6.3. ERMUSR 10-09-2007'~Ji
Elk River -~
Municipal Utilities
13069 Orono Parkway • P.O. Box 430
Elk River, MN 55330-0430
October 1, 2007
To: Elk River Municipal Utilities Commission
Jerry Takle
Jerry Gumphrey
Jim Tralle
From: Bryan Adams
Subject: Renewable Energy Project
~''>>one: 763.441.2020
w Fax: 763.441.8099
The Elk River Municipal Utilities is considering two renewable energy products. They are the
expansion of LFG to electric generation facility at the landfill and add generators to the Lake
Orono dam. Both projects require significant permitting efforts and costs. Attached is the
following information for your review.
1) Email dated September 4, 2007 addressing the SOZ emission from the Elk River Landfill.
As you recall, we are experiencing high maintenance costs on the existing engines at the
landfill because 4 to 6 wells have high sulfur content. One solution may be to plumb
these 4 to 6 wells directly to a new or existing flair and by-pass the engines. This may
cause some SOZ allowance issues.
2) Propose to secure the air permit to expand the existing LFG facility by another 8 engines.
The projected costs are in the $25,000 to $1,000.000 range. For a point of interest, a 4
engine LFG facility will cost approximately $4,000,000 to construct without permitting
costs.
3) Lake Orono Dam Assessment Report dated September 2007. From this report the
permitting costs far exceed the costs to do the construction.
The reason for this memo is to make the point that although renewable energy is given high
priority, permitting these projects is still very difficult. There will be a lot of wind energy
installed because the ease of permitting.
Adams, Bryan
From: Paul Taylor [ptaylor@barr.com]
Sent: Tuesday, September 04, 2007 4:46 PM
To: Walters, Debra; Adams, Bryan
Cc: Stolz, Stephanie; Ken.Kruszynski@shawgrp.com
Subject: Elk River Landfill: Implications for Routing LFG from High H2S Wells to Existing Flare
Sensitivity: Confidential
DebBryan:
Following up on our phone call this morning, you had prompted me to check whether there is a SO2 limit on ERL's flare that would
be in danger of being exceeded by the proposed routing of LFG from high H2S wells to the existing flare. I checked ERL's current
permit and there is no such limit.
However, there is a 0.5 Ib/MM Btu limit on each engine. This raises the question of whether this limit is being exceeded by the current
operation. Based on the individual well flow rates that you provided during my 5/11/07site visit and the H2S measurements made in
June (using Draeger tubes for 7 high H2S wells and canister results from one of these wells), I calculate that the SO2 emissions from
the LFG collected from all wells and fed to the engines averages out to be 0.3 lb/MM Btu, below the 0.5 Ib/MM Btu limit. In other
words, there appears to be sufficient low H2S LFG to offset the high H2S wells such that the SO2 limit on each engine will not be
exceeded. It should also be noted that the permit does not require testing of SO2 emissions from the engines provided they only
combust LFG.
Using the same data, I estimate that the 7 high H2S wells would produce 74 tons SO2/yr assuming complete combustion of the H2S
while the other wells would collectively produce an additional 6 tons/yr. It's not clear how the MPCA would view these high SO2
emissions but there's a good chance that they will be concerned about them (the permit does not require SO2 testing for the engines
because it is assumed that SO2 emissions will be low from combusting LFG).
Stephanie provided a spreadsheet this afternoon that included H2S and flow data from March 2007 and some H2S data for selected
wells in May/June and August 2007. The latter included H2S data from 2 high H2S wells (EW-23 and EW-43) that were not known to
me previously. Stephanie has promised to send more comprehensive H2S and flow data that will allow me to refine the calculations
presented above.
Ken: I believe it was your colleague (another Ken!) who called me last Friday to discuss the air permitting implications of routing the
high H2S wells to the existing flare. Could you please forward this a-mail to him and ask that he send me his contact details for the
future. Thanks.
