Meeting Attachment A

Meeting Attachment A

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LINDA JINES LANETTE DOANE PATTY LAMBERTY

CITY CLERK CITY CLERK TREASURER CITY CLERK TREASURER

PO BOX D 217 NILE ST PO BOX 70

ALLIANCE, NE 69301-0770 ANSLEY, NE 68814 ARNOLD, NE 69120-0070

LINDA MANNING CHARLENE ANDERSON SAMANTHA JACKSON

CITY CLERK CITY CLERK CITY CLERK

130 S GALENA ST PO BOX 599 PO BOX 160

ASPEN, CO 81611-1902 BASIN, WY 82410-0599 BAYARD, NE 69334-0160

TERESA BARTLETT DIANE ROSENFELT TRICIA ALLEN

CITY CLERK TREASURER CITY CLERK TREASURER CITY CLERK TREASURER

PO BOX 185 PO BOX 347 PO BOX 277

BEAVER CITY, NE 68926-0185 BENKELMAN, NE 69021-0347 BLUE HILL, NE 68930-0277

DORI HUCK STEPHANIE WRIGHT SANDY PSOTA

CITY CLERK TREASURER CITY CLERK CITY CLERK TREASURER


BRIDGEPORT, NE 69336-0280 BROKEN BOW, NE 68822-0504 BURWELL, NE 68823-0604

LANETT CONROY MARTHA BECKER ASHLEA BAUER

CITY CLERK TREASURER CITY CLERK CITY ADMINISTRATOR CLERK


CALLAWAY, NE 68825-0157 CARLISLE, IA 50047-0430 CHAPPELL, NE 69129-0487

JUDI MEYER JOLENE NELSON CARISSA LUFKIN

CITY CLERK CITY CLERK CITY CLERK TREASURER


CRETE, NE 68333-0086 DELTA, CO 81416-0019 FAIRBURY, NE 68352-0554

GARY JORN MICHELLE ASFELD JOHN BRENNAN

CITY ADMINISTRATOR CLERK CITY CLERK CITY CLERK

2307 BARADA ST PO BOX 468 PO BOX 100

FALLS CITY, NE 68355-1546 FLEMING, CO 80728-0468 FORT MORGAN, CO 80701-0100

SILVIA HUFFMAN KATHY WELFL CATHERINE MYTHEN

CITY CLERK TREASURER CITY CLERK CITY CLERK

116 S MAIN ST PO BOX 687 101 W 8TH ST

FOUNTAIN, CO 80817-2282 GERING, NE 69341-0687 GLENWOOD SPRINGS, CO 81601-3303

RANAE EDWARDS JESSIE FABER ERICA BOUCHER

CITY CLERK CITY CLERK TREASURER CITY CLERK


GRAND ISLAND, NE 68802-1968 GRANT, NE 69140-0614 GUNNISON, CO 81230-0239

KIM JACOBITZ KARIE WILSON KATHLEEN OLOFSON

CITY CLERK CITY CLERK TREASURER CITY CLERK TREASURER

220 N HASTINGS PO BOX 205 407 E DENVER ST

HASTINGS, NE 68901-5144 HAXTUN, CO 80731-0205 HOLYOKE, CO 80734-1606

NOTE: per Chris & Michelle 6/26/2019, a copy of MEAN's notice to terminate was alsosent to the Center, CO Clerk even though their ERPA is still Pending and not yet signed.

Municipal Energy Agency of Nebraska Schedule K and Schedule K-1

Revised Section III Schedule of Rates and Charges

Date Approved: _________January 17, 2019 Effective date of this Schedule of Rates and Charges: September 1, 2019April 1, 2019

By: _____________________________________ Supersedes Schedule of Rates and Charges dated Effective April 1, 2019May 1, 2018

Page 1

This Schedule of Rates and Charges supplied to the City by MEAN is a part of the Bulk Power Participation, Service Schedule K and K-1 between MEAN and the City.

SECTION 1. SERVICES TO BE PROVIDED

1.01 This schedule applies to the Bulk Power Participation provided to the City.

SECTION 2. BILLING ENERGY

2.01 The Total Metered Energy shall be equal to the energy measured by metering equipment installed at the City in accordance with Article XIV of the Electrical Resources Pooling Agreement between MEAN and the City, adjusted for losses to the point or points where the City interconnects with the delivering transmission system.

2.02 Monthly Western Area Power Administration Energy Allocation

a. If the City has a Western Area Power Administration (“WAPA”) EnergyAllocation(s), Monthly WAPA Energy Allocation is equal to the firm energyallocation supplied by WAPA to the City through any of the following regions:WAPA Pick-Sloan Missouri Basin Project (“WAPA UGP”), WAPA Loveland AreaProjects (“WAPA LAP”), or WAPA Salt Lake City Area Integrated Projects (“WAPASLCA”), for that month.

b. In the event the Monthly WAPA Energy Allocation exceeds the Total MeteredEnergy, the Monthly WAPA Energy Allocation shall be equal to the Total MeteredEnergy for MEAN billing purposes.

2.03 Monthly MEAN Energy is equal to Total Metered Energy, less Monthly WAPA Energy Allocation, less any energy delivered pursuant to any Supplemental Agreement for Wind-Generated Energy Purchase between MEAN and the City (“Contracted Wind”), less any Support Energy as defined in Section 4.01.

SECTION 3. SCHEDULE OF RATES AND CHARGES

3.01 Fixed Cost Recovery Charge

a. The Fixed Cost Recovery Charge consists of costs related primarily to MEAN’sownership of generation, contracted purchase of generating capacity and theoperation of MEAN. The total Fixed Cost Recovery Charge is evaluated annually

Meeting Attachment B





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as part of the fiscal year budget process. The Fixed Cost Recovery Charge shall be allocated based on a three-year historical average non-coincident monthly peak demand (supplied by MEAN), by Participant. The Annual Period used for historical average non-coincident peak demand in the calculation is October – September. A five percent (5%) differential for Schedule K Participants is maintained within the fixed cost recovery structure. The calculated allocation may be adjusted at the discretion of the MEAN Management CommitteeBoard of Directors. The Fixed Cost Recovery Charge shall be billed to City in an amount as follows:

Fixed charge per City as shown on Attachment 1 to this Revised Section III.

3.02 Energy Charge

a. The Energy Charge per kilowatt-hour shall apply to MEAN Energy and shall bebilled at a rate equal to the then-current Service Schedule M Energy Charge perkilowatt-hour as defined in Section 3.02 of the Schedule of Rates and Charges forSchedule M plus five percent (5%) and applicable rounding. The billing rate forSchedule K and Schedule K-1 as of the effective date of this Schedule of Rates andCharges, is as follows:

$0.04017

b. The Energy Charge for MEAN Energy is also subject to Section 3.04, Pooled EnergyAdjustment (PEA) of this Schedule of Rates and Charges.

3.03 Customer Charge (applicable directly to City as customer) $0.00 per month

3.04 Pooled Energy Adjustment (“PEA”). The purpose of the PEA is to allow MEAN the ability to recover the costs on a monthly basis for energy purchased and generated whenever the actual monthly energy costs to MEAN exceed the budgeted monthly energy costs. The positive difference (“PEA Amount”) for the month will be applied to the Monthly MEAN Energy as defined in Section 2.03 for that month and Monthly Support Energy as defined in Section 4.01 for that month and may be billed during the succeeding billing period.

3.05 Power Factor. If the City's power factor at any Point of Delivery is less than 95%, the City's Fixed Cost Recovery Charge may be adjusted to reflect a 95% power factor and any third-party charges, fines or penalties will be passed through to City.





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3.06 The rates and charges established in this Revised Section III may be modified from time to time by MEAN pursuant to the terms of the Agreement and shall become effective pursuant to such terms.

SECTION 4. SUPPORT ENERGY

4.01 Monthly Support Energy is equal to Monthly WAPA Energy, as defined in Section 4.02, minus Monthly WAPA Energy Allocation, as defined in Section 2.02.

4.02 Monthly WAPA Energy is equal to the following:

a. If City has an allocation from the WAPA UGP, the Monthly WAPA Energy shall beequal to the firm energy allocation supplied by WAPA for that month.

b. If City has an allocation of energy from the WAPA LAP, the City’s Monthly WAPAEnergy shall be equal to the Monthly WAPA LAP Energy, which is equal to the TotalMetered Energy less Contracted Wind, multiplied by the ratio of the firm WAPALAP demand allocation divided by the City’s non-coincident peak demand in thatmonth.

c. If City has an allocation of energy from the WAPA SLCA, the Monthly WAPA Energyshall be equal to the Monthly WAPA SLCA Energy, which is equal to the firm WAPASLCA demand allocation multiplied by the number of hours in the month.

d. If City has an allocation from both WAPA LAP and WAPA SLCA, the Monthly WAPAEnergy is equal to the sum of the City’s Monthly WAPA LAP Energy and MonthlyWAPA SLCA Energy.

