
39 Baseload Generation Additions
40 Emission Control Eqpt Major Additions
41 Other
42 Total Capital Expenditures
43
44
45 Debt and Debt Service
46 New Borrowings
47 Debt Service Payments
48 Debt Outstanding
49 Debt Service Coverage Ratio
2021
2020
$
$
165,238
23,229
188,467
$
100,412
59,227
159,639
$
$
2022
$
172,422
24,032
196,453
$
104,120
61,860
165,980
28,828
(6,942)
675
22,562 $
(12,779)
$
2023
$
182,286
24,836
207,122
$
108,750
64,903
173,653
30,474
(6,665)
663
24,471 $
(13,403)
$
2024
$
192,532
25,640
218,173
$
113,962
69,001
182,962
33,468
(6,409)
651
27,711 $
(14,107)
$
2025
$
204,126
26,437
230,564
$
120,188
72,594
192,783
35,210
(8,033)
868
28,045 $
(14,832)
$
2026
$
213,105
27,295
240,400
$
125,403
76,219
201,622
37,781
(7,187)
915
31,509 $
(15,657)
$
2027
$
225,300
28,246
253,546
$
132,073
79,526
211,599
38,779
(7,194)
781
32,366 $
(16,430)
$
2028
$
238,194
29,249
267,443
$
139,339
82,631
221,970
41,947
(6,826)
843
35,965 $
(17,292)
$
2029
$
252,424
30,306
282,730
$
147,589
87,924
235,513
45,473
(10,507)
1,272
36,238 $
(18,200)
$
2030
$
266,240
31,357
297,597
$
155,313
93,456
248,769
47,217
(9,025)
1,294
39,486 $
(19,202)
$
2031
$
281,615
32,457
314,072
$
164,880
97,475
262,355
48,828
(9,296)
939
40,472 $
(20,160)
$
2032
$
294,741
33,611
328,353
$
174,956
102,836
277,792
51,717
(8,836)
960
43,841 $
(21,229)
$
2033
$
311,506
34,861
346,366
$
185,426
107,753
293,179
50,561
(8,437)
979
43,102 $
(22,335)
$
2034
$
329,224
36,115
365,340
$
197,510
113,085
310,596
53,187
(8,175)
1,050
46,062 $
(23,498)
$
$
347,953
37,447
385,400
$
210,162
118,712
328,874
54,744
(7,767)
1,115
48,093 $
(24,722)
56,526
(7,343)
1,107
50,289
(26,010)
$
9,783
$
11,068
$
13,604
$
13,213
$
15,852
$
15,936
$
18,673
$
18,039
$
20,284
$
20,312
$
22,612
$
20,768
$
22,564
$
23,370
$
24,279
$
22,091
$
22,266
$
21,239
$
21,543
$
35,473
$
24,643
$
26,648
$
28,738
$
54,802
$
30,139
$
31,536
$
31,515
$
32,761
$
36,184
$
37,059
9,783
(5,811)
(3,796)
$
175
$
22,266
18,556
3,711
11,068
(8,074)
(4,021)
$
(1,028) $
$
21,239
19,299
1,939
0.0%
$
$
$
$
$
13,604
(9,033)
(4,267)
-
$
2.0%
6,652
13,817
20,468
$
10,872
108,958
4.2
$
$
$
$
304
21,543
20,003
1,539
13,213
(19,767)
(4,816)
25,300
$
13,930
$
35,473
22,026
13,447
3.0%
8,248
14,906
23,154
$
10,869
104,937
4.4
$
$
$
$
15,852
(21,568)
(5,113)
$
$
3.0%
8,759
15,722
24,482
$
10,871
100,670
4.7
$
$
$
$
15,936
(8,507)
(5,423)
-
(10,829) $
24,643
23,209
1,434
$
3.0%
7,321
12,650
16,343
36,314
$
25,300
12,807
121,154
4.2
$
$
$
$
2,005
26,648
23,741
2,907
18,673
(10,830)
(5,753)
$
2,090
$
28,738
25,051
3,687
2.0%
8,944
12,650
17,544
39,138
$
12,811
116,041
4.7
$
$
$
$
18,039
(40,971)
(6,748)
55,744
$
26,064
$
54,802
27,286
27,516
3.0%
9,005
18,032
27,037
$
12,811
110,617
4.7
$
$
$
$
20,284
(38,784)
(6,162)
$
$
3.0%
10,351
19,237
29,588
$
12,810
104,865
5.0
$
$