Paul Taylor
Air Quality Engineer
Barr Engineering Company
4700 West 77th Street
Minneapolis, MN 55435-4803
Tel: 952-832-2671 (direct)
Fax:952-832-2601
e-mail: ptaylor~a,barr.com
This e-mail and files transmi[ted with it are the property of Barr Engineering Company, are confidential and are intended solely for the use of the individual or entity to whom this
e-mail is addressed. /jyou are not one of the named recipients or believe tha[ you have received this message in error, please nat~ the sender and delete [his message from your
computer. Any other use, retention, dissemination, forwarding, printing or copying of this e-mail is prohibited.
Adams, Bryan
From: Paul Taylor [ptaylor@barr.com]
Sent: Friday, September 14, 2007 12:11 PM
To: Adams, Bryan; Walters, Debra
Subject: Elk River: Draft Proposal for Air Permitting of Second LFG-to-Energy Plant
Attachments: Proposa12007-09-14.doc
Bryan/Deb:
Please find attached a draft proposal for the project referenced above. This is an edited version of the proposal I e-mailed 7/3/07,
updated to reflect the revised project (the 7/3/07 proposal assumed the addition of 2 engines; the attached proposal assumes the
addition of up to 8 engines).
Note that the cost of preparing the permit application (Task 1) remains unchanged at $5,000. However, I have reduced the cost
associated with the AERA (Task 2) by reducing the scope to simply preparing for and attending a meeting with the MPCA. Given our
recent experience with the Spruce Ridge landfill, I believe this is the most appropriate way to proceed. As stated in the proposal, I
would prepare afollow-up cost estimate after the meeting with the MPCA once the scope of work is better defined. By the time we're
all done, I wouldn't be surprised if the cost reaches $25,000.
Also note that the proposal assumes that the proposed project will not trigger federal PSD permitting. I believe this is a reasonable
assumption for the reasons stated in the proposal. However, if it turns out that PSD is triggered, the costs will skyrocket (we're talking
at least $100,000 and many PSD projects reach $1,000,000).
Please review the attached and let me know if anything is unclear. I will then finalize the letter and put a hard copy in the mail.
Thanks.
Paul Taylor, Ph.D.
Air Quality Engineer
Barr Engineering Company
4700 West 77th Street
Minneapolis, MN 55435-4803
Tel: 952-832-2671 (direct)
Fax: 952-832-2601
e-mail: pta~r(c~,barr.com
This e-mail and files transmitted with it are the property of Barr Engineering Company, are confidential and are intended solely jor the use of the individual or entity to whom this
e-mail is addressed. If you are not one of the named recipients or believe that you have received this message in error, please notes the sender and delete this message from your
computer. Any o[her use, retention, dissemination, forwarding, printing or copying ojthis e-mail is prohibited.
September 14, 2007
Mr. Bryan Adams
Elk River Municipal Utilities
422 King Avenue
Elk River, MN 55330
Re: Proposal for Air Quality Services Related to the Installation and Operation of a Second
Landfill Gas (LFG)-to-Energy Plant at Waste Management's Elk River Landfill.
Dear Mr. Adams:
In response to your telephone request of September 4, 2007, I am pleased to submit an updated version of
our July 3, 2007 proposal for air quality services for the Elk River Municipal Utilities (ERML7) and the Elk
River Landfill (ERL).
Background
Waste Management Inc. (WMI) currently operates four Caterpillar 3516 engines in aLFG-to-Energy Plant
located at the Elk River Landfill. The first three engines were permitted in 2001 and began operation in
November 2002. The fourth engine received a moderate permit amendment in 2006 (air permit
141000041-004, issued January 18, 2006) and began operation in July 2006.
To process landfill gas expected to be generated by a significant expansion of the landfill to the south,
WMI intends to install a second LFG-to-Energy Plant that will initially house four additional engines but
will be built to accommodate up to eight engines. Each new engine will be identical to the those in place in
the existing LFG-to-Energy Plant.