4.03 Support Energy Charge

a. City shall pay MEAN for Support Energy, as defined in Section 4.01, at the SupportEnergy Rate which shall be equal to the then-current MEAN Service Schedule MEnergy Charge per kilowatt-hour.

b. The Support Energy Charge for Support Energy is also subject to Section 3.04,Pooled Energy Adjustment (PEA) of this Schedule of Rates and Charges.





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SECTION 5. CAPACITY COMMITMENT COMPENSATION

5.01 The City shall be reimbursed for the commitment of its accredited generation facilities as follows:

a. Demand Rate for each kilowatt of committed accredited capacity, $1.50 permonth.

b. Energy Rate shall be determined by, and may be modified from time to time by,the MEAN Management CommitteeBoard of Directors. The Energy Rate iscurrently set forth in the Electrical Resources Pooling Agreement Policies andProcedures.

SECTION 6. TRANSMISSION AND SUBTRANSMISSION CHARGES

6.01 Transmission service charges, including applicable ancillary service charges other than operating reserves, for delivery of demand and Billing Energy under the Agreement and Section 2 of this Revised Section III, plus any other contracted transmission service for delivery of City's WAPA power, shall be billed at the transmission service provider's then-current transmission rates.

6.02 In the event that delivery voltages lower than 115 KV or additional transformation or sub-transmission facilities are required to make deliveries to the City, the City shall be required to pay such additional amounts equal to those incurred by MEAN to make such deliveries at that voltage.

6.03 City shall reimburse MEAN for any other expenses incurred by MEAN in accordance with specific agreements between the City and MEAN.

SECTION 7. INTEREST ON LATE PAYMENTS

7.01 Unpaid balances on billings shall accrue interest from the due date until paid at the rate of 12% per annum.

April May June July August September October November December January February March Total

Schedule K

Glenwood Springs, CO 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,672.00$ 276,668.00$ 3,320,060.00$

Paxton 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,976.00 14,979.00 179,715.00

Total Schedule K 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,648.00$ 291,647.00$ 3,499,775.00$

Schedule K Revised Section III

Schedule K-1 Revised Section III

Attachment 1

Municipal Energy Agency of Nebraska

Fixed Cost Recovery Charge

Effective April 1, 2019

Revision No. 5.04.0

Effective Date ______May 23, 2019

Electrical Resources Pooling Agreement

Policies & Procedures Distribution Restriction: Public Document

Table of Contents

Introduction .................................................................................................................................. 2

I. Member Generation Not Leased to MEAN ....................................................................... 2

II. Reliability Standards for Bulk Power Supply of MEAN ..................................................... 4

III. Integrated Resource Plan Development ........................................................................... 5

IV. Abnormal System Conditions and Restoring Service ........................................................ 6

V. Procedures for the Use of Service Schedules ................................................................... 8

VI. Unit Capability Testing Procedures ................................................................................... 8

VII. Operation of Generation ................................................................................................ 13

VIII. Exercising of Unit(s) and Scheduling Obligations ........................................................... 18

IX. Recordkeeping and Reporting ........................................................................................ 21

X. Plant Staffing Obligations................................................................................................ 22

XI. Metering ......................................................................................................................... 24

XII. New or Additional Generation ........................................................................................ 26

XIII. Substitution of Leased Generation Facilities .................................................................. 31

XIV. Discontinuance of Commitment of Capacity to MEAN .................................................. 32

XV. Additional Criteria for Capacity Compensation Eligibility……………………………..……..……..35

XVI. Renewable Distributed Generation Policy………………………………… .......................... ………36

Meeting Attachment C

Revision No. 5.04.0

Effective Date _____May 23, 2019



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The Municipal Energy Agency of Nebraska (MEAN) Management Committee has set forth written documentation of the policies and procedures pursuant to the Electrical Resources Pooling Agreement (ERPA). This document incorporates the established policies and procedures that MEAN has been following over the years as well as new policies and procedures approved by the Management Committee or the MEAN Board of Directors from time to time. Effective _________________, 2019, the Management Committee delegated its duties to the MEAN Board of Directors. Accordingly, references in this document to matters to be determined by, or actions to be taken by, the Management Committee have been updated to refer to the MEAN Board of Directors. In the performance of services under these policies and procedures, staff which provides services to and on behalf of MEAN (MEAN Staff) are officially employed by the Nebraska Municipal Power Pool (NMPP) and are utilized by MEAN through a joint operating committee agreement.

I. MEMBER GENERATION NOT LEASED TO MEAN (Approved by Management Committeeon 5/26/05; modified on 8/15/13, 5/21/15, 5/18/17, 8/16/18, and 5/23/19 and ______)

Article V, Section 5.01 of the ERPA states that Bulk Power Participants will contractuallycommit to MEAN the energy output of all existing generation facilities that are ownedby the Participants for the purpose of economic dispatching by MEAN electric powerand energy from such generating facilities for the common benefit of all Participants.

Pursuant to Section 4 of the Service Schedule M Schedule of Rates and Charges,generating plants will be reimbursed for the commitment of accredited generationfacilities; Such plants committed to MEAN will be paid for capacity at the rateestablished in the Service Schedule M Schedule of Rates and Charges as modified fromtime to time by the MEAN Board of Directors and will be paid for energy generation asdescribed in these ERPA policies and procedures.

A. On January 20, 2005, the Management Committee and Board of Directors placeda moratorium on leasing any new or additional generation until such timepeaking capacity generation is needed.

B. Service Schedule M, K, K-1 and J Participants that have local generation notleased to MEAN are permitted to generate in accordance to the followingpolicies and procedures:

1. Operation of unit(s)

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a. The non-leasing Participant will notify The Energy Authority (TEA)Real Time Operator 48 hours prior to the time that it plans tooperate its unit(s) for any reason.

1) The only exception is for distribution system-wide outageor blackout caused by the transmission interconnection ordistribution system or weather, in which case the non-leasing Participant shall notify TEA Real Time Operatorimmediately.

b. The TEA Real Time Operator will approve or deny the non-leasingParticipant’s request to operate its unit(s).

1) If approved, the TEA Real Time Operator will confirm thedate, time, unit(s), and desired output per hour to beoperated.

c. In addition to the 48 hour notice required as described above, atleast 90 minutes prior to operating the unit, the non-leasingParticipant will verify the anticipated kW output per hour andstart/end times with the TEA Real Time Operator.

d. If for any reason the amount of output is modified before orduring operation, the non-leasing Participant must notify the TEAReal Time Operator immediately.

e. Prior to discontinuing generation, Participant will contact the TEAReal Time Operator to confirm that system conditions do notwarrant adjusting the timeframe for bringing the unit(s) offline.

2. Compensation

a. The non-leasing Participant will be compensated for energyproduction as set forth in Article VII, Section M below. The ratevaries depending on whether energy production is at the requestof MEAN or a third party, or is for any other reason. Thecompensation provided for herein is subject to the generationmeeting all other applicable requirements set forth in these ERPA

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policies and procedures or established from time to time by the MEAN Board of Directors or Management Committee.

b. MEAN will add back to the non-leasing Participant’s total loadcalculation the hourly energy production provided duringgeneration to ensure proper billing of monthly peak demand andenergy. To the extent required by applicable Tariff(s), MEAN alsowill add back to the Participant’s total load calculation the hourlyenergy production provided during generation to ensure properbilling of network transmission.

c. In the event the non-leasing Participant does not timely andproperly notify the TEA Real Time Operator of its intent tooperate, as outlined in #1 above, even during emergencies, thenon-leasing Participant will not be compensated for energyproduction or fuel. In such event, Participant will be responsiblefor all resulting charges and penalties assessed by a third party,including without limitation a transmission provider, RegionalTransmission Organization (RTO) or Independent TransmissionSystem Operator (ISO), arising out of the failure to timely andproperly notify TEA.

3. All provisions of these ERPA Policies & Procedures shall apply to non-leasing Participant except for the following Articles which are applicableonly to leased generation: VI, VII (except that the summary tableprovisions regarding non-leased generation shall apply), VIII, X, XIII, XIV,XV.