$
$
20,312
(12,379)
(6,536)
-
(24,663) $
30,139
28,938
1,201
$
3.0%
10,797
27,872
20,931
59,600
$
55,744
17,079
153,861
3.9
$
$
$
$
1,397
31,536
29,002
2,534
22,612
(15,703)
(6,931)
$
$
3.0%
9,441
27,872
21,465
58,779
$
16,080
147,698
4.6
$
$
$
$
20,768
(14,633)
(4,889)
-
(21) $
31,515
29,447
2,068
$
3.0%
11,215
22,234
33,449
$
16,079
141,163
4.6
$
$
$
$
1,246
32,761
30,679
2,082
22,564
(13,934)
(5,207)
$
3,423
$
36,184
32,802
3,382
2.0%
13,347
23,851
37,198
$
16,077
134,232
4.8
$
$
$
$
23,370
(16,950)
(5,545)
$
875
$
37,059
34,781
2,278
3.0%
12,774
24,761
37,535
$
13,614
129,343
5.7
$
$
$
$
24,279
(19,815)
(5,906)
$
(1,442)
$
35,617
35,825
(209)
3.0%
11,137
25,428
36,565
$
13,614
124,136
5.9
$
$
$
$
3.0%
13,509
27,283
40,792
$
13,614
118,591
6.1
$
$
$
$
15,685
29,145
44,831
13,614
112,685
6.4
Page 2 of 2
Rochester Public Utilities
Emission Rates and Externality Cost Rates
All Scenarios
CT #1
n/a
n/a
n/a
n/a
n/a
n/a
Emsn Rt-SO2-lbs/MWH-Coal/Gas Mix
Emsn Rt-PM10-lbs/MWH-Coal/Gas Mix
Emsn Rt-CO-lbs/MWH-Coal/Gas Mix
Emsn Rt-Nox-lbs/MWH-Coal/Gas Mix
Emsn Rt-Pb-lbs/MWH-Coal/Gas Mix
Emsn Rt-CO2-lbs/MWH-Coal/Gas Mix
Emsn Rt-SO2-lbs/MWH-All Gas
Emsn Rt-PM10-lbs/MWH-All Gas
Emsn Rt-CO-lbs/MWH-All Gas
Emsn Rt-Nox-lbs/MWH-All Gas
Emsn Rt-Pb-lbs/MWH-All Gas
Emsn Rt-CO2-lbs/MWH-All Gas
Extrnlty Rt-SO2-$/ton
Extrnlty Rt-PM10-$/ton
Extrnlty Rt-CO-$/ton
Extrnlty Rt-Nox-$/ton
Extrnlty Rt-Pb-$/ton
Extrnlty Rt-CO2-$/ton
CT #2
n/a
n/a
n/a
n/a
n/a
n/a
0.01660
2.96000
1.52000
1,051.20000
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
0.01660
2.96000
1.52000
1,051.20000
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
$
$
$
$
$
$
SLP
4.84966
0.21384
0.28432
1.59879
0.00061
2,460.96981
NewCoal
0.96000
0.17000
1.44000
0.67000
0.00024
2,761.51000
Proposed CT
#3
n/a
n/a
n/a
n/a
n/a
n/a
0.01000
0.07766
0.92400
3.08000
0.00001
1,126.00000
0.96000
0.17000
1.44000
0.67000
0.00024
2,761.51000
0.01660
2.96000
1.52000
1,051.20000
848.770
0.371
72.036
508.950
2.036
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
CT #1
CT #2
SLP
SLP
NewCoal
NewCoal
NewCoal
Proposed CT #3
Proposed CT #3
Proposed CT #4
Proposed CT #6
Proposed CT #6
SMMPA
*See scenario descriptions below
0.01660
2.96000
1.52000
1,051.20000
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
Unit Description
Combined Cycle Combustion Turbine, installed
1975
Combined Cycle Combustion Turbine, installed
2002
Silver Lake Plant
Represents an ownership share in a baseload
generating faciliy
FT8 TwinPac Combustion Turbine
New Combined Cycle Combustion Turbine
LMS 100 High-Efficiency Combustion Turbine
Scenario*
All scenarios
All scenarios
All scenarios
All scenarios
1
2
4
1 and 4
2, 3, and 6
6
1 and 4
2, 3, and 6
All scenarios
Peak Period
MW Capacity
From:
SMMPA
0.48000
0.15500
3.64500
0.77000
0.00012
1,943.49500
0.14000
5.85000
