HomeMy WebLinkAboutX-A-01 (a,b) Hydroelectric Plant City Council Memorandum
To: Mayor Fasbender & City Council Members
From: Ryan Stempski, P.E. – Public Works Director
Date: January 5, 2026
Item: Authorize Signature of Letter of Intent and Consider Resolution Regarding Disposal and Sale of the
Hydroelectric Plant
COUNCIL ACTION REQUESTED
Council has been requested to authorize signature of the attached Letter of Intent with J.F. Brennan Company, Inc.
regarding the terms of sale of the Hydroelectric Plant. Additionally, the Council has been requested to consider
adopting the enclosed resolution regarding the disposal and sale of the Hydroelectric Plant to comply with Section
7.04 of the City Charter.
BACKGROUND
The Hydroelectric Plant is an aging facility and cost projections to continue to own and maintain the facility are not
fiscally responsible to the taxpayers in Hastings.
Several meetings over the past two years have been held regarding this subject to provide information and obtain
directions including Utilities Committee Meetings, City Council Workshops, and City Council Meetings.
A Public Hearing was conducted at the December 15th City Council Meeting, and no public comments were received.
NEXT STEPS
J.F. Brennan Company, Inc. is a marine construction firm specializing in environmental remediation, dam construction,
commercial diving, harbor management and submarine cable services. They have provided a Letter of Intent that
outlines the terms of sale, which has been reviewed by the City Attorney:
· Purchase price is $1 for Brennan to take over ownership and maintenance of the Hydroelectric Plant
· Includes the transfer of the FERC License, USACE Agreement, and Xcel Agreement from the City to Brennan
· As-Is Sale as to the physical conditions of the assets comprising the Plant
· For a period of one year after closing, the City shall provide ongoing assistance with administration,
compliance, and submittals to transition requirements and regulations of licensure and agreements of the
Plant
· Brennan has a due diligence period of 60 days after execution of the Letter of Intent prior to closing
· If Brennan sells to an unrelated third party within 5 years of closing, Brennan shall pay the City 80% of net
sale proceeds if within year 1, 60% of net sale proceeds if within year 2, 40% of net sale proceeds if within
year 3, and 20% of net sale if within year 4
Also attached is the Resolution Regarding the Disposal and Sale of the Hydroelectric Plant that recognizes the
negative cash flow projections of over $14M over the next 25 years and complies with Section 7.04 of the City Charter
for disposal of property.
X-A-01 (a,b)
COUNCIL ACTION REQUESTED
Council is requested to authorize signature of the attached Letter of Intent with J.F. Brennan Company, Inc. and to
consider adopting the enclosed resolution regarding the disposal and sale of the Hydroelectric Plant.
ATTACHMENTS
· Letter of Intent from J.F. Brennan Company, Inc.
· Resolution Regarding the Disposal and Sale of the Hydroelectric Plant
· Hastings Hydro Maintenance Optimization Report prepared by Barr Engineering, dated October 2023
X-A-01 (a,b)
December 11, 2025
City of Hastings, Minnesota 101 4th Street East
Hastings, Minnesota 55033
Attn: Mr. Joe Spagnoletti
RE: NONBINDING LETTER OF INTENT (“LOI” OR “LETTER”) — HASTINGS HYDROELECTRIC PROJECT (FERC # P-4306)
Dear Mr. Spagnoletti:
This Letter is intended to summarize the principal elements of a proposal being considered by J.F.
Brennan Company, Inc., a Wisconsin corporation (“Brennan”), regarding the possible acquisition by one
of its affiliates (“Buyer”), for an expected purchase price in good faith of One and 00/100 Dollars
($1.00), of the above-referenced hydroelectric project with plant capacity of 4400 kW, located at or
upon Mississippi River Locks and Dam No. 2 (the assets and interests comprising the foregoing being
referred to hereafter as the “Plant”) and owned by the City of Hastings, Minnesota (the “City”). The
possible acquisition of the Plant by Buyer is referred to as the “Transaction.” For the avoidance of doubt,
except for the provisions contained in Part Two below, this Letter is part of a partial proposal and does
not and will not establish a binding obligation of the Buyer or the Seller (each sometimes referred to
hereafter as a “Party” and collectively as the “Parties”), it being understood that the Parties will be
legally bound to complete the Transaction only upon the execution of a mutually agreed upon definitive
written purchase and sale agreement (the “Definitive Agreement”).
Part One - Nonbinding
As soon as reasonably practicable after execution of this Letter, the Parties shall commence to negotiate
the Definitive Agreement relating to Buyer’s acquisition of the Plant. The Parties presently contemplate
executing the Definitive Agreement and closing the Transaction on or before June 1, 2026, which will be
subject in all respects to (1) satisfactory completion of the Buyer’s due diligence review of the Plant as
hereinafter set forth, (2) prior approval by the Board of Directors or Managers, as applicable, of the
Buyer, and (3) satisfaction of all conditions applicable to assignment of the Permits (as defined below).
The following represent the principal elements of the proposed Transaction:
1. Acquisition of Purchased Assets. Subject to satisfaction of the conditions described in this Letter
and in those contained in the Definitive Agreement, at the closing of the Transaction, the Buyer
would acquire substantially all the assets, and no liabilities or obligations of any kind or character,
comprising the Plant and/or necessary or appropriate for the ownership and operation of the
Plant, free and clear of all encumbrances. Buyer assumes maintenance obligations and liabilities
of the Plant assets as of the date of closing, such assets being sold in “as-is” condition as more
fully described in Paragraph 4. By way of reference only, and not as a limitation, the assets
comprising the Plant and/or necessary or appropriate for the ownership, operation and
maintenance of the Plant shall include the following:
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J.F. Brennan Company, Inc. page 2 of 5
(a) Real Property. All real property owned or occupied by the City and used in the operation of
or in any way associated with the Plant, including without limitation leasehold interests, rights
of access, licenses for access and/or occupancy (including any and all agreements between
the City and the United States Army Corps of Engineers (collectively, “USACE Agreements”),
and servitudes.
(b) Personal Property. All personal property owned, leased or otherwise held by the City under
contract and used in the operation of or in any way associated with the Plant, including
without limitation water diversion equipment, water conveyance equipment, power
generation equipment, electric interconnection and related facilities, spare and replacement
parts, inventory, tools, equipment leases, occupancy or access agreements and licenses
(including the USACE Agreements), power purchase agreements (including any and all
agreements between the City and Northern States Power/Xcel Energy (collectively, “Xcel
Agreements”)), Federal Energy Regulatory Commission (FERC) license(s), other federal or
state licenses, permits and operating orders or decrees, supplies, books, and records (both
electronic and physical).
2. Assignment of Licenses, Permits, Etc. The City shall initiate the process to assign or transfer to the
Buyer in accordance with relevant federal and state law all licenses (including FERC license(s)),
permits and operating orders or decrees issued by federal or state authorities and necessary or
appropriate for ownership, operation and maintenance of the Plant (collectively, the “Permits”),
subject to the Buyer’s commercially reasonable approval of the same. The City will coordinate
with the Buyer on such assignment and transfer process, including providing copies of all material
communications and filings with applicable governmental authorities prior to any submissions
with a reasonable time to review and approve the same. The Buyer will work with the City to
effect an orderly and timely assignment and transfer of all such Permits and will cooperate with
the City in providing any and all information or documentation necessary to effectuate the
assignment and transfer of all such Permits.
3. Assumed Liabilities. The Buyer shall not, by virtue of the Transaction, be deemed to have assumed,
and is not assuming, any liability or obligation of any kind, character or description whatsoever of
the City or the Plant, or otherwise applicable to ownership or operation of the Plant prior to the
date of closing for the Transaction. The Buyer will accept assignment of contracts, agreements,
licenses and permits, and the obligation to perform in accordance with the foregoing, from and
after the date of closing for the Transaction.
4. “As Is” Sale. The terms of the Transaction shall be “As Is, Where Is” as to the physical condition of
the assets comprising the Plant. The City shall nonetheless provide customary and limited
representations, warranties and indemnities to the Buyer.
5. Post-Closing Cooperation/Consultation. For a period of one year after the date of closing for the
Transaction, the City shall provide ongoing assistance to the Buyer with applicable administration,
compliance and submittals to and with FERC, the United States Army Corps of Engineers, Northern
States Power/Xcel Energy and other applicable regulatory bodies and contract counterparties, as
reasonably necessary and appropriate to transition operational history and experience from the
City to the Buyer. At the request of either Party, the Parties shall execute at closing a mutually
acceptable consulting services agreement documenting such assistance services.
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J.F. Brennan Company, Inc. page 3 of 5
6. Reserved.
Part Two - Binding
Upon execution of this Letter, the following paragraphs 7 through 11 of this Letter are legally binding and
enforceable agreements of the Parties (collectively, the “Binding Provisions”).
7. Due Diligence. Brennan has based current due diligence regarding the Plant, its constituent assets,
and their current condition and operating history on information that is publicly available,
information provided by the City, and a site visit conducted at the Plant on October 21, 2025. For
a period of sixty (60) days after full execution of this Letter, or for such longer period as may be
later agreed upon by the Parties in writing (the “Due Diligence Period”), the City will afford
Brennan, the Buyer and their respective representatives reasonable access to all assets and
facilities comprising the Plant, and all data, drawings, specifications, operating manuals, books
and records (including those of its advisors, accountants, attorneys and other representatives)
relating to the Plant for the purpose of permitting Brennan, the Buyer and their respective
representatives, at their sole cost and expense, to conduct a thorough due diligence investigation
of the legal, operational and financial condition of the Plant (the “Due Diligence Investigation”).
Brennan, the Buyer and/or their respective representatives will conduct the Due Diligence
Investigation in such a manner so as not to unreasonably interfere with the normal conduct of
operations at the Plant. Nonpublic information regarding the Plant obtained from the City in the
course of the Due Diligence Investigation will be subject to the terms and conditions of a mutually
acceptable Confidentiality Agreement between the City and Brennan or the Buyer, as applicable.
8. Exclusive Dealing. In consideration of the expenses the Buyer has incurred and will incur in
connection with the proposed Transaction, the City acknowledges and agrees that concurrent
with the Due Diligence Period, neither the City nor any of its representatives, officers, employees,
managers, supervisors, or agents shall initiate, solicit, entertain, negotiate, accept or discuss,
directly or indirectly, any proposal or offer from any person or group of persons other than
Brennan, the Buyer or their respective affiliates (an “Acquisition Proposal”) to acquire all or any
significant portion of the assets and properties comprising the Plant, or provide any non-public
information to any third party in connection with an Acquisition Proposal, or enter into any
agreement, arrangement or understanding requiring the City to abandon, terminate or fail to
consummate the Transaction.
9. Disclosure. Except as and to the extent required by law or regulation or except as to their
respective representatives that will perform work with respect to the proposed Transaction,
absent the prior written consent of the other Party, the Parties hereto will not, and will direct
their respective representatives not to, make, directly or indirectly, any public comment,
statement or communication with respect to, or otherwise disclose or permit the disclosure of
the existence of discussions regarding a possible transaction among the Parties or any of the
terms, conditions or other aspects of the proposed Transaction. If any Party is required by law or
regulation to make any such disclosure, such Party will first provide to the other Party the content
of the proposed disclosure, the reasons that such disclosure is so required, and the time and place
that the disclosure will be made. Notwithstanding the foregoing, Brennan or Buyer agrees and
acknowledges that the City is a political subdivision of the State of Minnesota and is subject the
Open Meeting Law (Minn. Stat. ch. 13D) and the Minnesota Government Data Practices Act (Minn.
Stat. ch. 13). Accordingly, this LOI must be authorized by the City Council of the City during a public
X-A-01 (a,b)
J.F. Brennan Company, Inc. page 4 of 5
meeting and this LOI and the Transaction will be public data, as defined by Minnesota law. The
City will use commercially reasonable efforts, but at all times subject to applicable law, to notify
Brennan or Buyer of the request for disclosure of trade secrets, or non-public or confidential
information provided by Brennan or Buyer to the City.
10. Expenses. The Parties will each pay their own transaction expenses, including, but not limited to,
the fees and expenses of accountants, attorneys, consultants, and other advisors, incurred in
connection with the proposed Transaction.