II. RELIABILITY STANDARDS FOR MEAN BULK POWER SUPPLY (Approved by ManagementCommittee on 5/26/05; modified on 8/15/13, 5/21/15, 11/17/16, 8/16/18 and 5/23/19)

Article VI, Section 6.07 (e) of the ERPA requires the Management Committee toestablish reliability standards for bulk power supply of MEAN.

A. The following are established as the reliability standards for bulk power supply ofMEAN: MEAN is currently registered with North American Electric ReliabilityCorporation (NERC) in the Midwest Reliability Organization (MRO) and theWestern Electricity Coordinating Council (WECC) regions as a Resource Planner(RP). MEAN must comply with or demonstrate non-applicability with all Federal

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Energy Regulatory Commission (FERC) approved reliability standards that are applicable to this function. MEAN’s NERC responsibilities do not extend beyond the requirements of the RP function.

B. To demonstrate compliance with, or non-applicability with, all FERC-approvedreliability standards in MEAN’s RP function, MEAN Staff will prepare planningand operating studies or other reports, as appropriate.

III. INTEGRATED RESOURCE PLAN DEVELOPMENT (Approved by Management Committee on5/26/05; modified on 5/21/15, 8/16/18, and 5/23/19 and _____)

Article VI, Section 6.07 (g) of the ERPA requires the development of long range powersupply plans to be updated annually for the ensuing 10 year period or longer.

A. MEAN Staff will develop an Integrated Resource Plan (IRP) on behalf of MEANand its Service Schedule M, K, K-1 and J Participants every five years as well asannual updates to the IRP as required by the Western Area PowerAdministration (WAPA) and others.

B. The IRP will comply with the provisions of the WAPA Energy Planning andManagement Program, which requires the following elements:

1. Identify and compare all practicable energy efficiency and energy supplyresource options.

2. Include action plan with timing set by customer.

3. Describe efforts to minimize adverse environmental effects of newresource acquisitions.

4. Provide ample opportunity for full public participation.

5. Conduct load forecasting.

6. Include brief description of measurement strategies for options identifiedin the IRP to determine whether objectives are being met.

C. MEAN will submit progress reports to WAPA on an annual basis.

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D. In the event WAPA changes its Energy Planning and Management Program in amanner which affects the IRP obligation, content, or filing requirements forMEAN or its participants, this procedure will be amended to include suchchanges and submitted to the Management Committee MEAN Board ofDirectors for approval.

E. If the situation warrants, MEAN will update elements of the IRP more often thanevery five years, including load forecasts, resource plans, and demand sidemanagement alternatives. The results will be reviewed with the ManagementCommittee andMEAN Board of Directors as necessary.

F. Participant will respond to MEAN Staff data requests in a timely manner.

G. Participant will implement measures selected in the development of a least costplan as specified by the plan.

IV. ABNORMAL SYSTEM CONDITIONS AND RESTORING SERVICE (Approved by ManagementCommittee on 8/19/04; modified on 5/20/10, 5/18/17 and 5/23/19)

Pursuant to Article VI, Section 6.07 (j) and 6.07 (q), of the ERPA, the duties of theManagement Committee include establishing and revising rules relating to the effect ofabnormal conditions on system operations and reviewing the procedures for restoringservice following emergency conditions.

A. In periods where a Participant has abnormal conditions on its system, theParticipant will notify the TEA Real Time Operator immediately in order tocoordinate any assistance needed by the Participant. The Participant willattempt to isolate the abnormal condition to its own system so the effects onsurrounding utilities are minimized.

B. In the event of loss of power from the grid due to any reason (blackout,brownout, storm damage, weather problems, transmission system overload,etc.), the Participant will separate from the grid and begin to self-generate tostabilize their distribution system.

1. Participant will contact the TEA Real Time Operator immediately toreport the conditions and provide all appropriate generation output data.

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C. In periods where MEAN has an abnormal condition in its operation of powersupply, the TEA Real Time Operator may ask Participants to generate to levelsrequested or take other steps necessary to relieve the condition, such asimplement load management programs and/or load curtailments.

D. Every effort will be made by all Participants and the TEA Real Time Operator tomaximize effective communication during abnormal periods.

E. The TEA Real Time Operator and Participant will coordinate taking generation offline.

F. In cases of a widespread grid event (i.e., blackout), the TEA Real Time Operatormay direct Participants to isolate from the grid and generate to their distributionload or ‘self-generate’.

1. If called upon by the TEA Real Time Operator, Participants will self-generate in conjunction with regional power system restoration efforts.

2. Participants will continue to self-generate (even if the surroundingdistribution systems have power restored) for as long as directed by theTEA Real Time Operator.

3. The TEA Real Time Operator will work with Participants on when toreconnect to the grid.

G. In periods where planned transmission and distribution work is scheduled eitherby a Participant, or a third party where the Participant has knowledge of thework where there will be an impact on load and/or the equipment used byMEAN to collect data, the Participant will notify MEAN as soon as possible, andwill indicate the planned duration of the outage, the equipment impacted andthe basic scope of work. Examples include but are not limited to the following:

1. Planned changes, additions, or removals of a delivery point.

2. Substation work. Including repair or replacement of transformer, currenttransducer (CT), potential/voltage transducer (PT/VT).

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3. Any meter testing, repair or replacement. This includes when meteragents let the Participant know they will be performing meter testing ontheir equipment.

V. PROCEDURES FOR THE USE OF SERVICE SCHEDULES (Approved by the ManagementCommittee on 5/26/05; modified on 8/16/18, and 5/23/19 and _____)

Article VI, Section 6.07 (m) of the ERPA requires procedures be established for the useof Service Schedules.

A. Participant must provide a verbal or written request to MEAN to receive serviceunder any Service Schedule.

1. The request must include the Service Schedule under which theParticipant wishes to receive service, the length of time covered by therequest, any special terms and conditions of the service request,transmission arrangements, and any other appropriate information.

2. MEAN will confirm requested service both orally and in writing.

B. Requests for services under any Service Schedule which requires specificManagement Committee approval (Service Schedules A, J, K and M) will beconsidered by the Management CommitteeMEAN Board of Directors.

VI. UNIT CAPABILITY TESTING PROCEDURES (Approved by Management Committee on5/13/04; modified on 5/21/09, 5/20/10, 8/16/12, 5/16/13, 8/15/13, 5/21/15, 5/18/17,8/16/18, and 5/23/19 and _____)

Pursuant to the provisions of Article VIII, Section 8.03 of the ERPA, the ManagementCommittee will establish the rules and regulations for Participants in determiningaccredited capability (referred to herein as “Accredited Capacity”). All tests will be inaccordance with the requirements of the respective Regional TransmissionOrganization, including without limitation the requirements specified in the SouthwestPower Pool (SPP) Criteria 12.0 Electrical Facility Ratings, and the then-current version ofthe Midcontinent Independent System Operator (MISO) Resource Adequacy BusinessPractice Manual BPM-011.

A. Scheduling of Unit Capability tests

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1. All scheduling of Unit Capability tests will be coordinated with the MEANManager of Resources and Transmission or his/her designee.

2. The MEAN Manager of Resources and Transmission or his/her designeewill give Participant no less than 48-hour verbal notice that a UnitCapability test will be conducted.

a. If the Participant refuses or is not ready to conduct the test asscheduled, the Participant will be assessed a penalty equal to onemonth’s capacity compensation payment to the Participant. Thepenalty will automatically be deducted from the next monthlyinvoice.

3. MEAN Staff or TEA reserves the right to postpone or reschedule a test atany time as system conditions warrant with no recourse from theParticipant.

4. Unit Capability tests will be conducted during the months of June, July,August or September. Exceptions must be approved by MEAN.

5. During any Unit Capability test, the net output of the generating unit(s)being tested will be recorded hourly and reported to MEAN Staff by theon-site and authorized MEAN Staff member, or at MEAN Staff’s discretiona Participant designee, in order to allow proper blending of the energyoutput of the unit(s) with other MEAN resources.

B. Persons required to be present during Unit Capability test:

1. In order to be accredited by the Management CommitteeMEAN Board ofDirectors, Unit Capability tests must be attended by at least oneauthorized MEAN Staff member, or at MEAN Staff’s discretion aParticipant designee when the plant has SCADA capabilities or similarlyapproved monitoring instrumentation. This individual will keep a recordof plant output and operation during the test.

2. Any member of the Management Committee MEAN Board of Directorsmay attend any such tests in an advisory capacity.

C. Testing procedures to demonstrate capability

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1. Plant net capacity will be defined as gross plant capacity output lessstation power (auxiliaries). Ratings will be confirmed annually or morefrequently as necessary to demonstrate the net capability. All units willbe tested at least once per year.