There are several regulatory thresholds that could drive the air permitting of the second LFG-to-Energy
Plant:
NSR-PSD (40 CFR 52.21)
The federal New Source Review (NSR) -Prevention of Significant Deterioration (PSD) program requires
that the emissions of certain regulated pollutants from a proposed project be quantified and compared to
threshold values. Since (i) the existing landfill is not a "major stationary source" under NSR and (ii) MSW
landfills are not listed in 40 CFR 52.21(b)(1)(i)(a), the threshold of concern is 250 tons/yr of CO, NOx,
PM, PM10, S02, VOC, Lead, NMOC etc. The PSD rules specify the calculation methods that must be
used to estimate emissions for comparison to the thresholds.
EAW (Minn. R. 4410.1000)
The most likely threshold for a mandatory Environmental Assessment Worksheet (EAW) is 250 tons/year
of any single air pollutant, after installation of air pollution control equipment, per Minn. R. 4410.4300,
subpart 15.
Mr. Bryan Adams
September 16, 2007
Page 2
AERA (MPCA policy)
The most likely threshold for the MPCA requiring the preparation of an Air Emissions Risk Analysis
(AERA) is 100 tons/year of any single air pollutant, after installation of air pollution control equipment.
Based on our recent experience permitting identical engines at WMI landfills located in Elk River,
Glencoe and Lake Mills, the pollutants with the highest emissions will be CO (with potential emissions of
between 31 and 35 tons/year per engine) and NOx (with an emission rate of between 15 and 22.5 tons/year
per engine). For eight additional engines, we would therefore expect the total CO emissions to be between
248 and 280 tons/year and the NOx emissions to be between 120 and 180 tons/year. The NOx emissions
from the proposed project are below the PSD and EAW thresholds but above the AERA threshold. The
lower bound CO emissions from the proposed project are just barely below the PSD and EAW thresholds
but above the AERA threshold. We suspect that WMI could be comfortable arguing for and accepting a
CO emission rate that will keep the project emissions below the PSD threshold of 250 tons/yr.
Because the proposed project is occurring only one year after the construction of the fourth engine, it is
possible that the MPCA will consider the two projects to be a "phased action" as defined in Minn. R.
4410.0200, subpart 60 and as explained further on page 3 of the EQB's Guide to Minnesota
Environmental Review Rules. You may remember that, when permitting the fourth engine, we considered
that project and the installation of the first three engines to have been a "phased action". However, since
the purpose of the second LFG-to-Energy Plant is to process landfill gas expected to be generated by a
landfill expansion that was not foreseen at the time that the fourth engine was permitted, we think there is a
strong argument that the proposed project is unrelated to the first LFG-to-Energy Plant and would propose
to proceed on that basis.
You may recall that considerable effort was made in 2005 to prepare an AERA and its associated Risk
Assessment Spreadsheet (RASS) for the ERL facility as part of the air permitting of the fourth engine. The
RASS produced risks that narrowly exceeded the risk guidelines but were considered acceptable by the
MPCA risk managers. Since then, we have been working with the MPCA to permit aLFG-to-Energy Plant
at Glencoe that will house four engines. For that project, the MPCA is proposing to require stack testing of
certain air toxics and we anticipate that the MPCA will very likely require similar testing of any future
LFG-to-Energy plants. The implications resulting from such testing are unknown at this time and cannot be
known until the LFG-to-Energy Plant at Glencoe is constructed and tested.
Based on the limited emission factor data available, we do not believe that the project will be a major
source of hazardous air pollutants (HAPs). However, it is possible that MPCA-required stack testing or
alternative emission calculation approaches imposed by the MPCA could alter this conclusion. For
example, the Iowa DNR recently rejected the standard calculations that have been used at all of WMI's
Minnesota and Iowa landfills and somewhat arbitrarily assumed that the Lake Mills landfill is a major
source of the HAP formaldehyde.