11. Sale of Plant. If Brennan or the Buyer sells to an unrelated third party a controlling interest in the
Plant, whether as an asset transaction or through an equity transfer, within five years of Closing
(as defined in the Definitive Agreement), Brennan or Buyer shall be obligated to pay City the
percentage of the net sale proceeds as outlined below:
within Year 1 - 80% of net sale proceeds to the City.
within Year 2 - 60% of net sale proceeds to the City.
within Year 3 - 40% of net sale proceeds to the City.
within Year 4 - 20% of net sale proceeds to the City.
After Year 4 - No sale proceeds to the City.
For purposes of clarification, “net sale proceeds” shall be equal to the total sale price, less the
applicable costs of the sale transaction incurred by Brennan or the Buyer, less the then
unamortized cost of all improvements to the Plant made by Brennan or the Buyer after Closing
and on or prior to the date of such third-party sale transaction. This provision shall survive the
Closing of the Transaction.
Termination. Following full execution hereof, this Letter will terminate upon the first to occur of: (a) the
mutual written agreement of the Buyer and the City; (b) the execution of the Definitive Agreement(s); or
(c) unless otherwise extended by the Parties in writing, September 30, 2026. Upon termination of this
Letter, the Parties shall have no further obligations hereunder except that of the provisions of Part Two
hereof, and the obligations of the Parties thereunder shall survive any such termination.
If this Letter meets your approval, please confirm the same by executing the acknowledgment below
and return it via email to markbinsfeld@jfbrennan.com. If you have any questions, please contact Mark
Binsfeld at (608) 406-5385.
Sincerely,
J.F. Brennan Company, Inc.
By: _________________________
Name: _________________________
Title: _________________________
Mark Binsfeld
Vice President of Business Development/ Principal
X-A-01 (a,b)
J.F. Brennan Company, Inc. page 5 of 5
The foregoing Letter of Intent is hereby accepted as of the ____ day of _________, 202_.
City of Hastings, Minnesota
By: ____________________________ By: _________________________________
Name: __________________________ Name: ______________________________
Title: ____________________________ Title: _______________________________
X-A-01 (a,b)
RESOLUTION NO. _______
CITY OF HASTINGS
DAKOTA COUNTY, MINNESOTA
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF HASTINGS
REGARDING THE DISPOSAL AND SALE OF THE
HYDROELECTRIC PLANT
WHEREAS, the City of Hastings owns the Hastings Hydroelectric Plant located at and upon the
Mississippi River Lock and Dam No. 2 (“Plant”) upon Parcel Identification No. 190210060010; and
WHEREAS, the City authorized the preparation of the “Hastings Hydro Maintenance
Optimization Report,” prepared by Barr Engineering, dated October 2023, which was included in the
council packet (the “Report”); and
WHEREAS, the Report concluded estimated operations and maintenance costs of the Plant that
was included in the City’s financial outlook over the next 25 years, which resulted in a negative cash flow
amount of over $14 Million; and
WHEREAS, Section 7.04 of the City Charter states that no real property shall be disposed of unless
the City Council passes a resolution containing specific findings that the public interest requires the Plant
be disposed of after a notice and public hearing; and
WHEREAS, the City Council held a public hearing on December 15, 2025, and published notice
of the same in the Hastings Journal, at which time the public was afforded the opportunity to provide
comments on the disposal and sale of the Plant; and
WHEREAS, given the Report conclusions and the public comments, the City Council finds that it
is not fiscally responsible to the citizens of Hastings to continue owning the Plant and desires to sell the
Plant to a suitable buyer, who will continue operations; and
NOW THEREFORE BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY OF
HASTINGS AS FOLLOWS:
1. The City has satisfied the notice and hearing requirements of Section 7.04 of the City Charter.
2. The public interest requires the Plant be disposed of and sold.
3. The Mayor and any other necessary staff are authorized to execute the necessary documents on
behalf of the City to complete the sale of the Plant to J.F. Brennan Company, Inc. consistent
with the terms of the December 11, 2025, Letter of Intent.
Council member_________________ moved a second to this resolution and upon being put to a vote it
was adopted by the Council Members present.
Adopted by the Hastings City Council on_______________, 2026, by the following vote:
Ayes:
Nays:
Absent:
X-A-01 (a,b)
Mary Fasbender, Mayor
ATTEST:
Kelly Murtaugh, City Clerk
X-A-01 (a,b)
3128 14th Avenue East Hibbing, MN 55746
218.262.8600 www.barr.com
Hastings Hydro Maintenance Optimization Report
Prepared for
L&S Electric / City of Hastings
October 2023
X-A-01 (a,b)
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Certification
I hereby certify that this plan, specification, or report was prepared by me or under my direct supervision, and that I am a duly Licensed Professional Engineer under the laws of the State of Minnesota.
Kurt L. Sobczynski PE #: 41973 Date
October 4, 2023
X-A-01 (a,b)
\\barr.com\projects\Hibbing\23 MN\19\23191501 Hastings Hydro Maintenance Opt\WorkFiles\Report\Hastings Hydro Maintenance Optimization Report_2023-10-03_Final.docx i
Hastings Hydro Maintenance Optimization Report
October 2023
Contents
1 Abstract .................................................................................................................................................................................... 1
2 Element 1: Identify System Boundaries and Functions ......................................................................................... 3
2.1 Step 1: System Selection and Information Collection ...................................................................................... 3
2.2 Step 2: System Boundary Definition ........................................................................................................................ 3
2.3 Step 3: System Description/Functional Block Diagram ................................................................................... 5
2.4 Step 4: System Functions and Functional Failures ............................................................................................. 6
3 Element 2: Identify Specific Failure Modes that Could Potentially Produce Functional Failures ......... 7
3.1 Step 5: Failure Mode and Effects Analysis (FMEA) ............................................................................................ 7
4 Element 3: Prioritize Failure Modes .............................................................................................................................. 8
4.1 Step 6: Logic Tree Analysis (LTA) .............................................................................................................................. 8
5 Element 4: Task Selection and Evaluation .................................................................................................................. 9
5.1 Step 7: Task Selection ................................................................................................................................................... 9
5.2 Economic Evaluation of Recommended Maintenance ..................................................................................10
5.2.1 Assumptions and Clarifications ..........................................................................................................................10
5.2.2 Economic Analysis Approach ..............................................................................................................................13
5.2.2.1 Present Value Given Future Investment/Cash Flow .........................................................................13
5.2.2.2 Present Value Given Annual Investment/Cash Flow ........................................................................13
5.3 Economic Analysis Results ........................................................................................................................................14
List of Tables
Table 5-1 History of Revenues -Electricity (provided by the City of Hasting) .............................................. 12
Table 5-2 Present Value Analysis Results .................................................................................................................... 14
Table 5-3 Projected Cash Flow ........................................................................................................................................ 15
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List of Appendices
Appendix A Tables
Table A-1 System Functions and Functional Failures
Table A-2 System Work Breakdown Structure Step 3-4
Table A-3 Failure Mode and Effects Analysis (FMEA)
Table A-4 Logic (Decision) Tree Analysis (LTA)
Table A-5 Task Selection
Table A-6 Preliminary Maintenance Recommendation
Appendix B Figures
Figure 1 Functional Block Diagram
Appendix C Present Value Calculations for Operating and Maintenance Costs
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1 Abstract
The purpose of this study is to determine the preventative maintenance activities that are required to
preserve the functional capabilities of the hydroelectric power plant owned by the City of Hastings. The
process used to determine the maintenance activities is Reliability Centered Maintenance (RCM). The RCM
methodology focuses on preserving the core functions of a system by identifying and controlling failure
modes. The team members who performed the RCM analysis can be listed as follows:
• Joe Spagnoletti, City of Hastings Public Works Superintendent
• Ryan Stempski PE, City of Hastings Public Works Director/City Engineer
• Troy Ellison, L&S Electric, Territory Manager
• Doug Junion, L&S Electric, General Manager
• Kurt L. Sobczynski PE, Mechanical Engineer, Barr
The RCM process consists of four elements. These elements were accomplished in a series of seven steps.
The elements and steps can be listed as follows:
• Element 1: Identifying System Boundary and Functions
o Step 1: System Selection and Information Collection
o Step 2: System Boundary Definition
o Step 3: System Description/Functional Block Diagram (Appendix B, Figure 1)
o Step 4: System Functions and Functional Failures
• Element 2: Identify Specific Failure Modes that Could Potentially Produce Functional Failures
o Step 5: Failure Mode and Effects Analysis
• Element: 3: Prioritize Failure Modes
o Step 6: Logic Tree Analysis
• Element: 4: Task Selection and Evaluation
o Step 7: Task Selection and Evaluation
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A maintenance plan was developed because of this exercise. The maintenance plan includes turbine and
generator major and minor inspections as well as electrical and vibration testing and monitoring. An
economic analysis was performed to determine the present value of the estimated operating and
maintenance (O&M) costs, and to compare these costs to the present value of the revenue for power
generation over the next 25 years. The results of the economic analysis can be listed as follows:
Projected power production revenue: $10,100,000
Estimated O&M costs: $12,400,000
Net cash (revenue – O&M): -$2,300,000
O&M % of revenue: 122%
The details of the economic analysis and associated assumptions can be found later in this document.
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2 Element 1: Identify System Boundaries and
Functions
The first element identifies the system boundary and functions. Identification of the system boundary
includes listing the equipment that will be covered in this study and identifying the functions of the entire
system collectively as well as the individual system components. The sources for the data that was used in
this element of the process include:
• Equipment list
• Operating and maintenance manual from Voith Hydro Services (turbine generator OEM)
2.1 Step 1: System Selection and Information Collection
The purpose of this step is to select the systems that are going to be analyzed and to determine the level
of assembly on which the analysis will be performed.
This step was performed as a group during a Team’s meeting. The group consisted of Kurt Sobczynski, as
facilitator and engineer; Joe Spagnoletti, as owner & operator; Doug Junion, mechanical and electrical
maintenance technician; and Troy Ellison, as facilitator.
The hydroelectric plant was divided into three sub-systems for the purposes of this study. These three
sub-systems contain all the equipment needed for the operation of the plant.
The sub-systems selected for study are:
1. Sub-system 1 Hydro Turbine Generator #1
2. Sub-system 2 Hydro Turbine Generator #2
3. Sub-system 3 General Plant
The level of assembly refers to the amount of detail that each component of each system and sub-system
are analyzed. It was decided that for this study the level of assembly would refer to the following:
1. Single large or unique assets or components for the mechanical system.
2. Hydraulic and electronic controls, switches and transformers will be treated and analyzed as
“black box’ systems.
2.2 Step 2: System Boundary Definition
The purpose of this step was to identify the boundaries of the three sub-systems and to list the
components of each system. This step was also performed as a team during a meeting.
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The turbine generator boundaries were selected to begin at the intake flumes and stop at the draft tubes
for each machine. Included with the turbine generators were all the electrical equipment associated with
the generators. The general plant system boundaries were selected to include all the auxiliary equipment
not included with the turbine generators. The systems, sub-systems, and equipment contained in the
boundaries can be listed as follows:
System Hydroelectric Plant City of Hastings
Sub-system 1: Hydro Turbine/Generator #1
1. Gate case, control servo, linkage, and HPU
2. Runner hub and pitch control servo and linkage
3. Turbine casing
4. Turbine and generator thrust and guide bearings.
5. Speed changer
6. Generator field, stator
7. Oil system
8. Cooling water system
9. Seal water system
10. Electronic speed governors and turbine controls
11. Static excitation and voltage controls
12. Switchgear and protective relays
Sub-system 2: Hydro Turbine/Generator #2
1. Gate case, control servo, linkage, and HPU
2. Runner hub and pitch control servo and linkage
3. Turbine casing
4. Turbine and generator thrust and guide bearings.
5. Speed changer
6. Generator field, stator
7. Oil system
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8. Cooling water system
9. Seal water system
10. Electronic speed governors and turbine controls
11. Static excitation and voltage controls
12. Switchgear and protective relays
Sub-system 3: General Plant
1. Trash rack & gates
a. Flume gate
b. Lifting equipment
c. Trash rack cleaner
2. Intake flume & draft tube
3. Station transformer
4. HVAC equipment
5. Miscellaneous equipment
a. Sump pumps
b. Air compressors
2.3 Step 3: System Description/Functional Block Diagram
The purpose of this step was to define the system functions, determine if there are any redundancy
features and key control parameters that will affect maintenance decisions.