2. Units which are dependent upon common systems which can restricttotal output shall be tested simultaneously to demonstrate the netcapability of the entire plant. MEAN Staff will determine on a case bycase basis which units may be tested independently based on plantsystem configuration and equipment condition.

3. All equipment, when tested, will be in good operating condition with allauxiliaries needed for normal operation in service and with provision forenhanced output facilities operating (i.e. added cooling) if this capabilityis to be included in net capability. Energy consumption by auxiliaryfacilities common to the entire plant (e.g. fuel handling or lighting) will bedistributed over the appropriate units in the plants and will represent theconsumption normally experienced during the high load part of the day.

4. A standard auxiliary power deduction will be assessed for Participantsthat do not have auxiliary metering available. The current standarddeduction is 2.5% of gross plant output. Such standard deductionpercentage may be modified from time to time by the MEANManagement CommitteeMEAN Board of Directors.

5. The fuel used during the test shall be individually metered for eachgenerator.

Natural gas fuel integrator readings for the test shall be taken at the startof the test, at the start of the first hour, at the end of the first hour, at theend of the second hour, and at the conclusion of the test.

For liquid fuel units with no day tank, or with fuel meters (inlet andreturn) located downstream of the day tank, the fuel integrator readings(both inlet and return) will be read in the same manner as the natural gasfuel meters.

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For liquid fuel units with day tanks and the fuel meter located upstream of the day tank, the liquid fuel integrator readings shall be taken at the start of the test, and at the conclusion of the test, after the day tank has been refilled to the precise level as prior to testing. Liquid fuel usage will be calculated based on total fuel burned and times recorded by MEAN Staff, or at MEAN Staff’s discretion a Participant designee, that represent unit load levels.

For dual fuel units, the methods of recording fuel usage listed above shall be used in the appropriate combination to reflect fuel used.

Minimum fuel storage volume shall be the fuel that will be available in sufficient quantities to run the unit at its accredited level for the four peak hours for five days in succession at the time of MEAN's annual peak. (Minimum fuel storage volume = Capability Test fuel/hr x 4 hrs. x 5 days.)

6. The test loading shall be maintained at as constant a level as practical.The reported test results shall be the hourly average of the MWh/hrintegrated net output for the 2-hour test period. The test for all units isdeemed successful only if such net output reported is equal to or greaterthan the net capacity in kW in MEAN’s current Load and CapabilityReport. If the test results in a kW output that is less than the current kWamount found in the Load and Capability Report, the latest test result willbe recorded in the next Load and Capability Report, unless the Participantretests the units in compliance with the then current policies andprocedures.

D. Steam turbine-generator unit tests

1. The test period for steam turbine-generator units will be not less thanfour continuous hours.

2. Generating unit net output capability will be corrected using the averageof the past five summers’ maximum inlet circulating water temperatures.Steam conditions will correspond to the operating standard establishedby the owner of the unit or plant. The steam generator will be operatedwith type and quality of fuel allowed by law.

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E. Combustion turbine and reciprocating engine generatordiesel unit tests

1. The test period for combustion turbine and reciprocating enginegeneratordiesel units shall be two continuous hours following sufficientwarm-up and stabilized operating conditions not to exceed 30 minutes.

2. The net dependable unit capacity for combustion turbine units only willbe corrected by applying the 5 year average maximum temperatureoccurring in that community to the original equipment manufacturercompressor inlet temperature vs. unit output performance curve (ifavailable). This correction will be completed by MEAN Staff.

F. Requests for retesting of units

1. Should all or a portion of the Accredited Capacity identified in MEAN’scurrent Load and Capability Report not be available to MEAN during anymonth because of an Outage, such as equipment failure or breakdown,the provisions for retesting of such unit(s) when they become availableagain shall be as provided in Article VII and the tests shall comply withthis Article VI.

G. Costs

If any Capability Test is authorized by the Management Committee MEAN Boardof Directors for the purpose of establishing the capability for accreditation for aBulk Power Participant or a Service Schedule J participant that has entered into atotal requirements purchase agreement with MEAN, that Participant will be fullyreimbursed for FOM, as defined in Article VII, Section M below, during the periodof the test (full load run) as approved by the Management CommitteeMEANBoard of Directors so long as the test is deemed successful by MEAN inaccordance with Article VI, Section C.6.

1. Actual cost of diesel fuel consumed will be the total gallons consumed asindicated in Article VI, Section C multiplied by the average fuel tank priceper gallon, which is calculated in the following manner:

(Current fuel quantity * Current fuel price) + (New fuel quantity * New fuel price) Total fuel quantity

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2. Actual cost of natural gas consumed will be the cubic feet consumed asindicated in Article VI, Section C, multiplied by the cost per cubic feet asindicated by the natural gas bill from the supplier. If the supplier chargesper MMBtu, the appropriate calculation will be used per the supplier’sbill.

H. A summary of the compensation arrangements for Capability Testing is shownbelow in Article VII, Section M.

VII. OPERATION OF GENERATION (Approved by Management Committee on 8/19/04;modified on 5/26/05, 5/20/10, 5/16/13, 8/15/13, 5/21/15, 5/18/17, 8/16/18, and5/23/19 and _____)

Pursuant to Article XIII, Section 13.02 of the ERPA, any Bulk Power Participant, uponrequest by MEAN, will supply MEAN energy up to the full amount of its AvailableAccredited Capacity.

A. The TEA Real Time Operator will contact the Participant by telephone of theneed to generate. The TEA Real Time Operator will specify which unit(s) to run,start time, and amount to generate. The Participant must be available togenerate within one (1) hour of the request.

B. When the TEA Real Time Operator determines generation is no longer required,it will contact the Participant by telephone, fax and/or email of the appropriatetime to stop generating.

C. The TEA Real Time Operator may request Participant to generate reactive volt-amperes (VARs) as system conditions warrant.

D. If Participant cannot bring designated unit(s) up to specified net output, theParticipant will immediately inform the TEA Real Time Operator so othergeneration can be scheduled.

E. Participants that lease generation to MEAN will not plan for maintenanceoutages from June 1 through September 30. Notification of plannedmaintenance outages that occur in the remaining months will be made by theparticipant to MEAN as soon as possible, but at minimum 48 hours prior to theoutage start time. Participant will indicate the planned duration of the outage,which units will be unavailable and the basic scope of work.

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F. Should all or a portion of the Accredited Capacity identified in MEAN’s currentLoad and Capability Report not be available to MEAN during any month becauseof a forced outage, which includes a condition in which the equipment isunavailable due to an unanticipated failure (referred to herein as a “ForcedOutage”), or because of a planned outage scheduled in advance to occurbetween June 1 and September 30 with a pre-determined duration (referred toherein as an “Unapproved Planned Outage”), the capacity compensationpayment will be adjusted and made in an amount that is reflective of theEquivalent Availability Rate for any such month or any subsequent month untilcapacity is restored. Forced Outage and Unapproved Planned Outage arecollectively referred to herein as “Outage”.

Equivalent Availability Rate (%) = Accredited Capacity kW – Outage kW Accredited Capacity kW

Adjusted Capacity Payment = Equivalent Availability Rate % * Capacity Payment

Participant must notify MEAN immediately in the event all or a portion of the Accredited Capacity identified in MEAN’s current Load and Capability Report is not available to MEAN, without regard to whether MEAN is in need of generation from Participant at that time. Failure to notify MEAN within eight (8) hours of the commencement of any outage will result in Participant being responsible for any penalties applicable to MEAN from a third party, including without limitation the market, RTO, ISO, or transmission provider(s), which penalties shall be passed through to Participant, and Participant will have the obligation to repay MEAN for capacity compensation payments made by MEAN during any period of unavailability. If the commencement date of the outage cannot be determined to MEAN’s satisfaction then the commencement date shall be deemed to be the later of the following dates: (i) the date of the last MEAN-documented generation by the affected unit(s), or (ii) the date of the last successful Capability Test of the affected unit(s).

For purposes of clarity:

If an outage that was planned to occur between October 1 and May 31 extends past May 31 it will transition to an Unapproved Planned Outage under this Article VII unless the outage was originally approved by MEAN to include such extended time period.

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An Unapproved Planned Outage that extends past September 30 will continue to be subject to this Article VII as an Unapproved Planned Outage until such time MEAN determines in its sole discretion that the unit has been brought back to service.