Finally, it should be noted that, with the installation of the second LFG-to-Energy Plant, the post-project
facility will qualify as a "major source" under NSR. This is important because any future projects will be
subject to a PSD threshold of 40 tons/year, rather than 250 tons/year.
Scope of Work
Barr will perform the following tasks:
Mr. Bryan Adams
September 16, 2007
Page 3
Permit Application
• Revise ERL's existing spreadsheet to calculate the potential emissions of criteria pollutants and
hazardous air pollutants (HAPs) for the proposed project.
• Determine which type of permit amendment (insignificant, minor, moderate or major) is applicable
to the proposed modification. To a great extent this depends on the calculated emission rates and
the applicability of various state and federal regulations.
• Complete the required MPCA permit amendment application forms.
• Submit the draft permit amendment application to ERMU, ERL and WMI for review and
comment.
• Prepare a final permit amendment application by making one round of revisions to the draft
application based on comments received following ERMU, ERL and WMI review.
AERA
• Meet with the MPCA risk assessment staff to negotiate a mutually acceptable approach to address
the AERA program.
It is assumed that the proposed project will not exceed either the PSD or EAW thresholds. For the
AERA/RASS, it is possible that the meeting with the MPCA may result in more refined air dispersion
modeling being needed. Once the AERA scope of work is defined, a refined cost estimate can be provided
for that task.
Schedule
We anticipate that it will take no more than six weeks to prepare the draft permit amendment application.
The schedule for the AERA/BASS work will depend on the outcome of the meeting with the MPCA risk
assessment staff. For that reason, we recommend scheduling that meeting as soon as possible.
Once the draft submittal(s) has (have) been prepared, we estimate an additional two weeks to prepare the
final submittal(s), allowing adequate review time for ERMU, ERL and WMI personnel.
Cost
As shown in Table 1, we anticipate that the cost of preparing the permit amendment application will be
approximately $5,000. The cost of the AERA work, as scoped above, is $1,200, which includes the cost of
one Barr representative preparing for and attending the meeting with the MPCA at which the scope of
work required by the MPCA for this project will be better defined.
Table 1: Cost Estimate
Task Cost $
1. Permit Application Prepare emission calculation spreadsheet and permit
a lication forms 5,000
2. AERA Prepare emission calculation spreadsheet and attend meeting
with MPCA risk mana ers 1,200
Total: 6,200
Mr. Bryan Adams
September 16, 2007
Page 4
Project Team
Barr's Principal in Charge for this project will be Tim Russell. Tim will be responsible for client relations
and contractual matters and will be available as needed to discuss the project and Bazr's performance. Paul
Taylor will be the project manager and will perform the work, with assistance from Matt Peters.
We look forward to working with you on this project in the near future. If any item discussed in this
proposal does not meet your needs, or if you have any questions, please call me at 952-832-2671.
Sincerely,
Paul Taylor
Project Manager
c: Ms. Deb Walters, Elk River Landfill
W:IBUSINESS UNITS\EM\PROPOSALS\2007\13 MPLS17044 ELK RIVER MUNICIPAL UTIL\PROPOSAL 2007-09-14.DOC
Lake Orono Dam Assessment Report
Prepared for
Elk River Municipal Utilities
Elk River, Minnesota
September 2007
Lake Orono Dam Assessment Report
Prepared for
Elk River Municipal Utilities
Elk River, Minnesota
September 2007
4700 West 77th Street
Minneapolis, MN 55435
BAR R Phone: (952) 832-1600
Fnx: (952) 832-2601
Lake Orono Dam Assessment Report
Table of Contents
1.0 Introduction ...................................................................................................................................... 1
2.0 Relicensing Process ......................................................................................................................... 2
3.0 Assessment of Generation Capability ..............................................................................................4
4.0 Economic Factors ............................................................................................................................. 5
4.1 Evaluation of Net Present Worth and Revenue .................................................................. 6
5.0 Summary and Conclusion ................................................................................................................7
Appendices
Appendix 2-1 FERC, Obtaining an Exemption from Licensing
Appendix 2-2 Tables of Contents
Appendix 3-1 Potential Generation Spreadsheets
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1.0 Introduction
Elk River Municipal Utilities is considering redevelopment of hydroelectric generation at the Lake Orono
Dam project. The Lake Orono Dam formerly generated electricity. It has been reported that the
powerhouse formerly had two 150-KW generating systems. When the dam was rehabilitated in the early
1980s, all of the equipment was removed and the powerhouse intakes and outlets were filled with
concrete. Presently the dam impounds water that creates Lake Orono that is a valuable regional resource.