A functional block diagram (Figure 1) of the sub-systems #1 and #2 was developed. The input and output
of these sub-systems was also listed. sub-systems #1 and #2 were broken down further and the individual
components of each sub-system were assigned asset numbers and listed under each sub-system. The
systems, sub-systems, and asset numbers are listed in Table A-2 in Appendix A.
A group review of the functional block diagram (Figure 1) and the system and asset list was conducted.
The following observations were made:
1. Sub-system #1 And sub-system #2, the turbine generators, are identical units and therefore the
hydroelectric plant has double redundancy. This is in effect when the flow rate through the plant
does not exceed the capacity of one turbine. It was pointed out that this occurs mostly in the
winter season, approximately 80% of the time.
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2. The flow rate through the plant “CFS” is dictated solely the Army Corps of Engineers. The primary
purpose of the dam is navigation. Electric power generation is secondary. Therefore, during the
summer months power generation is limited to maintain water for the locks and in the winter a
minimum flow must be passed though the spillway for environmental purposes also limiting
power production.
3. Protection features such alarms, interlocks, and trips for vibration, temperatures, and load
rejection are included in the control logic for the hydro turbine governors.
The sole purpose of the hydroelectric power plant is to convert the energy from the river into electric
power. The electric power is sold to the local utility. The main season for generating hydropower is in the
winter since the river traffic is stopped and the water flow is passed for environmental purposes and
hydropower generation.
2.4 Step 4: System Functions and Functional Failures
The purpose of this step was to define the functions of the components for each of the sub-systems and
to describe the functional failure(s) of this component.
The list of assets was reviewed, and the functions and functional failures was determined. The emphasis
was on the loss of function and not the failure of the component.
During this analysis it became apparent that the functions of sub-system’s #1 and #2, the turbine
generators, are identical so the analysis was performed on one unit only and copied to the other machine.
It was also realized that the potential preventative maintenance activities for the electrical power
transmission equipment were identical and that the individual functions of each electrical cabinet were
not relevant. Therefore, the electrical power transmission components were grouped into a common sub-
system and treated as a “black box” and given a common function and failure mode.
The functional block diagram (Figure 1), the asset list, and the system functions and failures are presented
in Table A-1.
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3 Element 2: Identify Specific Failure Modes that
Could Potentially Produce Functional Failures
The second element identifies the specific failure modes that could hinder the system and equipment
functions. A Failure Mode and Effects Analysis (FMEA) was performed to identify the failure modes that
could defeat the functions. An initial prioritization of the functions and failure modes was also conducted.
The FMEA and the prioritization are presented in chart form in a spreadsheet located in the Table A-3.
3.1 Step 5: Failure Mode and Effects Analysis (FMEA)
The purpose of this step was to connect the system functions and the system components by directly
identifying specific hardware failure modes that could produce the unwanted functional failures.
The System Functions and Functional Failure list developed in Step #4 was reviewed. Failure Modes were
assigned to each functional failure as described below:
• The failure mode is the reason or cause for the component failing to perform.
• A failure cause is the effect that caused the failure mode.
For example, the first asset analyzed, Asset #100 Kaplan Runner, the failure mode was cavitation and wear
on the runner. Cavitation is the spalling and uneven wear on the downstream side of the runner blades.
The potential causes (failure causes) of cavitation and wear are the improper adjustment of the blade
pitch and impact from foreign objects. The effects of the failures were also evaluated on the local sub-
system, the system, and the entire plant. The failure modes that affect both turbines, and thus the plant,
were determined to require further analysis to determine if preventative maintenance activities are
applicable. It was also determined that the failure modes that effect only one of the turbines would still
require further analysis since the costs of repair of the turbine due to failure outweigh the costs of the
preventative maintenance. The only failure modes that qualified for run to failure status were connected
to the HVAC equipment in the plant.
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4 Element 3: Prioritize Failure Modes
The third element prioritizes the functions and failure modes uncovered during the FMEA utilizing a Logic
Tree Analysis (LTA) approach. LTA is an analytical method that uses deductive logic to guide though a
process used to draw correct conclusions. The results of the LTA are presented in chart form in a
spreadsheet located in Table A-4.
4.1 Step 6: Logic Tree Analysis (LTA)
The purpose of this step is to evaluate and categorize the failure modes to determine if preventative
maintenance activities are warranted.
Each of the Failure Modes from Step #5 that required analysis, was subjected to the following questions.
The first question was that under normal conditions will the operator be aware that the failure mode has
occurred. If the answer to that question is yes, then the failure is deemed evident. The second question
asks whether the failure mode causes a safety problem, and the final question is does the failure mode
cause an outage for the system. Categories based upon these answers are assigned to each of the failure
modes as follows:
Safety = A
Outage = B
Minor = C
Hidden = D
Categories A or D/A, B or D/B are candidates for preventative maintenance activities while category C and
D/C are candidates for run to failure (RTF).
Only three failure modes were Category C and deemed run to failure, the remainder of the failure modes
were carried onto Step #7.
X-A-01 (a,b)
9
5 Element 4: Task Selection and Evaluation
The fourth element is the identification of preventative maintenance activities to address the failure
modes selected in Step #6.
5.1 Step 7: Task Selection
The purpose of this step is to select preventative maintenance tasks (PM’s) for each of the failure causes.
Each failure cause identified in Step #6 was reviewed based on the following seven question criteria:
• Q1: Is the age reliability relationship for this failure known?
• Q2: Are there any applicable time dependent (td) tasks?
• Q3: Are there any applicable condition dependent (cd) tasks?
• Q4: Is this a category "d" failure mode?
• Q5: Are there any applicable failure finding (ff) tasks?
• Q6: Are any of these tasks effective?
• Q7: Can a design modification eliminate the failure mode or effects?
Based upon the results of these questions, candidate PM tasks and the frequency of these tasks were
selected. In Question #1, the age reliability relationship refers to the wear rate of a component. This
question asks based on operating time or cycles is the wear or degradation of the component known and
constant so that a failure time can be predicted. Question #2 follows on Question #1 by asking if there are
any applicable time or life cycle dependent tasks or PM’s that can be performed. Question #3 asks if there
are any PM’s that can be performed that will be able to detect the onset of failure, Question #4 asks if the
failure mode is a category “D” or hidden failure. A hidden failure is unknown to an operator and may also
not be time dependent. Question #5 asks if there are any tasks that can be used to discover the failure
such as internal inspections. Question #6 asks if any of the PM’s suggested are effective. For this exercise
we recommended PM’s that L&S currently use in hydroelectric industry. The final question asks whether a
design modification of the component could eliminate the failure mode. The results of the task election
process can be seen in Table A-5.
The list of recommended preventative maintenance activities is presented in chart form in Table A-6. This
list includes the following:
1. Covered Equipment
2. Scope of work
3. Recommended Frequency
4. Cost Estimate
X-A-01 (a,b)
10
It should be noted that a substantial driver in determining the PM frequency was the FERC Part 12D
regulatory requirement for dewatering the turbine forebays and tailraces every 5 years for inspection.
Dewatering costs will also consume a substantial amount of the maintenance budget.
5.2 Economic Evaluation of Recommended Maintenance
An economic evaluation was performed by balancing the cost of the recommended maintenance over the
next 25 years with the projected revenue produced by power generation.
5.2.1 Assumptions and Clarifications
The following assumptions were made in this evaluation and in the full process described further in this
document:
• The annual power generation revenue is estimated to be $716,500. It is based on a budget
number for 2024 provided by the City of Hastings. A cost escalation for future power sale price
has not been included.
• The historical annual revenue data from 2006 to 2022 was also provided by the City of Hastings.
The year 2006 was the first full year of power generation revenue data. The average power
production was determined from the historical data to be $888,115. See Table 5-1.
• The rate of return for the power generation and the interest rate on the maintenance costs have
been assumed to be constant over the next 25 years at 5%.
• Repair and maintenance cost escalation has not been included in the maintenance costs
estimates.
• Repair and maintenance cost estimates were provided by L&S Electric.
• The maintenance intervals are based on typical industry requirements. Sit specific usage, wear,
and damage may affect the typical maintenance timing. It should be noted that the
recommended maintenance program is cyclical and begins again in 25 years.
• The equipment lists, and subsequent recommended preventative maintenance tasks were
developed in conjunction with L&S Electric and the City of Hastings. Barr did not visit the site to
assess or document the equipment and is not responsible for any omitted components or
equipment.
• An annual miscellaneous maintenance cost of $25,000 was added to account for small repairs not
included in specific line items. This is in addition to $44,000 in line item 6354 Repairs &
Maintenance Equipment from the budget supplied by the City of Hastings. The miscellaneous
maintenance cost is included in the overall maintenance costs and line item 6354 is included in
the operating costs.
X-A-01 (a,b)
11
• It was assumed for this study that the current condition of both turbine/generators was such that
a 25-yr major inspection and generator rewind is required for both units. It should be noted that
this is a conservative scenario. It is possible that the units are in better condition and that a 10-yr
minor inspection could be performed to determine the condition of the units. However, it would
be prudent to anticipate the more conservative requirement.
• The estimated annual operating costs for the hydroelectric plant are $450,000 and were provided
by the City of Hastings.
X-A-01 (a,b)
12
Table 5-1 History of Revenues -Electricity (provided by the City of Hasting)
Year Jan Feb March April May June July August Sept Oct Nov. Dec. Total
2003 $- $- $- $- $- $- $- $- $- $69,997 $70,636 $78,533 $219,165
2004 $59,845 $59,270 $87,281 $82,234 $58,661 $74,626 $- $136,612 $67,629 $- $- $- $626,159
2004 $- $- $- $- $- $- $- $- $- $68,215 $- $143,703 $211,918
2005 $98,169 $93,577 $103,093 $56,733 $72,122 $64,149 $94,054 $116,055 $111,246 $- $- $- $809,198
2005 $- $- $- $- $- $- $- $- $- $67,860 $192,071 $98,993 $358,924
2006 $115,810 $88,425 $81,643 $54,453 $61,444 $89,607 $101,410 $89,986 $54,072 $59,338 $63,983 $98,041 $958,213
2007 $110,881 $81,426 $85,063 $51,955 $79,694 $104,207 $103,659 $96,780 $100,568 $90,086 $102,555 $113,879 $1,120,754
2008 $92,761 $80,057 $100,020 $83,849 $68,585 $75,184 $116,089 $108,934 $93,398 $117,983 $114,113 $99,507 $1,150,481
2009 $98,703 $105,942 $98,267 $65,992 $78,700 $94,305 $95,391 $94,269 $74,420 $95,788 $90,087 $97,725 $1,089,590
2010 $97,858 $67,912 $54,367 $48,452 $62,399 $71,269 $77,911 $86,717 $84,807 $69,968 $92,628 $116,057 $930,344
2011 $94,394 $87,998 $75,284 $41,170 $41,239 $46,755 $26,118 $70,903 $98,593 $141,031 $76,910 $110,949 $911,343
2012 $80,232 $82,411 $102,229 $99,056 $61,221 $49,437 $79,551 $108,935 $76,780 $66,975 $88,598 $86,393 $981,820
2013 $74,176 $105,269 $71,815 $78,610 $45,737 $52,769 $70,257 $111,500 $82,605 $72,223 $87,926 $94,735 $947,624
2014 $96,570 $92,189 $100,788 $56,525 $38,823 $36,885 $49,265 $106,662 $74,476 $101,848 $80,138 $75,659 $909,827
2015 $94,954 $94,509 $95,361 $91,765 $66,536 $67,652 $86,252 $93,660 $84,228 $83,028 $69,227 $72,651 $999,822
2016 $178,497 $82,075 $138,546 $64,681 $64,121 $70,655 $44,309 $66,429 $48,225 $52,825 $61,060 $61,479 $932,900
2017 $75,917 $61,144 $67,031 $56,971 $32,001 $64,823 $87,620 $83,100 $76,406 $46,538 $66,607 $59,436 $777,594
2018 $62,236 $59,790 $60,370 $47,253 $37,746 $47,604 $43,536 $83,912 $64,685 $48,332 $64,646 $71,909 $692,018
2019 $85,517 $84,643 $66,194 $36,360 $34,599 $42,538 $44,479 $68,448 $55,768 $35,741 $49,230 $58,631 $662,148
2020 $57,480 $49,876 $42,468 $38,277 $39,491 $35,364 $33,031 $58,320 $55,615 $54,870 $53,299 $58,875 $576,967
2021 $69,787 $60,904 $52,539 $50,646 $59,280 $69,093 $61,350 $54,769 $61,320 $73,592 $55,610 $61,200 $730,088
2022 $66,760 $57,323 $58,199 $47,038 $30,286 $43,092 $82,676 $82,797 $73,638 $55,522 $65,009 $64,099 $726,439
2023 $78,589 $65,655 $82,107 $43,451 $- $- $- $- $- $- $- $- $-
Total $1,789,136 $1,560,395 $1,622,666 $1,195,472 $1,032,684 $1,200,014 $1,296,956 $1,718,787 $1,438,480 $1,471,760 $1,544,330 $1,722,455 $17,323,333
X-A-01 (a,b)
13
5.2.2 Economic Analysis Approach
The analysis was performed by calculating the present value of the projected power production revenue
and subtracting the estimated present value of the operating and maintenance (O&M) costs over the next
25 years. The present value analysis calculates the current value of a future cash flow or investment that
will be paid or disbursed at a future date, discounted back to the present at a given interest rate.