G. If the total Accredited Capacity is made available to MEAN within 90 days aftercommencement of any such Outage and the generating unit(s) pass any requiredCapability Test as described in Section I below, retroactive payment will be madeby MEAN to the Participant for the amount of capacity of MEAN’s current Loadand Capability Report, which was unavailable because of the Outage. Thecommencement of the 90-day period referred to in this Article VII shall not bedelayed by failure of Participant to timely notify MEAN of the Outage.

H. If all or a portion of the Accredited Capacity is unavailable to MEAN for a periodof 90 days or longer, MEAN will make no retroactive payment for the unavailablecapacity commitment.

I. Upon notice to MEAN by the Participant that all or a portion of the previouslyunavailable capacity is again available, a plant Capability Test will be conductedin accordance with the plant testing procedures set forth in Article VI unlessMEAN otherwise determines in its sole discretion that the unit has been broughtback to service.

J. To the extent a Participant cannot bring back to service a portion or allAccredited Capacity after an Outage, the Participant can request, in writing, toextend the 90-day period described in Section K below. The request shall bemade to the Executive Director of MEAN. The Executive Director shall have theauthority to grant extensions as outlined below, and may approve retroactivepayment of capacity compensation or may elect to defer such action forconsideration and approval by the Management CommitteeMEAN Board ofDirectors.

1. The petition for extension must be received prior to the expiration of theinitial 90-day period.

2. The petition must include a description of the repairs made to date,repairs remaining, and the expected date the unit will return to service,

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as well as the remaining net generation output still available from the plant.

3. Any extension approved by the Executive Director cannot exceed 15months beyond the initial 90-day period.

4. If an extension is granted, the Participant must provide monthly progressreports to MEAN until such time MEAN determines in its sole discretionthat the unit has been brought back to service.

K. Except as described below in this Section K, regardless whether Participantrequests or receives an extension, any existing Accredited Capacity returned toservice after being unavailable for 90 days or longer (or after the expiration ofthe term of any approved extension of such 90-day period) must reapply to theManagement Committee MEAN Board of Directors for MEAN availableAccredited Capacity for compensation and if approved such amount shall beincorporated in the Load and Capability Report. The Executive Director may fromtime to time grant exceptions to this requirement that Participant reapply forcompensation.

L. Compensation

1. MEAN will compensate Participant for production as set forth in ArticleVII, Section M below. The rate varies depending on whether theproduction is at the request of MEAN or a third party and approved byMEAN in advance.

2. MEAN will add back to the Participant's total load calculation the hourlyenergy production provided during generation to ensure proper billing ofmonthly peak demand and energy. To the extent required by applicableTariff(s), MEAN also will add back to the Participant’s total loadcalculation the hourly energy production provided during generation toensure proper billing of network transmission.

M. A summary of the compensation arrangements is shown below. Payments arecontingent on generation meeting all other applicable requirements set forth inthese ERPA policies and procedures or established from time to time by theMEAN Board of Directors or Management Committee.

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Reason for Generation: Leased Generation: Non-Leased Generation:

Capability test – successfully completed FOM N/A

MEAN Request FOM FOM

Quarterly exercise per MEAN schedule – RICE units – successfully completed FOM N/A

Every other month exercise per MEAN schedule – CT units – successfully completed FOM N/A

Emergency outage FOM Energy Charge

Request from third party – (example: rural)

Rate from 3rd party OR Energy Charge if not reimbursed by 3rd party

Rate from 3rd party OR Energy Charge if not reimbursed by 3rd party

All other generation Energy Charge Energy Charge

For purposes of the chart above:

“FOM” shall mean the actual cost of fuel consumed, plus variable operation and maintenance (O&M) cost as approved by the Management CommitteeMEAN Board of Directors. The variable O&M cost shall be $0.005 per kWh, which amount may be modified from time to time by the Management Committeethe MEAN Board of Directors.

“Energy Charge” shall mean the then-current Energy Charge applicable to MEAN Energy pursuant to the Service Schedule M Schedule of Rates and Charges or any new rate as may be approved by the Management Committee and MEAN Board of Directors. Generation compensation to Participants under the “Energy Charge” method will be via a credit on the Statement of Power and Energy Delivery from MEAN to the Participant.

N. Point of Delivery. To the extent the energy generated by behind the metergeneration interconnected with a Participant’s distribution system and leased toor purchased by MEAN is used by MEAN to serve such Participant, the energy

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may be delivered at the generator’s point of interconnection with the Participant or alternate point at which MEAN acquires the energy as agreed in writing between MEAN and the Participant or Participant’s customer.

VIII. EXERCISING OF UNIT(S) AND SCHEDULING OBLIGATIONS (Approved by ManagementCommittee on 8/19/04; modified on 5/20/10, 5/16/13, 8/15/13, 5/21/15, 5/18/17, 8/16/18,and 5/23/19 and _____)

Article XIII, Sections 13.04 and 13.05 of the ERPA state Participants will maintain all leased to MEAN generating units, switches, buildings and auxiliaries (power plant facilities) in good operating condition. Participants will operate power plant facilities so not to cause any type of impairment to the electric service of other Participant(s) or the electric system that is interconnected to their power plant, and will be required to periodically operate to prove the capability of such unit(s).

A. Exercising of unit(s)

1. Participants who lease generation to MEAN will exercise their generatingunits on a quarterly basis for reciprocating internal combustion engines(RICE) and every other month for combustion turbines (CT) per a pre-determined schedule as set by MEAN. Testing will include:

• Starting the unit, tying on line and operating for the pre-determined duration.

• The fuel used during the test will be the fuel that will beavailable in sufficient quantities to run the unit at itsaccredited level for the four peak hours for five days insuccession at the time of MEAN’s annual peak.(Minimum fuel storage volume = Capability Test fuel/hr x4 hrs. x 5 days.)

2. Schedule to be set by MEAN Staff. An annual schedule for exercising willbe created by MEAN Staff by October 1 of the previous year. The TEAReal Time Operator may need to revise the exercise schedule due tosystem conditions.

a. The Monday prior to the week of the scheduled unit exercise,MEAN Staff will provide the generator operators of the unitsscheduled to exercise, an email indicating which units, generation

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levels, and duration of operation is anticipated. The generator operator will confirm that information and make any changes as well as provide the preferred unit start time no later than noon Central time the following Friday by responding via email to [email protected].

b. MEAN Staff will send a follow up email with the confirmedinformation to the generator operator and TEA the Fridayafternoon prior to the week that the unit(s) are scheduled toexercise.

c. The generator operator will contact the TEA Real Time Operatorto verify at least 90 minutes prior to generating the plannedoperating times and output.

d. The generator operator will notify TEA when the unit(s) are onlineand stable.

e. The generator operator will notify TEA immediately if for anyreason the amount of output is modified during operation or ifany unit(s) need to shut down prior to the scheduled time.

f. Prior to discontinuing generation, the generator operator willcontact TEA to confirm that system conditions do not warrantadjusting the timeframe for bringing the unit(s) offline.

g. The generator operator will provide MEAN Staff a completedgeneration log within 24 hours of unit operation. It will beemailed to [email protected].

3. Participant may request to exercise from time to time other than the pre-determined scheduled exercises.

a. Generator operator will call the TEA Real Time Operator at least48 hours in advance of planned unit operation.

b. The generator operator will verify with TEA at least 90 minutesprior to generating the planned operating times and output.

mailto:[email protected]


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c. The generator operator will notify TEA when the unit(s) are onlineand stable.

d. The generator operator will notify TEA immediately if for anyreason the amount of output is modified during operation or anyunit(s) need to shut down prior to the scheduled time.

e. Prior to discontinuing generation, the generator operator willcontact TEA to confirm that system conditions do not warrantadjusting the timeframe for bringing the unit(s) offline.

f. The generator operator will provide MEAN Staff a completedgeneration log within 24 hours of unit operation. It will beemailed to [email protected].

4. Compensation

a. Compensation for unit exercises will be as set forth in Article VII,Section M above. The rate varies depending on whether theexercise follows the pre-determined schedule (quarterly for RICEunits, and every other month for CT units) or is considered to beother generation because it is in excess of the pre-determinedschedule.

b. MEAN will add back to the Participant’s total load calculation thehourly energy production provided during generation to ensureproper billing of monthly peak demand and energy. To the extentrequired by applicable Tariff(s), MEAN also will add back to theParticipant’s total load calculation the hourly energy productionprovided during generation to ensure proper billing of networktransmission.