0.87000
1,125.48000
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
Years available
Resource List
Unit
Proposed CT
#4
Proposed CT #6
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
To:
26
2005
2015
47
106
60
50
25
25
50
50
25
100
100
216
2005
2005
2016
2020
2025
2023
2027
2029
2025
2016
2018
2005
throughout
2015
throughout
throughout
throughout
throughout
throughout
throughout
throughout
throughout
throughout
throughout
Market
0.48000
0.15500
3.64500
0.77000
0.00012
1,943.49500
n/a
n/a
n/a
n/a
n/a
n/a
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
n/a
n/a
n/a
n/a
n/a
n/a
$
$
$
$
$
$
848.770
0.371
72.036
508.950
2.036
Rochester Public Utilities
Emissions Cost and Tonnage for Retail Sales, 30 Yr Totals
Scenario #1: No DSM
Scenario Description: Recommended expansion plan from Part IV with the forecast unaffected by demand side management
Resource
CT #1
7,421
Retail MWH's
Extrnlty Cost-SO2
Extrnlty Cost-PM10
Extrnlty Cost-CO
Extrnlty Cost-Nox
Extrnlty Cost-Pb
Extrnlty Cost-CO2
Extrnlty Cost-Total
$
$
$
$
$
$
$
Tons of Emissions-SO2
Tons of Emissions-PM10
Tons of Emissions-CO
Tons of Emissions-Nox
Tons of Emissions-Pb
Tons of Emissions-CO2
52
4
406
7,941
8,403
CT #2
198,720
$
$
$
$
$
$
$
0.1
11.0
5.6
-
1,400
109
10,879
212,634
225,022
SLP
2,316,569
$
$
$
$
$
$
$
1.6
294.1
151.0
-
210,228
122
133,400
357
5,803,055
6,147,162
NewCoal
3,899,082
$
$
$
$
$
$
$
5,617.3
247.7
329.3
1,851.9
0.7
-
281,301
1,040
94,093
239
10,960,090
11,336,763
Proposed CT
#3
321,433
Proposed CT
#4
Proposed CT #6
1,185,446
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,871.6
331.4
2,807.3
1,306.2
0.5
-
2,264
176
17,598
343,938
363,977
2.7
475.7
244.3
-
-
$
$
$
$
$
$
$
-
70,432
1,285
37,147
1,358,078
1,466,942
SMMPA
51,607,107
$
$
$
$
$
$
$
83.0
3,467.4
515.7
-
3,394,699
34,858
1,431,264
1,580
102,093,492
106,955,893
Market
1,331,414
$
$
$
$
$
$
$
12,385.7
3,999.6
94,054.0
19,868.7
3.1
-
87,580
899
36,925
41
2,633,914
2,759,360
Grand Total
60,867,193
$
$ 4,047,956
$
38,495
$ 1,761,713
$
2,216
$ 123,413,142
$ 129,263,522
319.5
103.2
2,426.5
512.6
0.1
-
20,194.1
4,769.2
103,865.4
24,456.0
4.4
-
Market
1,011,076
66,508
683
28,041
31
2,000,196
2,095,459
Grand Total
54,689,854
$
$ 3,620,446
$
35,686
$ 1,574,181
$
1,881
$ 109,103,288
$ 114,335,481
242.7
78.4
1,842.7
389.3
0.1
-
16,754.2
4,265.5
96,287.3
21,852.7
3.7
-
Rochester Public Utilities
Emissions Cost and Tonnage for Retail Sales, 30 Yr Totals
Scenario #2: Aggressive DSM, Coal & Gas Mix
Scenario Description: Recommended plan adjusted by using the aggressive demand side management results with SLP operating on coal and adjustments to the new resources
CT #1
Resource
Retail MWH's
Extrnlty Cost-SO2
Extrnlty Cost-PM10
Extrnlty Cost-CO
Extrnlty Cost-Nox
Extrnlty Cost-Pb
Extrnlty Cost-CO2
Extrnlty Cost-Total
Tons of Emissions-SO2