The purpose of the following calculations is to determine the current value of the cash flows and
investments of the Hastings Hydroelectric Plant to make an accurate assessment of the financial viability
of the investment.
5.2.2.1 Present Value Given Future Investment/Cash Flow
The present value formula calculates the current worth of a future cash flow or investment that will be
received or paid at a future date, discounted back to the present at a given interest rate.
Present Worth (P/F, i, n)
Operational cycle (n) 25 years
Interest rate (i) 5 %
Present value (P)
Future value (F)
or the Factor (P/F) for i=5%, n=25 can be looked up in a table in which case:
5.2.2.2 Present Value Given Annual Investment/Cash Flow
The series present worth formula calculates the equivalent present value of equal cash flows received or
disbursed at regular intervals over a specific period of time at a given interest rate.
Series Present Worth (P/A, i, n)
Operational cycle (n) 25 years
Interest rate (i) 5 %
Present value (P)
Annual worth or costs (A)
𝑃𝑃=𝐹𝐹(1 +𝑖𝑖)−𝑛𝑛
𝑃𝑃=�𝑃𝑃𝐹𝐹��𝐹𝐹
X-A-01 (a,b)
14
or the Factor (P/A) for i=5%, n=25 can be looked up in a table in which case:
5.3 Economic Analysis Results
The present value of the projected revenue of the hydroelectric plant was determined to be $10,100,000.
The present value of the O&M costs were determined to be $12,400,000. The present value of the net
cash flow is a negative $2,300,000. In this case the O&M costs are 122% of the projected power revenue.
According to the US Energy Information Administration (EIA) in the Annual Energy Outlook for 2022, the
average O&M costs for a conventional hydroelectric power plant were $43.78 per KW. The hydro turbines
at the City of Hasting facility are rated at 2200 KW for each unit. The annual combined O&M costs for
both units based on the EIA 2022 average should then be approximately $193,000. The present value for
the O&M costs for the next 25 years based on this average are $2,700,000. These O&M costs are
approximately 27% of the present value of the projected power revenue.
The present values from the current projection and from a projection based on the O&M costs from the
IEA 2022 average are listed in the Table 5-2. The projected annual cash flow can be seen in Table 5-3. The
present value calculations can be seen in Appendix C.
Table 5-2 Present Value Analysis Results
Revenue Current Projection Projection based on EIA 2022
Projected Power Revenue $10,100,000 $10,100,000
O&M Costs $12,400,000 $2,700,000
Net Cash (Revenue -O&M) -$2,300,000 $7,400,000
O&M % of Revenue 122 % 27 %
𝑃𝑃=(1 +𝑖𝑖)𝑛𝑛−1𝑖𝑖(1 +𝑖𝑖)𝑛𝑛
𝑃𝑃=�𝑃𝑃𝐴𝐴��𝐴𝐴
X-A-01 (a,b)
15
Table 5-3 Projected Cash Flow
Year Projected Revenue Operating Costs
Maintenance Costs O&M Total Cash Flow Annual 3 Year 5year 10 Year 25 Year Total
0 $716,500 $450,000 $60,000 - - - 3,050,000 $3,110,000 $3,560,000 $2,843,500
1 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
2 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
3 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
4 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
5 $716,500 $450,000 $60,000 - $714,000 - - $774,000 $1,224,000 $507,500
6 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
7 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
8 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
9 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
10 $716,500 $450,000 $60,000 - - $1,020,000 - $1,080,000 $1,530,000 $813,500
11 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
12 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
13 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
14 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
15 $716,500 $450,000 $60,000 $45,000 $714,000 - - $819,000 $1,269,000 $552,500
16 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
17 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
18 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
19 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
20 $716,500 $450,000 $60,000 - - $1,020,000 - $1,080,000 $1,530,000 $813,500
X-A-01 (a,b)
16
Year Projected Revenue Operating Costs
Maintenance Costs O&M Total Cash Flow Annual 3 Year 5year 10 Year 25 Year Total
21 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
22 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
23 $716,500 $450,000 $60,000 - - - - $60,000 $510,000 $206,500
24 $716,500 $450,000 $60,000 $45,000 - - - $105,000 $555,000 $161,500
25 $716,500 $450,000 $60,000 - - - 3,050,000 $3,110,000 $3,560,000 $2,843,500
X-A-01 (a,b)
17
The O&M costs for the City of Hastings hydroelectric plant are more than four times greater than the
average as reported by the EIA. Some potential causes for the higher-than-average costs are:
• Economy of scale – The O&M costs for smaller projects tend to higher than the larger projects.
Much of the regulatory inspection, operating staff, and maintenance are performed and needed
on both small and large projects, however the larger projects have more income to offset these
costs.
• Accessibility - The difficultly in accessing and in dewatering the facility greatly increase the costs
of inspection and maintenance.
• Power Production – The primary purpose of the Lock and Dam is for navigation of the river and
not for power generation. Power production is limited due to the need to keep water available for
navigation purposes.
• Complexity of the Turbine/Generators - The turbines installed in this facility are Kaplan style
turbines with speed changers that are coupled to synchronous generators. This style of turbine
was chosen to accommodate the variable heads and high water flows indicative of a facility that is
integrated with a navigable Lock and Dam. While this type of turbine is efficient in this
application, it is by its nature complex and, therefore, requires more maintenance and upkeep
than a Francis or propeller style turbine.
• Power costs – The power produced by the facility is purchased by the local utility. The rate for this
power is a function of the avoided variable costs for one of the Utilities existing power generating
plants and an accredited capability based on the current generation in either the summer or
winter season. It is possible that a higher rate could be negotiated that will lower the effect of the
O&M costs.
X-A-01 (a,b)
Appendices
X-A-01 (a,b)
Appendix A
Tables
X-A-01 (a,b)
Table A-1
System Functions and Functional Failures
Sub-System: Asset # Description Function # Functional Failure # Function/Functional Failure Description
Turbine
100 Kaplan Runner 1.0
Convert Hydraulic Energy of Water into Torque
1.1 Inefficient Conversion of Hydraulic Energy to Torque (80%)
1.2 Complete Failure to Convert Hydraulic Energy to Torque
101 Trunnion Seal 2.0
Seal Turbine Blade & Separate Governor Oil in Hub from River Water
2.1 Loss Of Oil into River
2.2 Water Contamination in Oil System
102 Mechanical shaft seal 3.0
Seal Runner and Turbine Shaft
3.1 River Water Leaks into Power Plant
3.2 Water Contamination in Oil System of River Side Guide Bearing
103 Pitch control Servo 4.0
Adjust Pitch of Kaplan Blade to Improve Turbine Efficiency
4.1 Pitch Control Will Not Move
4.2 Pitch Controls Out of Adjustment
104 Runner side guide bearing 5.0
Position, Align, And Compensate for Radial Forces from Turbine Shaft
5.1 Misaligned (Radial) Turbine Shaft
5.2 Catastrophic Bearing Failure
105 Thrust bearing 6.0
Position, Align, And Compensate for Axial Forces from Turbine Shaft
6.1 Misaligned (Radial) Turbine Shaft
6.2 Misaligned (Axial) Turbine Shaft
6.3 Catastrophic Bearing Failure
106 Wicket gates & controls 7.0
Adjust Position of Wicket Gate to Increase and Decrease Water Flow Through the Turbine
7.1 Unable to Increase or Decrease Water Flow Though Turbine
7.2 Unable to Shut Off Water Flow Through Turbine
107 Brake system 8.0
Stop Turbine from Rotating When Speed is Lower Than 96 RPM
8.1 Will Not Stop Turbine from Rotating
8.2 Will Not Allow Turbine to Rotate
Reducer 108 Gearbox Speed Reducer 9.0
Increase Turbine Shaft Speed to Synchronous Generator Speed. Transmit Power from Turbine to Generator
9.1 Unable To Transmit Power from Turbine to Generator
Generator 109 Rotating Electric Generator 10.0 Convert Torque from Turbine into Electricity
10.1 Loss Of Electrical Power
Generator Exciter 110 Generator Electronic Exciter #1
11.0 Energize Generator Field
11.1 Cannot Energize Field or Start Up Unit
12.0 Provide Voltage Control
12.1 Unable to Control Voltage or Frequency
Governor
111 HPU 13.0 Provides Hydraulic Power to Wicket and Blade Pitch Control & Brakes
13.1 Cannot Open Wicket Gates or Control Pitch of Blades or Release Brakes
112 Accumulator
14.0
Stores Hydraulic Power to Balance Operation of Hydraulic Pumps and Motors
14.1 Cannot Open Wicket Gates or Control Pitch of Blades
15.0
Stores Hydraulic Power to Allow a Final Closing of Wicket Gates in the Event of Loss of Station Power
15.1 Cannot Stop Rotation of Turbine (Runaway)
113 Governor Oil Tank 16.0
Store Control Oil for Both Wicket and Kaplan Control Governors
16.1 Integrity, Loss of Oil into River
16.2 No Control Oil for Governor, Cannot Control Wicket Gates or Blade Pitch
114 LP1 Controls Hydraulic Main Floor 17.0
Hydraulic Switches & Controls to Regulate Wicket Gate and Kaplan Servo's
17.1 Cannot Open Wicket Gates or Control Pitch of Blades
115 HPU Motor #1 18.0 Provide Hydraulic Pressure For HPU
18.1 No Pressure, Cannot Open Wicket Gates or Control Pitch of Blades
116 HPU Motor #2 19.0 Provide Hydraulic Pressure For HPU
19.1 No Pressure, Cannot Open Wicket Gates or Control Pitch of Blades