5. Payments are contingent on generation meeting all other applicablerequirements set forth in these ERPA policies and procedures orestablished from time to time by the MEAN Board of Directors orManagement Committee.


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B. Process for compensation for charges and penalties incurred

Participant will be responsible for any charges and penalties incurred by MEANas a result of, or arising from, Participant’s failure to comply with subsection 1, 2,3, 4, and 5 of Section A. of this Article VIII. Such charges and penalties will bepassed through to Participant.

IX. RECORDKEEPING AND REPORTING (Approved by Management Committee on 8/19/04;modified on 5/20/10, 5/21/15, 5/18/17, 8/16/18 and 5/23/19)

Pursuant to Article XIII, Section 13.06 of the ERPA, Participants are required to prepare and submit reports concerning schedules, loads and generating facilities capabilities, as may be reasonably requested by MEAN.

A. The Participant must maintain hourly log sheets for all emission unit operationand generation activity.

1. MEAN will supply each Participant specific log sheets for their generatingunit(s).

2. The Participant will record hourly kWh generated, per unit, hourly stationservice (auxiliary), and the total quantity of fuel used for the operation ofthe unit. A log sheet must be submitted any time fuel is consumed, evenif no energy was generated.

3. The Participant will email the completed log sheet to [email protected] each day when applicable.

a. If necessary, the Participant may call MEAN and orally relay theinformation.

b. Oral communication will be followed up with a completed logsheet mailed or emailed to MEAN within 48 hours of generating.

B. All generation reports should be kept neatly and open for inspection by eitherparty. Records of all transactions will be kept at MEAN including informationbeing supplied by Participant. In some cases, this information is also required forair emissions permits for regulatory compliance.


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C. In order to receive compensation, Participant will submit a report to MEANwithin thirty (30) days of the end of the month in which generation occurred.The monthly data report will serve as the invoice to MEAN and must beaccompanied by copies of diesel and/or natural gas invoices from Participant’ssupplier. Failure to submit such monthly data within thirty (30) days of the endof the month will result in suspension of capacity compensation payments fromMEAN.

X. PLANT STAFFING OBLIGATIONS (Approved by Management Committee on 5/13/04;modified on 5/20/10, 8/16/18, and 5/23/19 and _____)

Pursuant to Article XIII, Section 13.07, of the ERPA, Participant is required to maintain continuously available and manned one primary telephone number and one or more back-up telephone number(s) for contact by MEAN and response by Participant to a request for any of the services provided by the Agreement.

A. Contact list

MEAN and the TEA Real Time Operator will maintain a contact list of the primaryand secondary contacts, including pertinent telephone numbers, for eachParticipant that leases generation output to MEAN and all back-up numbersmade available by the Participant. The contact list will be updated on a regularbasis.

B. Penalties for inability to generate due to lack of staff

1. The following will apply to any Participant unable or unwilling to beginoperation of requested generation within the one (1) hour requirementdue to limited staff and/or other municipal commitments:

a. First offense – Letter to the Participant’s governing body outliningthe contractual obligations the community has with MEAN andclarification of the ramifications of future failures.

b. Second offense (within the same 12-month period of the firstoffense) – Letter to the Participant’s governing body plus a $500assessment that will be automatically deducted from theParticipant’s monthly capacity compensation payment.

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c. Third offense (within the same 12-month period of the firstoffense) – Letter to the Participant’s governing body plus anassessment of 25% of one month’s capacity compensation or$500, whichever amount is higher, that will be automaticallydeducted from the Participant’s monthly capacity compensationpayment.

d. Any further offenses (within the same 12-month period of thefirst offense) – MEAN will cease payment of the Participant’smonthly capacity compensation until such time the ManagementCommittee MEAN Board of Directors meets to review anddetermine the appropriate action. MEAN will make no retroactivepayment for the unavailable capacity commitment.

2. No assessment will be incurred if a Participant provides documentationacceptable to MEAN that the generating unit failed due to mechanicalfailure beyond the control of the Participant and that such failure thatwas not a result of negligence, poor maintenance or poor operatingpractice.

C. Appeal process

1. In the event a Participant desires to appeal the imposed assessment asoutlined in Section B. 1. above, the Participant will give notice, in writing,to MEAN within 60 days from the date of the imposed assessment. Thenotice must state the specific grounds on why the Participant is disputingthe assessment.

2. Any such appeal received by MEAN will be presented to the ManagementCommittee MEAN Board of Directors at their next regularly scheduledmeeting.

a. Prior to the meeting, a copy of the written notice will bedistributed to the Management Committee MEAN Board ofDirectors along with a written response from MEAN as to why theassessment was incurred.

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3. Any action taken by the Management Committee MEAN Board ofDirectors will be final and binding.

XI. METERING (Approved by Management Committee on 5/26/05; modified on 5/20/10,1/22/15, 5/18/17, 8/16/18, and 5/23/19 and _____)

Article XIV, Section 14.01 of the ERPA states that all Participants provide and maintain metering equipment on their fuel and electric systems.

A. Tie-line metering

1. All tie-line points must have revenue quality metering equipment,accurate to +/- 1.0% in accordance with ERPA requirements.

2. MEAN is responsible for ensuring that all Service Schedule M, K, K-1 and JParticipants have revenue quality metering installed at the tie-line. Allother Participants are responsible for ensuring revenue quality meteringto ensure accurate energy delivery and billing.

3. MEAN is responsible for installing a data recorder to collect and recordmetering data at the tie-line for Service Schedule M, K, K-1 and JParticipants. All other Participants are responsible for the cost of MEANinstalling a compatible data recorder to ensure accurate delivery andbilling.

a. If the metering equipment is owned by a third party, usually thetransmission provider, MEAN is responsible for installing a datarecorder.

B. Generation metering

1. All generation must have revenue quality electric equipment, accurate to+/- 1.0% in accordance with ERPA requirements. For clarity, revenuequality electric metering can include electro-mechanical meters, SCADAinformation, generator data pack meters, “smart” relay output, and anyother means provided the readings are accurate to +/- 1.0%. Thisaccuracy shall be the overall accuracy including any error introduced bythe potential and current transformers.

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All generation must have fuel metering equipment, accurate to at minimum +/- 4.0% in accordance with ERPA requirements. Fuel meters must be rated for the type of fuel being measured (i.e., diesel fuel, natural gas).

2. It is the Participant’s responsibility to install revenue quality meteringequipment that can measure the gross and net output of the unit(s) onan hourly interval. If auxiliary electric metering is not available, the then-current standard auxiliary power of gross plant output will be assessed.(See Section VI.C.4, Unit Capability Testing Procedures for additionalinformation.)

3. The Participant is responsible for all metering relaying equipment,current and potential transformers, as well as any and all otherequipment necessary to obtain revenue quality electric meteringreadings, and precise fuel usage readings at the accuracy level indicatedin Section XI.B.1, Generation Metering. This includes verifying calibrationof all meters at a frequency appropriate to ensure the specified accuracy.

C. Penalties for not having appropriate metering equipment installed

1. The following penalties may apply to Service Schedule M, K, K-1 and JParticipants that do not have revenue quality metering equipmentinstalled on all generation or fail to maintain such metering equipment:

a. First violation – Letter to the Participant’s governing bodyoutlining the contractual obligations the community has withMEAN and clarification of the ramifications of future violations.

b. Second violation (if not corrected within 30 days of the firstwritten request) – Letter to the Participant’s governing body plusa $500 assessment that will be automatically deducted from theParticipant’s monthly capacity compensation payment.

c. Third violation (if not corrected within 60 days of the first writtenrequest) – Letter to the Participant’s governing body plus anassessment of 25% of one month’s capacity compensation or$500, whichever amount is higher, that will be automatically

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deducted from the Participant’s monthly capacity compensation payment.

d. Any further violations (if not corrected within 90 days) – MEANwill cease payment of the Participant’s monthly capacitycompensation until such time the Management Committee MEANBoard of Directors meets to review and determine theappropriate action. MEAN will make no retroactive payment forthe unavailable metering capabilities.

2. Appeal process

a. In the event a Participant desires to appeal the imposedassessment as outlined in Section C. 1. above, the Participant willgive notice, in writing, to MEAN within 60 days from the date ofthe imposed assessment. The notice must state the specificgrounds on why the Participant is disputing the assessment.

b. Any such appeal received by MEAN will be presented to theManagement Committee MEAN Board of Directors at their nextregularly scheduled meeting.

c. Prior to the meeting, a copy of the written notice will bedistributed to the Management Committee MEAN Board ofDirectors along with a written response MEAN as to why theassessment was incurred.

d. Any action taken by the Management Committee MEAN Board ofDirectors will be final and binding.