This report presents the results of a preliminary evaluation of issues related to redevelopment of
hydroelectric generation. Redevelopment of hydroelectric facilities requires an economically viable site
and careful attention to the permitting issues. The following sections present the results of preliminary
assessment of the following categories:
• Relicensing Process
• Assessment of Generation Capability
• Economic Factors
• Summary and Conclusion
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2.0 Relicensing Process
Licensing of a hydroelectric generating plant is primarily regulated by the Federal Energy Regulatory
Commission (FERC). As stated in FERC's Hydroelectric Project Licensing Handbook, "Under the
authority of the Federal Power Act, as amended by the Electric Consumers Protection Act, the Federal
Energy Regulatory Commission (FERC) has responsibility of issuing licenses for nonfederal
hydroelectric powerplants." The handbook goes on to say, "FERC regulations provide two procedural
alternatives for developing hydropower projects. First a developer may, as an initial step, seek a
preliminary permit. A permit allows the developer time to perform feasibility studies while maintaining
priority to file a later application for a license. Alternatively, since a preliminary permit is not a
prerequisite, a developer may file directly for a license or an exemption without requesting a preliminary
permit."
Review of the FERC handbook indicates that based on the project site it would be appropriate to file for
an exemption from a license at the site. Conservations with Dana Gauthier, Minnesota Department of
Natural Resources Dam Safety, and Ed Abrams, FERC Licensing Washington DC, indicated a FERC
license or possibly an exemption are required to develop the site. FERC staff also indicated that, in order
to file and secure a license, the developer (Elk River Municipal Utilities) needs to have, among other
items, rights to the water, must own the lands on which the project is located, and have a means for power
transmission. Ownership of the lands must be clarified to determine if this is meant to be the land that the
dam, generating, and transmission facilities are located or if this means the entire land around the
impoundment. The issue of land ownership can be determined early in the licensing process. Copies of
the current section titled, Obtaining an Exemption from Licensing, by FERC is included as Appendix 2-1.
Ed Abrams indicated that among a large list of issues the licensing process is very dependent on site-
specific conditions and the other regulatory concerns such as the presence of rare and endangered species,
fish and other aquatic species migration, and water and water quality. He indicated that the licensing and
exemption process can take from 18 months to well over 24 months to complete. The cost of relicensing
is dependent upon the number of studies that need to be completed as part of the process. While the
FERC is responsible for licensing hydroelectric projects, they will seek input from state and federal
agencies and other stakeholders. Because the position of the agencies regarding development of
hydroelectric generation is a critical part of the licensing process and ultimately the cost to obtain a
license, Elk River Municipal Utilities should consider developing a letter that could be sent to all of the
likely state and federal agencies that would be a stakeholder in the process indicating that the Utility is
considering redevelopment of hydroelectric generation at the Lake Orono Dam site and is seeking
feedback regarding possible issues related to the redevelopment. Alternatively, an invitation to a meeting
could also be included to discuss the possible redevelopment. Responses to the letter or meeting would
provide an initial assessment of the difficulty or ease of the licensing process.
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Based on our recent experience with the relicensing of a hydroelectric facility in Michigan, it is estimated
that the process could cost between $500,000 and $2,000,000. The actual costs will be highly dependent
upon the position of the stakeholders and the studies that are required.