X-A-01 (a,b)
Sub-System: Asset # Description Function # Functional Failure # Function/Functional Failure Description
Governor (Cntd) 117 Accumulator Motor Fluid Trans 20.0
Moves Control Oil from Accumulator to Oil Cooler Heat Exchanger
20.1 Control Oil Will Overheat, Cannot Control Wicket Gates of Control Pitch of Blades
Lube Oil System
118 Filtration Assembly 21.0
Removes Contaminants from Lube Oil
21.1 Contaminated Lube Oil, Decreased Bearing Life
21.2 Plugged Filter, No Lube Oil Flow, Bearing Failure
119 Filtration System Motor 22.0 Circulates Lube Oil Through Filters
22.1 Insufficient Lube Oil Pressure
120 Lube Oil Motor 23.0 Drives Lube Oil Pump
23.1 No Lube Oil Pressure
121 Lube Oil Pump 24.0
Pumps Lube Oil Through System, Minimum Pressure
24.1 Insufficient Lube Oil Pressure
24.2 No Lube Oil Pressure
122 Heat Exchanger Cooling Fan Motor 25.0 Cools Lube Oil Maximum Allowed Lube Oil Temp
25.1 Lube Oil Temp Above Maximum
123 Heat exchanger 26.0
Cools Lube Oil Maximum Allowed Lube Oil Temp
26.1 Lube Oil Temp Above Maximum
26.2 Lube Oil Temp Below Minimum
26.3 Integrity Of Heat Exchanger, Loss of Lube Oil
124 Lube Oil Tank #1 27.0
Stores Lube Oil & Governor Control Oil
27.1 Loss Of Oil into River
27.2 No Lube Oil for Turbine
Electrical Switchgear
- Electrical Switchgear “Black Box”
28.0
Transfer electrical power, signals, and control for operation of Turbine generator
125 Cabinet S4 for Generator #1
28.1 Electrical failure results in the shutdown of the turbine and the inability to generate power
126 Ground Fault Relay
127 Gen Differential Relay
128 Gen Protection System
129 ITE Breaker 4.76KV
130 Cabinet S5 for Generator #1
131 Misc. gauges and indicator readouts
VFD cabinet Unit #1
132 Unit #1 HPU 29.0 Provides power to HPU
29.1 control logic keeps turbine offline
133 Unit #1 LOP 30.0 Provides power to lube oil pump
30.1 control logic keeps turbine offline
134 Prime Sump Pump 31.0 Provides power to HPU
31.1 prime sump pump will not pump
135 Secondary Sump Pump 32.0 Provides power to HPU
32.1 secondary sump pump will not pump
X-A-01 (a,b)
Table A-2
System Work Breakdown Structure Step 3-4
Sub-System Asset # Description MFG Serial #
Unit #1
Turbine
100 Kaplan Runner Voith -
101 Trunnion Seals Voith -
102 Shaft Mechanical Seal Voith -
103 Pitch Control Servo Voith -
104 Runner Side Guide Bearing Voith -
105 Thrust Bearing Voith -
106 Wicket Gates & Controls Voith -
Reducer 108 Gearbox Speed Reducer Voith H19631
Generator 109 Rotating Electric Generator Yaskawa 515386101
Exciter 110 Electronic Exciter #1 Basler DECS-200 -
Governor
111 HPU Continental -
112 Accumulator Wilkes & McLean -
113 Governor Oil Tank - -
114 LP1 Controls Hydraulic Main Floor - -
115 HPU Motor #1 Dayton VM3558
116 HPU Motor #2 Baldor CM3714T
117 Accumulator Motor Fluid Trans Baldor VM3558
Lube Oil System
118 Filtration Assembly - -
119 Filtration System Motor Baldor VM3558
120 Lube Oil Motor Leeson 170165.6
121 Lube Oil Pump - -
122 Heat Exchanger Cooling Fan Motor Baldor VM3554T
123 Heat Exchanger Thermal Trans Z7611
X-A-01 (a,b)
Sub-System Asset # Description MFG Serial #
Electrical Switchgear
125 Cabinet 54 for Generator #1 - -
126 Ground Fault Relay Bassler BE1-59N Mounted on S4
127 Gen Differential Relay Bassler BE1-87G Mounted on S4
128 Gen Protection System Bassler BE1-GPS Mounted on S4
129 ITE Breaker 4.76KV - -
130 Cabinet 55 for Generator #1 - -
131 Misc. Gauges and Indicator Readouts - Mounted on S3
132 VFD Cabinet Unit #1 - -
133 Unit #1 LOP ABB ACQ550-U1.015A-4
134 Unit #2 Chiller VFD Mitsubishi FRF84000170E3N6
135 Prime Sump Pump Mitsubishi FRF74000380NA
136 Secondary Sump Pump ABB 22C-D030N103
Unit #2
Turbine
200 Kaplan Runner Voith -
201 Trunnion seals Voith -
202 Shaft Mechanical Seal Voith -
203 Pitch control Servo Voith -
204 Runner side guide bearing - -
205 Thrust bearing - -
206 Wicket gates & controls Voith -
207 Brake system Voith -
Reducer 208 gearbox speed reducer Voith H19632
Generator 209 2000 KW Rotating Electric Generator Yaskawa 515386102
Exciter 210 Electronic Exciter #1 Basler DECS-200 Mounted on S3
Governor
211 HPU Continental -
212 Accumulator Wilkes & McLean -
213 LP2 Controls Hydraulic Main Floor - -
214 HPU Motor #1 Baldor 36VF71B
215 HPU Motor #2 Baldor CM3714T
216 Accumulator Motor Baldor VM3558
217 Governor oil tank --
X-A-01 (a,b)
Sub-System Asset # Description MFG Serial #
Lube Oil System
218 Filtration Assembly - -
219 Filtration System Motor Baldor VM3558
220 Lube Oil Motor Leeson 170165.6
221 Lube Oil Pump - -
222 Heat exchanger motor Baldor VM3554T
223 Heat exchanger Thermal Trans Z7677
224 Lube oil tank 2 - -
Electrical Switchgear
225 Cabinet 52 for Generator #2 - -
226 Ground Fault Relay Bassler BE1-59N Mounted on S2
227 Gen Differential Relay Bassler BE1-87G Mounted on S2
228 Gen Protection System Bassler BE1-GPS Mounted on S2
229 ITE Breaker 4.76 KV - -
230 Cabinet 55 for Generator #2 - -
231 Misc. gauges and indicator readouts - Mounted on S3
232 VFD cabinet Unit #2 - -
233 Unit #2 HPU VFD controller - AC5550-U1.015A-4
234 Unit #2 LOP VFD controller - 22BD012N104
235 Starter intake fan VFD controller - -
236 Starter exhaust fan VFD controller --
X-A-01 (a,b)
Table A-3
Failure Mode and Effects Analysis (FMEA)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Local System Plant LTA Comments
1.1 100 & 200 Kaplan Runner 1.00 Cavitation And Wear on Runner
1.11 Normal Wear on Runner (Age Related) x x x Even Though Effects Only One Turbine, Both Turbines Are Needed to Pass CFS At Some Conditions, Cost of Failure Too Great (Red). 1.12 Cavitation Caused by Improper Adjustment of Blade Pitch x x x
1.2 100 &200 Kaplan Runner 1.20 Catastrophic Failure of Runner
1.21 Impact Damage from Foreign Object x x x Plant Issue Due to Environmental Contamination 1.22 Impact Damage from Turbine Gate Component x x x
2.1 101 & 201 Trunnion Seal 2.10 Worn Seal 2.11 Normal Wear on Seal (Age Related) x x x x Plant Issue Affects Both Turbines 2.12 Mechanical Failure of Seal Keepers x x x x
2.2 102 & 202 Trunnion Seal 2.20 Worn Seal 2.21 Normal Wear on Seal (Age Related) x x x
2.22 Mechanical Failure of Seal Keepers
3.1 102& 202 Mechanical Seal 3.10 Worn Seal 3.11 Normal Wear on Seal (Age Related)
3.12 Flush Water Lines Plugged Not on Trunnion Not Used on Mechanical
3.2 102& 202 Mechanical Seal 3.20 Worn Seal 3.11 Normal Wear on Seal (Age Related) Plant Issue Affects Both Turbines 3.12 Flush Water Lines Plugged Not on Trunnion Not Used on Mechanical x x x x
4.1 102 & 202 Pitch Control Servo 4.10 Servo and Linkages Frozen in Position
4.11 Servo Cylinder Scored or Damaged and Frozen into Cylinder x x x
4.12 Linkage or Bushing Bearings Broken or Severed or Frozen in Position x x x
4.2 102 & 202 Pitch Control Servo 4.20 Servo and Linkages Out of Adjustment
4.21 Linkage or Connecting Bushings Loose (Primary Control Electronic) x x x
4.22 Leaking Fittings and Servo
5.1 103 & 203 Runner Side Guide Bearing 5.10 Guide Bearing Wear
5.11 Normal Bearing Wear (Age Related) x x x
5.12 Contaminated Lube Oil (Premature Wear) x x x
5.13 Shaft Misalignment (Uneven Wear) x x x
5.2 104 & 203 Runner Side Guide Bearing 5.20 Guide Bearing Liner Failure
5.21 Contaminated Lube Oil (Premature Wear) Mechanical Seal Failure Water Contamination x x x
5.22 Shaft Misalignment (Uneven Wear) x x x
5.23 Excessive Radial Clearance x x x
6.1 104 & 204 Thrust Bearing 6.10 Thrust Bearing Liner Wear (Look Up) 6.11 Shaft Misalignment (Uneven Wear) x x x
6.2 104 & 204 Thrust Bearing 6.20 Thrust Bearing Liner Wear (Look Up) 6.22 Shaft Misalignment (Uneven Wear) x x x
6.3 104 & 204 Thrust Bearing 6.30 Thrust Bearing Liner Wear (Look Up)
6.31 Shaft Misalignment (Uneven Wear) x x x
6.32 Contaminated Lube Oil (Premature Wear) x x x
6.33 Excessive Radial Clearance x x x
7.1 105 & 205 Wicket Gates & Controls 7.10 Stiction in Gates and Controls
7.11 Wear In Bushings x x x
7.12 Foreign Object or Debris in Wickets x x x
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Local System Plant LTA Comments
7.2 105 & 205 Wicket Gates & Controls 7.20 Frozen Or Broken Gates and Controls
7.21 Wear In Bushings x x x
7.22 Foreign Object or Debris in Wickets x x x
8.1 106 & 206 Brake System 8.10 Worn Brake Shoes 8.11 Normal Wear on Linings (Age Related) x x x
8.2 106 & 206 Brake System 8.20 Failed Brake Mechanism 8.21 Excessive Stress on Brake Components Caused by Overspeed x x x
9.1 107 & 207 Gearbox Speed Reducer 9.10 Gearbox Bearing or Gear Failure
9.11 Bearing Failure (Age Related) x x x
9.12 Bearing Failure (Lube Related) x x x
9.13 Gear Failure (Age Related) x x x
9.14 Gear Failure (Lube Related) x x x
9.15 Coupling Failure (Turbine /Gearbox) x x x
9.16 Coupling Failure (Gearbox Generator) x x x
9.17 Gearbox Seal Failure (Age Related) x x x
10.1 108 & 208 Rotating Electric Generator 10.10 Generator Stator or Field Failure
10.11 Rotor Winding Resistance (Age Related) x x x
10.12 Stator Winding Resistance (Age Related) x x x
10.13 Stator Wedges or Bar Failures x x x
10.14 End Winding Supports and Connections Failure x x x
10.15 Air Cooling and Ventilation Failure x x x
10.16 Upstream And Downstream Generator Bearing Failures x x x
10.17 Diode Failure x x x
11.1 109 & 209 Electronic Exciter #1 11.1 Electronic Failure 11.11 Electronic Failure x x x
12.1 109 & 209 Electronic Exciter #1 12.10 Electronic Failure 12.11 Electronic Failure x x x
13.1 110 & 210 HPU 13.10 No Control Hydraulic Oil Pressure or Flow 13.11 Electronic Failure x x x
14.11 111 & 211 Accumulator 14.10 Low Pressure in Bladder
14.11 Broken Bladder x x x
13.1214.12 Low Nitrogen Charge x x x