XII. NEW OR ADDITIONAL GENERATION (Approved by Management Committee on11/18/04; modified on 5/20/10, 5/21/15, 5/18/17, 8/16/18, and 5/23/19 and _____)

According to Article XV of the ERPA, any generating units installed by Participants or by MEAN should be the most economical size and type practicable based on size of the system, loads of other Participants, anticipated growth, transmission facilities, and ability to interconnect with other systems. All generating units installed by Participants

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are subject to the established reliability standards of the Management CommitteeMEAN Board of Directors.

A. Any Participant requesting capacity compensation for new or additionalgeneration is required to submit a formal written request to the MEAN Directorof Wholesale Electric Operations. The following technical information must beincluded in the written request:

1. Size of the proposed new or additional generation

2. Requested megawatt capacity compensation

3. Type of generating unit (combustion turbine, reciprocating engine-generator, wind and water powered turbine generators, photovoltaicgenerators/invertors, etc.)

4. Fuel type (single fuel only – natural gas or oil; combined fuel – oil andnatural gas by % of total; secondary fuel option – natural gas or oil only orcombined oil and natural gas by % of total, or wind, hydro, biofuel, etc.)

5. Fuel storage on-site (type of fuel and available storage, in gallons, asapplicable)

6. Fuel transportation arrangements

7. One-line electrical diagram including existing plant, proposed addition,and interconnection

8. Capability Test-determined or manufacturer’s/installers’ estimated heatrate (BTUs of fuel / kWh of generation)

9. Staffing schedule of plant operating employees for the proposedgeneration addition

10. Consulting engineer selected to perform engineering functions necessaryto complete installation and Capability Test of unit

11. Implementation plan for formal approval by any government orregulatory bodies, if applicable

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12. Estimated operating hourly capability for a typical year (annual loadduration curve or equivalent), limits imposed by environmentalregulations and any other unit output limits applicable

13. Other characteristics (warranty of equipment, expected maintenanceschedules and special equipment needs for repair; i.e. lifting cranes, labequipment, black start capability, distribution benefits, retirement ofexisting unit, etc.)

B. Upon receipt of a formal written request, MEAN Staff will evaluate the proposedgeneration facility using the following criteria to determine if it is an economicand operational fit with MEAN’s existing and resource mix:

1. Category:

a. Traditional powered and dispatchable resources, (fossil, existinghydro and nuclear) or

b. Renewable powered restricted dispatchable resources (newhydro, wind, solar, biofuel, etc.)

2. Type of prime mover, such as combustion turbine, combined cycle, aero-derivative, combustion engine, wind or water turbine, etc.

3. Amount of generation (MW) and the annual energy productioncompared to the Participant’s total and supplemental peak demand andenergy needs

4. Fuel type, availability, and fuel cost projections

5. Available capacity factor, maximum hours of operation and capacitylimits listed by time of year

6. MEAN’s projected loads, resource needs, and resource mix specifically forrestricted dispatchable renewable generators:

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a. The proposed and existing restricted dispatchable generationcannot exceed 2.0% of MEAN’s peak load responsibility in therespective control area. For example in Fiscal Year Ending 2016:

Summer MEAN Peak Load Responsibility by Balancing Area in KW Non-coincident Peak

MISO SPP WACM PSCO Total 90,602 160,107 160,894 34,089 445,692

2% 2% 2% 2% 2% 1,812 3,202 3,218 682 8,914

b. The sum of all restricted dispatchable generation shall not exceed10,000 kW of the total of MEAN’s generation resources.

7. Staffing levels of existing and proposed generation at power plant site.

8. Transmission (local and regional) impacts determined by transmissionload flow studies.

9. Summary of the member’s past leased generation performance andcompliance with ERPA requirements.

10. Compliance with interconnection requirements, rules and tariffs of theRTO or ISO.

11. Potential rate impact on MEAN Bulk Power Participants

12. Other factors, as necessary

The Participant and/or the Participant’s consulting engineer will supply MEAN Staff with the required information outlined above and/or any additional information that may be necessary in order to complete the evaluation.

C. Upon receipt of the required information from the Participant, MEAN Staff has60 days to evaluate the proposed new or additional generation request andsubmit a written report back to the Participant. If any deficiencies are notedduring the evaluation process, MEAN Staff may ask the Participant to makemodifications to its request. MEAN’s written report may include, but not belimited to, the following:

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1. General background information

2. Evaluation of request based on the criteria listed in Section B above

3. Conclusions and recommendation to Power Supply Committee and

Management Committeethe MEAN Board of Directors

D. The Participant has 30 days to review and respond to MEAN’s written report. After this 30-day period, MEAN Staff will finalize the report and submit it to the Power Supply Committee for their review and consideration at the next regularly scheduled meeting.

1. The Power Supply Committee will make a recommendation to the

Management Committee and MEAN Board of Directors to approve/deny the request for new or additional generation.

2. Final approval/denial of the request for new or additional generation is

made by the Management CommitteeMEAN Board of Directors. If the request is approved, the Board of Directors determines the level of capacity compensation paid to the Participant. (Capacity compensation is not addressed in this section of the ERPA Policies & Procedures document.)

E. Upon Management Committee and MEAN Board of Directors approval for new

or additional generation

1. MEAN will complete, at the expense of the generation project and to be paid as outlined in the Board’s approval document, the necessary load flow studies for regional reliability accreditation (i.e., MISO, SPP, WECC), request interconnection from the control area provider, request network resource designation from the transmission provider, and request any accreditation necessary from regional, state and/or local regulatory body, if applicable.

2. MEAN is responsible for the costs of all studies required for regional

reliability accreditation. The Participant is responsible for all labor, consulting, and material costs necessary to address and meet or exceed the transmission provider’s requirements for interconnection, protective

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relaying, metering equipment, and any transmission improvement required to designate the proposed generation as a network resource for MEAN.

F. If the proposed new or additional generation is not a traditional reciprocating orcombustion turbine engine peaking facility, MEAN Staff will, in conjunction withthe evaluation process, work with the Participant to develop an appropriatecapacity and energy compensation methodology. The recommendedcompensation will be based on:

1. The avoided cost of resources off-set by new generation

2. The market price of excess capacity and energy from the proposedgeneration net of transmission cost for delivery that MEAN is able toremarket

3. Other criteria that may be deemed appropriate by the Power SupplyCommittee

G. Capacity compensation for the new or additional generation begins only whenthe arrangements listed under Section E above are completed, the unit is placedinto commercial service, and the unit has successfully passed the Capability Test.(NOTE: MEAN representative(s) must conduct the Capability Test.)

XIII. SUBSTITUTION OF LEASED GENERATION FACILITIES (Approved by ManagementCommittee on 11/18/10; modified on 8/16/12, 5/21/15, 5/18/17, 8/16/18 and 5/23/19)

A Participant that desires to commit to MEAN the output of one or more of Participant’sgenerating facilities not then leased to MEAN or replace an existing leased generationunit with a unit of similar type and characteristics of the existing leased generatingfacilities (“Alternate Facilities”), in lieu of output from one or more generating facilitiesthen-currently leased to MEAN, shall be permitted to make such substitution inaccordance with the following policies and procedures:

A. Written notice of such substitution of generating facilities must be provided byParticipant to the MEAN Executive Director at least ninety (90) days prior to thedesired effective date.

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B. The amount of capacity committed to MEAN by Participant and compensated byMEAN to the Participant after such substitution may not exceed the amount ofcapacity committed to MEAN by Participant prior to such substitution.

C. MEAN Staff shall verify the amount of Participant’s Accredited Capacity via aCapability Test that follows the then-current ERPA Policies and Procedures toreflect the substitution of generating facilities leased to MEAN.

D. Alternate Facilities must be of a similar type and characteristics of the existinggenerating facility including, but not limited to startup time and hours ofavailability. Alternate Facilities must also remain in compliance with allGovernmental Standards (as that term is defined in Article XV) and are subject tothe provisions of the then-current ERPA Policies and Procedures and the ERPA asapplicable to generation leased to MEAN.