Tons of Emissions-PM10
Tons of Emissions-CO
Tons of Emissions-Nox
Tons of Emissions-Pb
Tons of Emissions-CO2
CT #2
140,248
175
$
$
$
$
$
$
$
1
0
10
187
198
0.0
0.3
0.1
-
$
$
$
$
$
$
$
988
77
7,678
150,068
158,811
1.2
207.6
106.6
-
SLP
1,651,836
$
$
$
$
$
$
$
149,904
87
95,121
255
4,137,884
4,383,251
4,005.4
176.6
234.8
1,320.5
0.5
-
NewCoal
1,422,649
$
$
$
$
$
$
$
102,638
380
34,331
87
3,998,981
4,136,417
682.9
120.9
1,024.3
476.6
0.2
-
Proposed CT
#3
218,631
Proposed CT
#4
Proposed CT #6
981,553
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,540
120
11,969
233,939
247,568
1.8
323.6
166.2
-
-
$
$
$
$
$
$
$
58,318
1,064
30,758
1,124,493
1,214,632
68.7
2,871.0
427.0
-
SMMPA
49,263,686
$
$
$
$
$
$
$
3,240,549
33,275
1,366,272
1,508
97,457,540
102,099,145
11,823.3
3,817.9
89,783.1
18,966.5
3.0
-
$
$
$
$
$
$
$
Rochester Public Utilities
Emissions Cost and Tonnage for Retail Sales, 30 Yr Totals
Scenario #3: Aggressive DSM, All Gas
Scenario Description: Recommended plan adjusted by using the aggressive demand side management results with SLP operating on natural gas and the coal unit replaced with gas-fired capacity
CT #1
Resource
Retail MWH's
CT #2
140,248
175
Extrnlty Cost-SO2
Extrnlty Cost-PM10
Extrnlty Cost-CO
Extrnlty Cost-Nox
Extrnlty Cost-Pb
Extrnlty Cost-CO2
Extrnlty Cost-Total
$
$
$
$
$
$
$
1
0
10
187
198
Tons of Emissions-SO2
Tons of Emissions-PM10
Tons of Emissions-CO
Tons of Emissions-Nox
Tons of Emissions-Pb
Tons of Emissions-CO2
$
$
$
$
$
$
$
0.0
0.3
0.1
-
988
77
7,678
150,068
158,811
SLP
2,101,143
$
$
$
$
$
$
$
1.2
207.6
106.6
-
69,249
360
233,091
3
2,408,236
2,710,939
-
Proposed CT
#3
265,579
Proposed CT
#4
Proposed CT #6
200,745
1,110,130
-
$
$
$
$
$
$
$
$
$
$
$
$
$
$
NewCoal
$
$
$
$
$
$
$
10.5
81.6
970.7
3,235.8
0.0
-
-
1,871
146
14,540
284,174
300,731
2.2
393.1
201.8
-
1,414
110
10,990
214,800
227,315
$
$
$
$
$
$
$
1.7
297.1
152.6
-
65,957
1,203
34,787
1,271,794
1,373,741
SMMPA
49,263,686
$
$
$
$
$
$
$
77.7
3,247.1
482.9
-
3,240,549
33,275
1,366,272
1,508
97,457,540
102,099,145
Market
1,387,061
$
$
$
$
$
$
$
11,823.3
3,817.9
89,783.1
18,966.5
3.0
-
91,240
937
38,469
42
2,744,000
2,874,688
Grand Total
54,468,767
$
$ 3,471,270
$
36,108
$ 1,705,836
$
1,553
$ 104,530,799
$ 109,745,567
332.9
107.5
2,527.9
534.0
0.1
-
12,166.7
4,089.8
97,426.8
23,680.3
3.1
-
Market
1,090,275
71,718
736
30,238
33
2,156,872
2,259,598
Grand Total
55,613,517
$
$ 3,681,721
$
36,187
$ 1,602,204
$
1,922
$ 111,084,950
$ 116,406,984
261.7
84.5
1,987.0
419.8
0.1
-
17,157.5
4,337.7
97,638.7
22,241.7
3.8
-
Rochester Public Utilities
Emissions Cost and Tonnage for Retail Sales, 30 Yr Totals
Scenario #4: Normal DSM, Coal & Gas Mix
Scenario Description: Recommended plan adjusted by using the normal demand side management forecast with SLP operating on coal and adjustments to the new resources.