15.1 111 & 211 Accumulator 15.10 Low Pressure in Bladder
15.11 Broken Bladder x x x
15.12 Low Nitrogen Charge x x x
16.1 112 & 212 Governor Oil Tank 16.10 Corroded Oil Tank That Leaks 16.10 Corrosion Due to Age x x x
16.2 112 & 212 Governor Oil Tank 16.20
Catastrophic Failure of Oil Tank Due to Overpressure
16.22 Cannot Be Overpressure x x x
17.1 113 & 213 Lp1&2 Controls Hydraulic Main Floor 17.10 Electronic Failure 17.11 Electronic Failure x x x
18.1 114 & 214 HPU Motor #1 18.10 18.11 Motor Bearing Failure x x x
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Local System Plant LTA Comments
No Control Hydraulic Oil Pressure or Flow 18.12 Electronic Failure x x x
19.1 115 & 215 HPU Motor #2 19.10 No Control Hydraulic Oil Pressure or Flow
19.11 Motor Bearing Failure x x x
19.12 Electronic Failure x x x
20.1 116 & 216 Accumulator Motor Fluid Trans 20.10 Overheated Lube & Hydraulic Oil
20.11 Motor Bearing Failure x x x
20.12 Electronic Failure x x x
21.1 117 & 217 Filtration Assembly 21.10 Contaminated Filter 21.11 Defective Filter x x x
21.2 117 & 217 Filtration Assembly 21.20 Plugged Filter 21.12 Plugged Filter (Age or Pressure Drop) Trip Off Turbine x x x
21.3 118 & 218 Filtration System Motor 21.30 No Oil Pressure 21.13 Motor Bearing Failure x x x
21.14 Electronic Failure x x x
22.1 119 & 219 Lube Oil Motor 22.10 No Oil Pressure 22.11 Motor Bearing Failure x x x
22.12 Electronic Failure x x x
23.1 120 & 220 Lube Oil Pump 23.10 Pump Impeller Worn 23.11 Normal Wear (Age Related) x x x
23.2 120 & 220 Lube Oil Pump 23.20 Pump Relief Valve Improperly Set or Failed 23.21 Relief Valve Failure Components Frozen or Rusted In Position x x x
24.1 121 & 221 Heat Exchanger Cooling Fan Motor 24.10 Overheated Lube & Hydraulic Oil
24.11 Motor Bearing Failure x x x
24.12 Electronic Failure x x x
25.1 122 & 222 Heat Exchanger 25.10 Fouled Heat Exchanger 25.12 Build Up on Oil Side of Heat Exchanger or Debris on Air Side (Time Factor) x x x
25.2 122 & 222 Heat Exchanger 25.20 Thermostat Failure 25.21 Buildup of Insulating Contaminant on Temperature Sensor (Mechanical) x x x
25.3 122 & 222 Heat Exchanger 25.30 Heat Exchanger Tube Failure 25.31 Tube Rupture Due to Overheating & Corrosion x x x
26.1 123 & 223 Lube Oil Tank 1 & 2 26.10 Loss Of Integrity of Tank 26.12 Tank Failure Due to Corrosion x x x
26.2 123 & 223 Lube Oil Tank 1 & 2 26.20 Loss Of Integrity of Tank 26.21 Tank Failure Due to Corrosion x x x
27.1 Multi Electrical Switchgear 27.10 Electronic Failure 27.12 Electronic Failure x x x
28.1 134 Unit #1  HPU VFD 28.10 Electronic Failure 28.12 Electronic Failure x x x
29.1 135 Unit #1  LOP VFD 29.10 Electronic Failure 29.12 Electronic Failure x x x
X-A-01 (a,b)
Table A-4
Logic (Decision) Tree Analysis (LTA)
Functional
Failure
Functional
Failure # Asset # Asset Description
Failure
Mode
#
Failure Mode Description Evident Safety Outage Cat Comments
- 1.1 100 & 200 Kaplan Runner 1.00 Cavitation And Wear on Runner N N Y D/B
- 1.2 100 & 200 Kaplan Runner 1.20 Catastrophic Failure of Runner Y Y Y B
- 2.1 101 & 201 Trunnion Seal 2.10 Worn Seal Y N Y B
- 2.2 102 & 201
Trunnion Seal
2.20
Worn Seal Y N Y B
Mechanical Seal Worn Seal Y N Y B
Mechanical Seal Worn Seal Y N Y B
- 3.1 102 & 202 Pitch Control Servo 3.10 Servo And Linkages Frozen in Position Y N Y B
- 3.2 103 & 202 Pitch Control Servo 3.20 Servo and Linkages Out of Adjustment Y N Y B
- 4.1 103 & 203 Runner Side Guide Bearing 4.10 Guide Bearing Wear N N Y D/B
- 4.2 104 & 203 Runner Side Guide Bearing 4.20 Guide Bearing Liner Failure N N Y D/B
- 5.1 104 & 204 Thrust Bearing 5.10 Thrust Bearing Liner Wear (Look Up) N N Y D/B
- 5.2 104 & 204 Thrust Bearing 5.20 Thrust Bearing Liner Wear (Look Up) N N Y D/B
- 5.3 104 & 204 Thrust Bearing 5.30 Thrust Bearing Liner Wear (Look Up) N N Y D/B
- 6.1 105 & 205 Wicket Gates & Controls 6.10 Stiction In Gates and Controls Y N Y B
- 6.2 105 & 205 Wicket Gates & Controls 6.20 Frozen or Broken Gates and Controls Y Y Y A
- 7.1 106 & 206 Brake System 7.10 Worn Brake Shoes N N Y D/B
- 7.2 106 & 206 Brake System 7.20 Failed Brake Mechanism Y Y Y A
- 8.1 107 & 207 Gearbox Speed Reducer 8.10 Gearbox Bearing or Gear Failure Y N Y B
- 9.1 108 & 208 Rotating Electric Generator 9.10 Generator Stator or Field Failure Y Y Y A
- 10.1 109 & 209 Electronic Exciter #1 10.10 Electronic Failure Y N Y B
- 11.1 109 & 209 Electronic Exciter #1 11.10 Electronic Failure Y N Y B
- 12.1 110 & 210 HPU 12.10 No Control Hydraulic Oil Pressure or Flow Y N Y B
- 13.1 111 & 211 Accumulator 13.10 Low Pressure in Bladder Y N Y B
- 14.1 111 & 211 Accumulator 14.10 Low Pressure in Bladder Y N Y B
- 15.1 112 & 212 Governor Oil Tank 15.10 Corroded Oil Tank that Leaks Y Y Y A
- 15.2 112 & 212 Governor Oil Tank 15.20 Catastrophic Failure of Oil Tank Due to Overpressure Y Y Y A
- 16.1 113 & 213 LP1&2 Controls Hydraulic Main Floor 16.10 Electronic Failure Y N Y B
- 17.1 114 & 214 HPU Motor #1 17.10 No Control Hydraulic Oil Pressure or Flow Y N Y B
- 18.1 115 & 215 HPU Motor #2 18.10 No Control Hydraulic Oil Pressure or Flow Y N Y B
- 19.1 116 & 216 Accumulator Motor Fluid Trans 19.10 Overheated Lube & Hydraulic Oil Y N Y B
- 20.1 117 & 217 Filtration Assembly 20.10 Contaminated Filter Y N Y B
- 20.2 117 & 217 Filtration Assembly 20.20 Plugged Filter Y N Y B
X-A-01 (a,b)
Functional
Failure
Functional
Failure # Asset # Asset Description
Failure
Mode
#
Failure Mode Description Evident Safety Outage Cat Comments
- 21.1 118 & 218 Filtration System Motor 21.10 No Oil Pressure Y N Y B
- 22.1 119 & 219 Lube Oil Motor 22.10 No Oil Pressure Y N Y B
- 23.1 120 & 220 Lube Oil Pump 23.10 Pump Impeller Worn Y N Y D/B
- 23.2 120 & 220 Lube Oil Pump 23.20 Pump Relief Valve Improperly Set or Failed N N Y D/B
- 24.1 121 & 221 Heat Exchanger Cooling Fan Motor 24.10 Overheated Lube & Hydraulic Oil Y N Y B
- 25.1 122 & 222 Heat Exchanger 25.10 Fouled Heat Exchanger N N N C
- 25.2 122 & 222 Heat Exchanger 25.20 Thermostat Failure N N Y B
- 25.3 122 & 222 Heat Exchanger 25.30 Heat Exchanger Tube Failure N Y Y D/A River Water Contamination
- 26.1 123 & 223 Lube Oil Tank 1 & 2 26.10 Loss of Integrity of Tank Y Y Y D/A River Water Contamination
- 26.2 123 & 223 Lube Oil Tank 1 & 2 26.20 Loss of Integrity of Tank Y Y Y D/A River Water Contamination
- 27.1 Multi Electrical Switchgear 27.10 Electronic Failure Y N Y B
- 28.1 134 Unit #1  HPU VFD 28.10 Electronic Failure Y N Y B
- 29.1 135 Unit #1  LOP VFD 29.10 Electronic Failure Y N Y B
Unit #2
Intake And Discharge Equipment
32.1 300 Trash Rack 32.10 Holes In Trash Rack Allow Debris Through Y N Y B
33.1 301 Trash Rack Cleaner 33.10 Failed Cleaner Mechanism Y N Y B
34.1 302 Intake Flume 34.10 Failed Integrity of Flume Y Y Y A
35.1 303 Draft Tube 35.10 Failed Integrity of Draft Tube Y Y Y A
Electrical
36.1 304 Backup Generator 36.10 Failed Generator Y Y N A
37.1 305 Breaker De-Watering Use 37.10 Electronic Failure N N N C
38.1 306 Battery Storage System 38.10 Batteries Discharged; No Power Available N Y Y D/A
39.1 307 Sump Starter/Control 39.10 Electronic Failure N Y Y A
40.1 308 Starter/Relays-Sump Pumps 40.10 Electronic Failure N Y Y A
41.1 309 Trolley & Hoist Controls/Disconnect 41.10 Electronic Failure N N Y B Needed to Correct Other Failures
42.1 Multi Common Power Elec Tx Equip 42.10 Electronic Failure N N Y B
Sump Pumps and Compressors
43.1 Multi Submersible Sump Pump 43.10 Pump Failure N N Y B
44.1 326 Emergency B/U Pump 44.10 Pump Failure N Y Y A
45.1 234 Emergency B/U Pump Motor 45.10 Electronic Failure N Y Y A
HVAC 46.1 Multi Starter Exhaust Fan VFD 46.10 Electronic Failure N N N C
X-A-01 (a,b)
Table A-5
Task Selection
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Question # Candidate task Effective Info Est Freq Comments 1 2 3 4 5 6 7
1.1 100 & 200 Kaplan Runner 1.00 Cavitation And Wear on Runner
1.11 Normal Wear on Runner (Age Related) N N N Y Y Y N Turbine Minor Inspection 5yr 5yr
1.12 Cavitation Caused by Improper Adjustment of Blade Pitch N N N N Y Y N Turbine Minor Inspection 5yr 5yr
1.2 100 & 200 Kaplan Runner 1.20 Catastrophic Failure of Runner
1.21 Impact Damage from Foreign Object N N N N Y Y N Turbine Minor Inspection 5yr 5yr
1.22 Impact Damage from Turbine Gate Component N N N N Y Y N Turbine Minor Inspection 5yr 5yr
2.1 101 & 201 Trunnion Seal 2.10 Worn Seal
2.11 Normal Wear on Seal (Age Related) N N N N Y Y N Turbine Minor Inspection 5yr 5yr
2.12 Mechanical Failure of Seal Keepers N N N N Y Y N Turbine Minor Inspection 5yr 5yr
2.2 102 & 201
Trunnion Seal
2.20
Worn Seal
2.21 Normal Wear on Seal (Age Related) N N N N Y Y N Turbine Minor Inspection 5yr 5yr
2.22
Mechanical Failure of Seal Keepers N N N N Y Y N Turbine Minor Inspection 5yr 5yr
Mechanical Seal Worn Seal
Normal Wear on Seal (Age Related) N N N N Y Y N Turbine Minor Inspection 5yr 5yr
Flush Water Lines Plugged N N N N Y Y N Turbine Minor Inspection 5yr 5yr
Mechanical Seal Worn Seal
Normal Wear on Seal (Age Related) N N N N Y Y N Turbine Minor Inspection 5yr 5yr
Flush Water Lines Plugged N N N N Y Y N Turbine Minor Inspection 5yr 5yr
3.1 102 & 202 Pitch Control Servo 3.10 Servo And Linkages Frozen in Position
3.11 Servo Cylinder Scored or Damaged and Frozen into Cylinder N N N N Y Y N Turbine Major Inspection 25yr 25yr
3.12 Linkage Or Bushing Bearings Broken or Severed or Frozen in Position N N N N Y Y N Turbine Minor Inspection 5yr 5yr
3.2 103 & 202 Pitch Control Servo 3.20 Servo And Linkages Out of Adjustment 3.21
Linkage Or Connecting Bushings Loose (Primary Control Electronic) N N N N Y Y N Turbine Minor Inspection 5yr 5yr
Leaking Fittings and Servo N N N N Y Y N Turbine Minor Inspection 5yr 5yr