Attached as Appendix 2-2 are the table of contents and some selected sections from a Draft License
Application for Minor Water Power Project, Minnesota Falls Hydroelectric Project, FERC Project No.
10336-00 and Initial Consultation Package Orienta Hydro Project FERC Project No. 10781-00.
The City of Granite Falls held the preliminary permit for the Minnesota Falls dam at the time the draft
license application was submitted. Dahlberg Light and Power Company was seeking the preliminary
permit when the initial consultation package was submitted. These two documents provide examples of
the level of effort that was required for these two projects and might represent the level of effort required
for the Lake Orono Dam.
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3.0 Assessment of Generation Capability
The United States Geological Study (USGS) has maintained a stream flow gaging station on the Elk
River near Big Lake, Minnesota. The station number is 0527500. Information from this gage location
has been collected since 1911. The drainage area at the gaging station is 615.00 square miles. The
drainage area at Lake Orono is reported to be 640 square miles.
An evaluation of potential generation was completed based on several different capacity generating units.
Table 2-1 presents the installed capacity and potential generation without adjustments for availability.
The availability factor represents an assumption regarding the overall availability of the site when
considering low flow, maintenance, and other possible plant shutdown periods. An assumed availability
factor of 0.8 has been applied to the yearly generation to determine the adjusted yearly generation.
The analysis was completed based on average daily discharge, adjusted for the difference in drainage area
between the gaging station and the dam, and limits based on capacity of the generating unit(s). Once
stream flow exceeded the generating capacity, water would be spilled through the tainter gates or over the
spillway while maintaining the maximum generation capacity. Copies of the excel spreadsheets that were
used to evaluate the potential generation are included as Appendix 3-1.
Table 3-1
Summary of Generation
Generator Capacity
(KW) Yearly Generation
(KW-hr) Adjusted Yearly Generation
(i(11V-hr)
180 1,491, 000 1,193, 000
200 1, 619, 000 1, 295, 000
300 2,011,000 1,609,000
400 2,265,000 1,812,000
All 2,588,000 2,070,000
Using the value of power ($0.04/KW-hr), the value of the average annual generation varies from about
$50,000 to $95,000 depending upon the installed capacity and site availability.
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4.0 Economic Factors
Economic factors will be the overriding issue to determine the viability of the project. Development of
hydropower is capital intensive to license, permit, and build the project. Once the project is completed
and online, the ongoing operation and maintenance costs are minimal. Like wind power and landfill gas,
the fuel is essentially free. However, the availability of the fuel to run the plant is generally outside of the
Utilities' direct influence. The power plant would be run-of--river with a very narrow operating band on
the headwater. Once the project is constructed and operational, power will be generated when water is
available. Detailed costs for dam improvements and generating equipment have not been completed for
this report. However, previous assessment of the equipment was completed by Elk River Municipal
Utilities. Review of the costs indicates that they are on the low side. Based on our initial assessment of
the project, we have developed a cost summary that is presented as Table 4-1 below. Values that were
included in the ERMU cost estimate were based on the Engineering New Record (ENR) cost indices from
2000 to present. The cost of the turbine generator, electric feeder, switchgear, and to modify the
discharge and riprap were increased for the upper bound value based on a ratio of the highest generation
capacity/lowest generation capacity. Engineering was assumed to be 8% of construction. A contingency
of 25% was added to the estimated total cost of permitting and construction.