Resource
CT #1
Retail MWH's
Extrnlty Cost-SO2
Extrnlty Cost-PM10
Extrnlty Cost-CO
Extrnlty Cost-Nox
Extrnlty Cost-Pb
Extrnlty Cost-CO2
Extrnlty Cost-Total
Tons of Emissions-SO2
Tons of Emissions-PM10
Tons of Emissions-CO
Tons of Emissions-Nox
Tons of Emissions-Pb
Tons of Emissions-CO2
CT #2
112,756
531
$
$
$
$
$
$
$
4
0
29
568
601
0.0
0.8
0.4
-
$
$
$
$
$
$
$
794
62
6,173
120,650
127,680
0.9
166.9
85.7
-
SLP
1,718,855
$
$
$
$
$
$
$
155,985
91
98,981
265
4,305,767
4,561,089
4,167.9
183.8
244.4
1,374.0
0.5
-
NewCoal
1,663,208
$
$
$
$
$
$
$
119,993
444
40,137
102
4,675,180
4,835,856
798.3
141.4
1,197.5
557.2
0.2
-
Proposed CT
#3
285,682
Proposed CT
#4
Proposed CT #6
1,035,546
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,013
157
15,640
305,684
323,494
2.4
422.8
217.1
-
-
$
$
$
$
$
$
$
61,526
1,123
32,450
1,186,349
1,281,446
72.5
3,029.0
450.5
-
SMMPA
49,706,665
$
$
$
$
$
$
$
3,269,688
33,575
1,378,558
1,521
98,333,879
103,017,221
11,929.6
3,852.3
90,590.4
19,137.1
3.0
-
$
$
$
$
$
$
$
Rochester Public Utilities
Emissions Cost and Tonnage for Retail Sales, 30 Yr Totals
Scenario #5: Normal DSM, All Gas
Scenario Description: Recommenced plan adjusted by using the normal demand side management forecast with SLP operating on natural gas and the coal unit replaced with gas-fired capacity
Resource
CT #1
Retail MWH's
Extrnlty Cost-SO2
Extrnlty Cost-PM10
Extrnlty Cost-CO
Extrnlty Cost-Nox
Extrnlty Cost-Pb
Extrnlty Cost-CO2
Extrnlty Cost-Total
Tons of Emissions-SO2
Tons of Emissions-PM10
Tons of Emissions-CO
Tons of Emissions-Nox
Tons of Emissions-Pb
Tons of Emissions-CO2
CT #2
167,555
531
$
$
$
$
$
$
$
4
0
29
568
601
0.0
0.8
0.4
-
$
$
$
$
$
$
$
1,180
92
9,173
179,286
189,732
1.4
248.0
127.3
-
SLP
2,250,599
$
$
$
$
$
$
$
74,175
385
249,671
3
2,579,536
2,903,770
11.3
87.4
1,039.8
3,465.9
0.0
-
-
Proposed CT
#3
283,254
Proposed CT
#4
Proposed CT #6
215,265
1,203,823
-
$
$
$
$
$
$
$
$
$
$
$
$
$
$
NewCoal
$
$
$
$
$
$
$
-
1,995
155
15,507
303,086
320,744
2.4
419.2
215.3
-
1,516
118
11,785
230,338
243,757
1.8
318.6
163.6
-
$
$
$
$
$
$
$
71,524
1,305
37,723
1,379,131
1,489,683
84.3
3,521.2
523.7
-
SMMPA
49,706,665
$
$
$
$
$
$
$
3,269,688
33,575
1,378,558
1,521
98,333,879
103,017,221
11,929.6
3,852.3
90,590.4
19,137.1
3.0
-
Market
1,532,831
$
$
$
$
$
$
$
100,829
1,035
42,511
47
3,032,374
3,176,797
Grand Total
55,360,523
$
$ 3,520,912
$
36,666
$ 1,744,958
$
1,571
$ 106,038,198
$ 111,342,305
367.9
118.8
2,793.6
590.1
0.1
-
12,308.7
4,148.3
98,931.5
24,223.4
3.1
-
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