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Question # Candidate task Effective Info Est Freq Comments 1 2 3 4 5 6 7
4.1 103 & 203 Runner Side Guide Bearing 4.10 Guide Bearing Wear
4.11 Normal Bearing Wear (Age Related) N N N N Y Y N Turbine Minor Inspection 10yr/Bearing Replacement 10yr Condition Based Replacement
4.12 Contaminated Lube Oil (Premature Wear) N N N N Y Y N Oil Tests/Turbine Minor Inspection 10yr 10yr Quarterly Oil Tests
4.13 Shaft Misalignment (Uneven Wear) N N N Y Y Y N Turbine Minor Inspection 10yr 10yr
4.2 104 & 203 Runner Side Guide Bearing 4.20 Guide Bearing Liner Failure
4.21
Contaminated Lube Oil (Premature Wear) Mechanical Seal Failure Water Contamination
N N N Y Y Y N Oil Tests/Turbine Minor Inspection 10yr 10yr Quarterly Oil Tests
4.22 Shaft Misalignment (Uneven Wear) N N N Y Y Y N Turbine Minor Inspection 10yr 10yr
4.23 Excessive Radial Clearance N N N Y Y Y N Turbine Minor Inspection 10yr 10yr
5.1 104 & 204 Thrust Bearing 5.10 Thrust Bearing Liner Wear (Look Up) 5.11 Shaft Misalignment (Uneven Wear) N N N Y Y Y N Turbine Minor Inspection 10yr 10yr
5.2 104 & 204 Thrust Bearing 5.20 Thrust Bearing Liner Wear (Look Up) 5.21 Shaft Misalignment (Uneven Wear) N N N Y Y Y N Turbine Minor Inspection 10yr 10yr
5.3 104 & 204 Thrust Bearing 5.30 Thrust Bearing Liner Wear (Look Up)
5.31 Shaft Misalignment (Uneven Wear) N N N Y Y Y N Turbine Minor Inspection 10yr 10yr
5.32 Contaminated Lube Oil (Premature Wear) N N N N Y Y N Oil Tests/Turbine Minor Inspection 10yr 10yr Quarterly Oil Tests
5.33 Excessive Radial Clearance N N N N Y Y N Turbine Minor Inspection 10yr 10yr
6.1 105 & 205 Wicket Gates & Controls 6.10 Stiction In Gates and Controls
6.11 Wear In Bushings N N N N Y Y N Turbine Major Inspection 25yr 25yr
6.12 Foreign Object or Debris in Wickets N N N N Y Y N Turbine Minor Inspection 5yr 5yr
6.2 105 & 205 Wicket Gates & Controls 6.20 Frozen Or Broken Gates and Controls
6.21 Wear In Bushings N N N N Y Y N Turbine Major Inspection 25yr 25yr
6.22 Foreign Object or Debris in Wickets N N N N Y Y N Turbine Minor Inspection 5yr 5yr
7.1 106 & 206 Brake System 7.10 Worn Brake Shoes 7.11 Normal Wear on Linings (Age Related) N N N Y Y Y N Turbine Minor Inspection 5yr 5yr
7.2 106 & 206 Brake System 7.20 Failed Brake Mechanism 7.21 Excessive Stress on Brake Components Caused by Overspeed N N N N Y Y N Turbine Minor Inspection 5yr 5yr
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Question # Candidate task Effective Info Est Freq Comments 1 2 3 4 5 6 7
8.1 107 & 207 Gearbox Speed Reducer 8.10 Gearbox Bearing or Gear Failure
8.11 Bearing Failure (Age Related) N N N N Y Y N Vibration Tests/Turbine Minor Inspection 10yr 10yr Quarterly Vibration Test
8.12 Bearing Failure (Lube Related) N N N N Y Y N Oil Tests/Turbine Minor Inspection 10yr 10yr Quarterly Oil Test
8.13 Gear Failure (Age Related) N N N N Y Y N Vibration Tests/Turbine Minor Inspection 10yr 10yr Quarterly Vibration Test
8.14 Gear Failure (Lube Related) N N N N Y Y N Oil Tests/Turbine Minor Inspection 10yr 10yr Quarterly Oil Test
8.15 Coupling Failure (Turbine /Gearbox) N N N N Y Y N Vibration Tests/Turbine Minor Inspection 10yr 10yr Quarterly Vibration Test
8.16 Coupling Failure (Gearbox Generator) N N N N Y Y N Vibration Tests/Turbine Minor Inspection 10yr 10yr Quarterly Vibration Test
8.17 Gearbox Seal Failure (Age Related) N N N N Y Y N Turbine Minor Inspection 10yr 10yr
9.1 108 & 208 Rotating Electric Generator 9.10 Generator Stator or Field Failure
9.11 Rotor Winding Resistance (Age Related) N N N N Y Y N Generator Electrical Inspection 5yr 5yr
9.12 Stator Winding Resistance (Age Related) N N N N Y Y N Generator Electrical Inspection 5yr 5yr
9.13 Stator Wedges or Bar Failures N N N N Y Y N Generator Electrical Inspection 12yr 12yr
9.14 End Winding Supports and Connections Failure N N N N Y Y N Generator Electrical Inspection 12yr 12yr
9.15 Air Cooling and Ventilation Failure N N N N Y Y N Generator Electrical Inspection 12yr 12yr
9.16 Upstream And Downstream Generator Bearing Failures N N N N Y Y N Generator Electrical Inspection 12yr 12yr
9.17 Diode Failure N N N N Y Y N Generator Electrical Inspection 5yr 5yr
10.1 109 & 209 Electronic Exciter #1 10.10 Electronic Failure 10.11 Electronic Failure N N N N Y Y N Switch Gear Clean & Test 3yr
11.1 109 & 209 Electronic Exciter #1 11.10 Electronic Failure 11.11 Electronic Failure N N N N Y Y N Switch Gear Clean & Test 3yr
12.1 110 & 210 HPU 12.10 No Control Hydraulic Oil Pressure or Flow 12.11 Electronic Failure N N N N Y Y N Switch Gear Clean & Test 3yr
13.1 111 & 211 Accumulator 13.10 Low Pressure in Bladder
13.11 Broken Bladder N N N N Y Y N Vessel Inspection 5yr
13.12 Low Nitrogen Charge N N N N Y Y N Vessel Inspection 5yr
14.1 111 & 211 Accumulator 14.10 Low Pressure in Bladder
14.11 Broken Bladder N N N N Y Y N Vessel Inspection 5yr
14.12 Low Nitrogen Charge N N N N Y Y N Vessel Inspection 5yr
15.1 112 & 212 Governor Oil Tank 15.10 Corroded Oil Tank That Leaks 15.11 Corrosion Due to Age N N N N Y Y N Vessel Inspection 5yr
15.2 112 & 212 Governor Oil Tank 15.20 Catastrophic Failure of Oil Tank Due to Overpressure 15.21 Cannot Be Overpressure N N N N N N N No PM Required
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Question # Candidate task Effective Info Est Freq Comments 1 2 3 4 5 6 7
16.1 113 & 213 LP1&2 Controls Hydraulic Main Floor 16.10 Electronic Failure 16.11 Electronic Failure N N N N Y Y N Switch Gear Clean & Test
17.1 114 & 214 HPU Motor #1 17.10 No Control Hydraulic Oil Pressure or Flow
17.11 Motor Bearing Failure N N N N Y Y N Vibration Tests Quarterly
17.12 Electronic Failure N N N N N N N RTF
18.1 115 & 215 HPU Motor #2 18.10 No Control Hydraulic Oil Pressure or Flow
18.11 Motor Bearing Failure N N N N Y Y N Vibration Tests Quarterly
18.12 Electronic Failure N N N N N N N RTF
19.1 116 & 216 Accumulator Motor Fluid Trans 19.10 Overheated Lube & Hydraulic Oil
19.11 Motor Bearing Failure N N N N Y Y N Vibration Tests Quarterly
19.12 Electronic Failure N N N N N N N RTF An Alternative is That Small Electric Motors Could be Either Replaced or Rebuilt on a Time-Based Interval
20.1 117 & 217 Filtration Assembly 20.10 Contaminated Filter 20.12 Defective Filter N N N N N N N R&R Filter As Required Defective Filter Will Show Signs (Hi DP) at Start of Use, Replace Filter
20.2 117 & 217 Filtration Assembly 20.20 Plugged Filter 20.12 Plugged Filter (Age or Pressure Drop) Trip Off Turbine N N N N Y Y N R&R Filter As Required
Establish Typical Time or Operating Hour Interval and Replace Filter on Routine Basis
21.1 118 & 218 Filtration System Motor 21.10 No Oil Pressure
21.11 Motor Bearing Failure N N N N Y Y N Vibration Tests Quarterly
21.12 Electronic Failure N N N N Y Y N RTF An Alternative is That Small Electric Motors Could be Either Replaced or Rebuilt on a Time-Based Interval
22.1 119 & 219 Lube Oil Motor 22.10 No Oil Pressure
22.11 Motor Bearing Failure N N N N Y Y N Vibration Tests Quarterly
22.12 Electronic Failure N N N N N N N RTF An Alternative is That Small Electric Motors Could be Either Replaced or Rebuilt on a Time-Based Interval
23.1 120 & 220 Lube Oil Pump 23.10 Pump Impeller Worn 23.11 Normal Wear (Age Related) N N N Y Y Y N Turbine Minor Inspection 5yr 5yr
23.2 120 & 220 Lube Oil Pump 23.20 Pump Relief Valve Improperly Set or Failed 23.21 Relief Valve Failure Components Frozen or Rusted in Position N N N Y Y Y N Turbine Minor Inspection 5yr 5yr
24.1 121 & 221 Heat Exchanger Cooling Fan Motor 24.10 Overheated Lube & Hydraulic Oil
24.11 Motor Bearing Failure N N N N Y Y N Vibration Tests Quarterly
24.12 Electronic Failure N N N N N N N RTF An Alternative is That Small Electric Motors Could be Either Replaced or Rebuilt on a Time-Based Interval
25.1 122 & 222 Heat Exchanger 25.10 Fouled Heat Exchanger 25.12 Build Up on Oil Side of Heat Exchanger or Debris on Air Side (Time Factor) N N N N N N N RTF
25.2 122 & 222 Heat Exchanger 25.20 Thermostat Failure 25.21
Buildup of Insulating Contaminant on Temperature Sensor (Mechanical)
N N N N N N N RTF
25.3 122 & 222 Heat Exchanger 25.30 Heat Exchanger Tube Failure 25.31 Tube Rupture Due to Overheating & Corrosion N N N Y N N N RTF
26.1 123 & 223 Lube Oil Tank 1 & 2 26.10 Loss Of Integrity of Tank 26.12 Tank Failure Due to Corrosion N N N Y Y Y N Vessel Inspection 5yr
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Question # Candidate task Effective Info Est Freq Comments 1 2 3 4 5 6 7
26.2 123 & 223 Lube Oil Tank 1 & 2 26.20 Loss Of Integrity of Tank 26.21 Tank Failure Due to Corrosion N N N Y Y Y N Vessel Inspection 5yr
27.1 Multi Electrical Switchgear 27.10 Electronic Failure 27.12 Electronic Failure N N N N Y Y N Switch Gear IR & Clean & Test 1-3yr IR Tests Annual, Clean & Test 3yr
28.1 134 Unit #1  HPU VFD 28.10 Electronic Failure 28.12 Electronic Failure N N N N Y Y N Switch Gear IR & Clean & Test 1-3yr
29.1 135 Unit #1  LOP VFD 29.10 Electronic Failure 29.12 Electronic Failure N N N N Y Y N Switch Gear IR & Clean & Test 1-3yr
Intake And Discharge Equipment
32.1 300 Trash Rack 32.10 Holes In Trash Rack Allow Debris Through 32.11 Holes Caused by Mechanical Damage Removing Ice and Debris N N Y N Y Y N Visual External & NDT Of Flumes 5yr Coordinate Inspection to Coincide with FERC Part 12D
33.1 301 Trash Rack Cleaner 33.10 Failed Cleaner Mechanism 33.11 Physical Damage to Unit Ruin to Remove Ice and Debris N N Y N Y Y N Visual External & NDT Of Flumes 5yr Coordinate Inspection to Coincide with FERC Part 12D