Table 4-1
Cost Summary
Estimated Cost
Item Description Lower Bound Upper Bound
Permitting 1 Preliminary Filing to FERC $20,000 $50,000
2 Engineering Through RFQ $150,000 $250,000
3 Environmental Studies $500,000 $2,000,000
4 Follow-up Studies $80,000 $150,000
Subtotal Permitting $750,000 $2,450,000
Construction 5 Trash Racks * $25,000 $38,000
6 Clear Draft Tube " $65,000 $100,000
7 Modify Deck $30,000 $50,000
8 Modify Discharge and Riprap $95,000 $210,000
9 Turbine Generator $125,000 $280,000
10 Electric Feeder $30,000 $70,000
11 Switch Gear $30,000 $70,000
12 Engineering & Inspection (8%) $32,000 $65,000
Subtotal Construction Cost $432,000 $883,000
Subtotal $1,182,000 $3,333,000
Contingency (25%) $295,000 $833,000
Total $1,477,000 $4,166,000
'` Source of cost is ERMU Cost Estimate 1/18/00
"'` Estimated to be in the range of
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4.1 Evaluation of Net Present Worth and Revenue
Section 3 (Assessment of Generation Capability) estimates, based on a range of capacity of generating
units, that the annual revenue as $0.04/Kw-hr is between $50,000 and $95,000. Operations were assumed
to require on average 10 hours per week for one person. Assuming 25% time and an estimated annual
cost of $60,000, the annual operating costs would be $15,000. Additional operating cost to run the
facility would be required but this may be accomplished without adding any other additional staff.
Adjusting the annual revenue by deducting $15,000 from the estimated revenues would result in an
estimated annual net revenue of $35,000 to $80,000, respectively for the upper and lower estimates. The
net present worth of this revenue based on a 5% annual interest rate and a 20-year period is approximately
$450,000 and $1,000,000, respectively. The range of net present worth of this revenue over a period of
40 years is $600,000 to $1,370,000, since it is not uncommon for hydropower facilities to have a lifespan
greater than 40 years. This assessment provides an initial estimate of the limits of the current investment
to break even over a 20-year period and a 40-year period, respectively.
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5.0 Summary and Conclusion
Redevelopment of the Lake Orono Dam is dependent upon the requirements of state, federal, and local
agencies, the cost of studies and construction, and the revenue the project can develop as well as the
desire of the Elk River Municipal Utilities to redevelop the project. While the current sentiment is for
renewable energy, regulations of water-based structures including dams and hydroelectric activities can
be a detriment in the process. Two hydroelectric projects are currently in process for development in the
city of Minneapolis. One is the Crown Mill site, located on the right bank adjacent to the St. Anthony
Falls, Upper Lock and the other is the Lower St. Anthony Falls site, located on the left bank and to the
left of the Lower St. Anthony Falls Lock and Dam. Both sites are located on the Mississippi River.
Water rights differ between the two sites that will impact the volume of water that is available for
generation. The upper Crown site has about 50 feet of head while the lower St. Anthony Falls site has
about 25 feet of head. Neither site has an existing powerhouse or any other generation equipment.
Development within the city of Minneapolis can be challenging, the Crown site has been in the
development process for over a decade and the lower dam site has been idle since 1985 when the dam
failed. These sites have favorable head (50 feet and 25 feet) and flow but still remain undeveloped-
indicating the difficultly with the overall process.
Development of Lake Orono for hydroelectric generation will be costly and may not have favorable
economic factors. A preliminary net present worth of the annual revenue from generation ranges from
$500,000 to $1,000,000 using an annual interest rate of 5% for a period of 20 years, and $600,000 to
$1,370,000 for a period of 40 years. The range of estimated costs to permit and construct the project is
$1,477,000 to $4,166,000. This initial cost estimate and assessment of revenue shows that the project will
not provide a 20-year return on investment. These revenues and costs are highly variable and may change
over time. The revenue/cost comparisons are meant to provide anorder-of-magnitude comparison. If
hydroelectric development at the Lake Orono Dam remains of interest to Elk River Municipal Utilities,
the following are recommended:
• Send a letter to the local, state, and federal stakeholders seeking their input regarding
development of hydropower at the Lake Orono Dam.
• Complete a Phase 1 inspection to determine the condition of the facilities and suitability for
development.
• Refine the selection of the turbine generator capacity/output.
• Evaluate optional turbine generator supplies to better determine cost and required site
modifications.
• Revise the economic assessment to consider the revenue per Kw-hr and an annual interest rate for
the capital expenditures.
• Reassess the estimated cost and revenue.
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