34.1 302 Intake Flume 34.10 Failed Integrity of Flume 34.11 Flume Failure Cause by Corrosion and Erosion N N Y N Y Y N Visual External & NDT Of Flumes 5yr Coordinate Inspection to Coincide with FERC Part 12D
35.1 303 Draft Tube 35.10 Failed Integrity of Draft Tube 35.13 Draft Tube Failure Caused by Corrosion and Erosion N N Y N Y Y N Visual External & NDT Of Flumes 5yr Coordinate Inspection to Coincide with FERC Part 12D
Electrical
36.1 304 Backup Generator 36.10 Failed Generator
36.11 Engine Will Not Start Due to Fuel Issues Y Y Y N Y Y N Backup Generator Maintenance 1yr Yearly Maintenance + Routine Starts
36.12 Engine Will Not Start Due to Battery and Starter Issues Y Y Y N Y Y N Backup Generator Maintenance 1yr Yearly Maintenance + Routine Starts
36.13 Engine Will Not Start Due to Ignition Issues Y Y Y N Y Y N Backup Generator Maintenance 1yr Yearly Maintenance + Routine Starts
36.14 Engine Starts but Fails to Generate Power Due to Electrical Issues Y Y Y N Y Y N Backup Generator Maintenance 1yr Yearly Maintenance + Routine Starts
37.1 305 Breaker De-Watering Use 37.10 Electronic Failure 37.11 Electronic Failure N N N N Y Y N Switch Gear Ir & Clean & Test 1-3yr
38.1 306 Battery Storage System 38.10 Batteries Discharged; No Power Available
38.11 Batteries Failed Y Y N Y Y Y N Battery Station Maintenance 1yr
38.12 Charger Failed Due to Electronic Issues N N N Y Y Y N Battery Station Maintenance 1yr
39.1 307 Sump Starter/Control 39.10 Electronic Failure 39.11 Electronic Failure N N N N Y Y N Switch Gear Ir & Clean & Test 1-3yr
40.1 308 Starter/Relays-Sump Pumps 40.10 Electronic Failure 40.11 Electronic Failure N N N N Y Y N Switch Gear Ir & Clean & Test 1-3yr
41.1 309 Trolley & Hoist Controls/Disconnect 41.10 Electronic Failure 41.11 Electronic Failure N N N N Y Y N Switch Gear IR & Clean & Test 1-3yr
42.1 Multi Common Power Elec Tx Equip 42.10 Electronic Failure 42.11 Electronic Failure N N N N Y Y N Switch Gear Ir & Clean & Test 1-3yr
Sump Pumps and Compressors
43.1 Multi Submersible Sump Pump 43.10 Pump Failure 43.11 Bearing Failure N N N N Y Y N Vibration Tests Quarterly
X-A-01 (a,b)
Functional Failure # Asset # Asset Description Failure Mode # Failure Mode Description Failure Cause # Failure Cause Description Question # Candidate task Effective Info Est Freq Comments 1 2 3 4 5 6 7
44.1 326 Emergency B/U Pump 44.10 Pump Failure 44.11 Bearing Failure N N N N Y Y N Vibration Tests Quarterly
45.1 234 Emergency B/U Pump Motor 45.10 Electronic Failure 45.11 Electronic Failure N N N N Y Y N Switch Gear & Clean & Test 1-3yr
HVAC
46.1 Multi Starter Exhaust Fan VFD 46.10 Electronic Failure 46.11 Electronic Failure Run To Failure
Q1 Is the age reliability relationship for this failure known? Q2 Are there any applicable time dependent (TD) tasks? Q3 Are there any applicable condition dependent (CD) tasks? Q4 Is this a category "D" failure mode? Q5 Are there any applicable failure finding (FF) tasks? Q6 Are any of these tasks effective? Q7 Can a design mod eliminate the failure mode or effects?
X-A-01 (a,b)
Table A-6
Preliminary Maintenance Recommendation
Inspection Title Equipment Scope of Work Frequency Cost Estimate
($ Per Turbine) Dewater4
Turbine Minor Inspection 5yr Kaplan Runner Guide and Thrust Bearings, Wicket Gates Hydraulics, Gearbox
Minor Inspection, Visual Internal of Runner, Wicket Gates, Wicket and Blade Tip Clearances Checked, Checked Seals Replaced, Stroke Wicket Gates and Kaplan Blades, Check Oil for Water, Tear Down, Inspect and Repair the Lube Oil Pump & Relief Valve, Brake System Inspection, Seal Bladder Check, Inflatable Seal Bladder Check Before and After Dewatering
5 years 75,000 - 125,000 Yes
Turbine Minor Inspection 10yr Kaplan Runner Guide and Thrust Bearings, Wicket Gates Hydraulics, Gearbox Minor Inspection, Visual Internal of Runner, Wicket Gates, Bearing Covers Removed Liner Inspected Alignment and Clearances Checked, Gearbox Cover Removed Clearances Checked Seals Replaced 10 years 125,000 - 250,000 Yes
Turbine Major Inspection 25yr Kaplan Runner Guide and Thrust Bearings, Wicket Gates Hydraulics, Gearbox Major Inspection, Complete Turbine Rebuilds, Bearing Replacement, Alignment, Kaplan & Wicket Gate Servo Rebuild, Gearbox Rebuild 25 years 500,000 -1,000,000 Yes
Vibration Testing Kaplan Runner Guide and Thrust Bearings, Wicket Gates Hydraulics, Gearbox Vibration Analysis Quarterly 3,000 - 5,000 No
Oil Testing Kaplan Runner Guide and Thrust Bearings, Wicket Gates Hydraulics, Gearbox Oil Analysis Quarterly - No
Generator Electrical Inspection 5yr Generator & Exciter Field & Stator
Test The Insulation Resistance, Winding Resistance, Polarization Index the Exciter Stator, Exciter Rotor, Generator Stator and Rotor, Operating Voltage Hi-Pot and Surge Comparison Test the Stator Winding, Ac Volt Drop Test the Rotor Coils, Test the Rotating Diode Assembly and Inspect All Winding and Generator Components for Wear and Deficiencies.
2-5 years 5,000 - 7,000 No
Generator Electrical Inspection 12yr Generator & Exciter Field & Stator, Bearings, Air Cooler
Minor Inspection, Dry Ice Clean Generator Windings, Inspect All Wedges And Winding Components, Test The Insulation Resistance, Winding Resistance, Polarization Index The Exciter Stator, Exciter Rotor, Generator Stator and Rotor, Operating Voltage Hi-Pot And Surge Comparison Test The Stator Winding, Ac Volt Drop Test the Rotor Coils, Test the Rotating Diode Assembly And Inspect all Winding and Generator Components for Wear and Deficiencies, Check Laser Alignment to Gear Box and Bearing Inspection.
12 years 25,000 - 35,000 No
Generator Rewind Generator & Exciter Field & Stator, Bearings, Air Cooler Generator & Excitor Rewind, Bearing Liner Replacement 25 ye25 yearsars25
200,000 - 300,000 No
Switchgear IR Switchgear Infrared Scans Annual 3,000 - 5,000 No
Switch Gear Clean & Test Switch Gear Trip & Relay Tests, Cleaning & Re-Certification 3 years or As Per Jurisdiction 30,000 - 45,000 No
Visual External & NDT Of Vessels Oil Tanks, Accumulators Visual External or Internal Inspection NDT, Inspect and Recharge Bladder as Required 5 years 3,000 - 5,000 No
Battery Station Maintenance Battery Station, Charger, Batteries & Switches Visual Inspection, Cleaning and Maintenance of Batteries, Load Tests, Hydrometer Test, Charging System and Switch Functionality Test 1 year 3,000 - 5,000 No
25 years
X-A-01 (a,b)
Inspection Title Equipment Scope of Work Frequency Cost Estimate
($ Per Turbine) Dewater4
Backup Generator Maintenance Backup Generator Engine, Generator, Controls and Switches Service, Inspection, and Maintenance of Backup Generator as per Manufacturers Recommendations 1 year 3,000 - 5,000 No
Visual External & NDT of Flumes Intake Flume, Draft Tube and Chest, Trash Rack Visual External or Internal Inspection NDT 5 years
5,000 - 10,000, Cost could be shared with FERC Part 12D Inspection
Yes, divers or submersible may be required
1)Due to dewatering expenses and logistics, both units are taken down sequentially the same year.2)Oil analysis currently is done by the plant.3)Assume that daily & weekly oiling and machine checks that are recommended by the OEM are performed by operations.4)Dewater costs estimated to be $200,000 for both turbines and should be added to the inspection cost, as appropriate.5)Minor inspection PM frequency set to match FERC Part 12D Inspection Requirement.6)Vessel inspection cost per vessel.
X-A-01 (a,b)
Appendix B
Figures
X-A-01 (a,b)
X-A-01 (a,b)
Appendix C
Present Value Calculations for Operating and Maintenance Costs
X-A-01 (a,b)
Appendix C
Present Value Calculations for Operating and Maintenance Costs
Item Factor Total (approximate)
Average Annual Revenue 716,500$
P/A 14.0939
Revenue Present Worth (P)10,098,000$
Operating Costs (by City of Hastings) 450,000$
P/A 14.0939
Operations Present Worth (P)6,342,000$
Battery Station Maintenance 5,000$
Backup Generator Maintenance 5,000$
Vibration Testing 20,000$
Oil Testing 5,000$
Miscellaneous 25,000$
Total Annual Maintenace 60,000$
P/A 14.0939
Annual Maintenance Present Worth (P)846,000$
Switch Gear Clean & Test 45,000$
(P/F) n=3 0.8638 38,871$
(P/F) n=6 0.7462 33,579$
(P/F) n=9 0.6446 29,007$
(P/F) n=12 0.5568 25,056$
(P/F) n=15 0.481 21,645$
(P/F) n=18 0.4155 18,698$
(P/F) n=21 0.3589 16,151$
(P/F) n=24 0.3101 13,955$
3-year Maintenance Present Worth (P)197,000$
Turbine Minor Inspection 5yr 125,000$
Turbine Minor Inspection 5yr 125,000$
Generator Electrical Inspection 5yr 7,000$
Generator Electrical Inspection 5yr 7,000$
Dewater 450,000$
Total Cost Per 5yr 714,000$
(P/F) n=5 0.7835 559,419$
(P/F) n=15 0.481 343,434$
5-year Maintenance Present Worth (P)903,000$
Turbine Minor Inspection 10yr 250,000$
Turbine Minor Inspection 10yr 250,000$
Generator Electrical Inspection 10yr 35,000$
Generator Electrical Inspection 10yr 35,000$
Dewater 450,000$
Revenue
Operating Costs
Annual Maintenance Expenses
3 Year Maintenance Expenses
5 Year Maintenance Expenses
10 Year Maintenance Expenses
1 of 2
X-A-01 (a,b)
Appendix C
Present Value Calculations for Operating and Maintenance Costs
Item Factor Total (approximate)
Total Cost Per 10yr 1,020,000$
(P/F) n=10 0.6139 626,178$
(P/F) n=20 0.3769 384,438$
10-year Maintenance Present Worth (P)1,011,000.00$
Turbine Major Inspection 25yr 1,000,000$
Turbine Major Inspection 25yr 1,000,000$
Generator Rewind 300,000$
Generator Rewind 300,000$
Dewater 450,000$
Total Cost Per 25yr 3,050,000$
(P/F) n=0 1 3,050,000$
25-year Maintenance Present Worth (P)3,050,000$
12,349,000$
10,098,000$
(2,251,000)$
122%
25 Year Maintenance Expenses
Total Present Worth of O&M Costs
Net Cash (Revenue - O&M costs)
O&M % of Revenue
Total Revenue
2 of 2
X-A-01 (a,b)