XIV. DISCONTINUANCE OF COMMITMENT OF CAPACITY TO MEAN (Approved by ManagementCommittee on 11/18/10; modified on 8/16/12, 8/16/18, and 5/23/19 and _____)

A Participant that desires to discontinue commitment to MEAN of any generating facility may be permitted to discontinue such commitment in accordance with the following policies and procedures:

1. The Participant must provide MEAN’s Executive Director with advance writtennotice to discontinue commitment of capacity to MEAN, including the reasonand the proposed scheduled final date of capacity commitment. Such noticeshall be given immediately after the Participant’s governing body reviews theissue and makes its decision, whether the decision results from the Participant’sinability to comply with Governmental Standards (examples include a stateoperating permit renewal or a newly implemented EPA rule) or because theParticipant chooses not to modify its equipment and/or operations to comply, orfor any other reason.

2. Once the written termination notice is received, MEAN’s Executive Director willrefer the matter to the Management CommitteeMEAN Board of Directors unlessthe Executive Director determines the discontinuance of commitment ofcapacity will have minimal or no negative impact on the MEAN Load andCapability Report (“De Minimis”). In the event that the discontinuance ofcommitment of capacity is determined to be De Minimis, MEAN Staff isauthorized to relieve the Participant of its obligation to commit the capacity to

Revision No. 5.04.0




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MEAN. MEAN Staff shall report to the Management CommitteeMEAN Board of Directors any such action to relieve the Participant of its obligation.

3. In the event the impact is not determined to be De Minimis under subsection 2.above, the Management Committee MEAN Board of Directors will considerformally “accepting” notification from the Participant that the Participant’saffected generator(s) will no longer serve as generating units committed topooling as described in the ERPA. Acceptance will be subject to a necessarytransition period, the length of which will be determined by MEAN in its solediscretion, to assure that MEAN and the Participant maintain compliance withthen-current Governmental Standards. This compliance includes, but is notlimited to, MEAN’s regional reliability and capacity reserve requirements,Participant’s operating permits, contractual obligations with suppliers andservice providers, and all other obligations of both MEAN and the Participant.

4. As a general guideline, the necessary transition period will end as of the effectivedate of the next MEAN Load and Capability Report (effective dates are currentlyMay 1 and November 1, each referred to as a “Report Date”); provided,however, that if Participant’s notice of discontinuance is received by MEAN lessthan sixty (60) days prior to such Report Date, the necessary transition periodwill continue through the next successive MEAN Load and Capability Reportperiod.

5. If for any reason insufficient notice is provided to MEAN to allow for thenecessary transition period as described above, Participant will reimburse MEANfor all penalties, charges and costs incurred arising out of the discontinuance ofcommitment of capacity.

6. The Participant will be subject to the then-current ERPA Policies and Proceduresfor approval of new and additional generation (currently Article XII) in the eventthat the Participant desires to reestablish the lease of such capacity or any newcapacity to MEAN after the date upon which the capacity payments and capacitycommitment obligations of Participant end. This provision includes instanceswhere the Participant fails to meet deadlines for compliance with GovernmentalStandards, but corrects the deficiency after the deadline that is given by the dulyauthorized regulatory body.

7. If a Participant desires to lease generation to an entity outside of MEAN, thatParticipant shall coordinate such transaction with MEAN Staff and pay for all

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operational, capital, and incremental costs of transfer and scheduling of such transaction. Each transaction will be evaluated on a case-by-case basis.

8. A sample resolution which may be considered by the Management

CommitteeMEAN Board of Directors is shown below:

NOW, THEREFORE, BE IT RESOLVED BY the MEAN Management Committee MEAN Board of Directors that:

The letter from the City of ________ (“Participant”) dated ________ is hereby accepted as formal notice that the Participant’s generators will no longer serve as generating units committed to pooling as described in the Electrical Resources Pooling Agreement (“ERPA”) of MEAN effective as of ___________________, 20___, which shall be the end of a necessary transition period (“Lease End Date”) to assure that MEAN and the Participant maintain compliance with then-current local, state, regional, and federal policy, rules, laws, standards, and regulations. This compliance includes, but is not limited to, MEAN’s regional reliability and capacity reserve requirements, Participant’s operating permits, contractual obligations with suppliers and service providers, and all other obligations of both MEAN and the Participant. The requirement in ERPA Article XIII, Section 13.05 that the Participant maintain all generating units owned by the Participant in good operating condition is hereby waived for the Participant effective upon the Lease End Date. The Participant’s Accredited Capability, as that term is defined in the ERPA, shall be deemed to be zero for any generating units not leased to MEAN as of the Lease End Date, and the Participant shall then no longer qualify for capacity commitment compensation from MEAN. The Participant generators will then be converted to “Member Generation Not Leased to MEAN” and will adhere to the then-current ERPA Policies and Procedures covered in Article I, “Member Generation Not Leased to MEAN”. If the Participant generator(s) do not meet or exceed the then-current operating permits and state, regional and federal rules governing the generator, the Participant may not use the Participant generator(s) to comply with the “Member Generation Not Leased to MEAN” Policy.

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After all necessary transitions have been completed and capacity payments from MEAN have stopped, the Participant will be subject to the then-current ERPA Policies and Procedures for approval of new and additional generation (currently Article XII) in the event that Participant desires to reestablish commitment of said capacity or any new capacity after the Lease End Date.

XV. ADDITIONAL CRITERIA FOR CAPACITY COMPENSATION ELIGIBILITY (Approved byManagement Committee on 8/16/12; modified on 1/10/13, 8/16/18, and 5/23/19 and_____)

In addition to other eligibility requirements, all Participant capacity committed to MEAN shall comply with the following requirements to remain eligible for capacity compensation:

A. Participant must maintain compliance with all applicable regulatory andgovernmental laws, orders, rules, tariffs, policies, protocols, businesspractices, criteria, standards and regulations (“Governmental Standards”)regarding Participant’s generating units committed to MEAN, including butnot limited to those Governmental Standards adopted at the local, state,regional, or federal level. Participant must promptly inform MEAN inwriting in the event of Participant’s noncompliance with anyGovernmental Standards. Participant shall reimburse MEAN for anypenalties, fines or other expenses incurred by MEAN arising from orrelating to Participant’s noncompliance.

B. The Management Committee MEAN Board of Directors may from time totime establish deadlines by which Participants with capacity committed toMEAN must provide official notification of intent regarding continuedcommitment of capacity to MEAN or by which capacity committed toMEAN must comply with Governmental Standards or standardsestablished by MEAN. Such deadlines may be established to assist MEANin planning for any necessary capacity purchases, or for other purposes.Failure to respond or comply by the deadline may result in loss of eligibilityfor capacity compensation and the determination by MEAN that theParticipant’s unit(s) will no longer serve as generating units committed topooling as described in the ERPA.

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C. The Participant will be subject to the then-current ERPA Policies andProcedures for approval of new and additional generation (currentlyArticle XII) for the affected unit(s) in the event that the Participant: (i)desires to reestablish the lease of such capacity or any new capacity toMEAN after the date upon which the capacity payments and capacitycommitment obligations of Participant end for the affected unit(s), or (ii)provides MEAN with official notice of intent to remove one or moregenerating units from commitment to MEAN due to noncompliance oranticipated noncompliance with Governmental Standards or MEANstandards, or (iii) fails to respond or comply by the deadline established byMEAN for notification or compliance pursuant to Section B above.

XVI. RENEWABLE DISTRIBUTED GENERATION POLICY

[Copy of Renewable Distributed Generation Policy as approved by the MEAN Board of Directors is attached as Attachment 1.]

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Revision History

Version Effective Date Description of Revision 1.0 May 13, 1981 Adoption of procedures 1.1 January 14, 1983 Periodic review and update 1.2 August 4, 1983 Periodic review and update 1.3 December 6, 1984 Periodic review and update 1.4 January 10, 1985 Periodic review and update 1.5 March 7, 1985 Periodic review and update 1.6 April 10, 1985 Periodic review and update 1.7 August 8, 1985 Periodic review and update 1.8 September 27, 1985 Periodic review and update 1.9 October 24, 1985 Periodic review and update 1.10 December 5, 1985 Periodic review and update 1.11 January 23, 1986 Periodic review and update 1.12 September 19, 1996 Periodic review and update 2.0 May 13, 2004 Periodic review and update 2.1 August 19, 2004 Periodic review and update 2.2 November 18, 2004 Periodic review and update 2.3 May 26, 2005 Periodic review and update 2.4 May 20, 2010 Periodic review and update 2.5 November 18, 2010 Periodic review and update 2.6 August 16, 2012 Periodic review and update 2.7 January 10, 2013 Periodic review and update

2.8 May 16, 2013 Periodic review and update

2.9 August 15, 2013 Periodic review and update 2.10 January 22, 2015 Periodic review and update 2.11 May 21, 2015 Periodic review and update 2.12 May 19, 2016 Addition of Distributed and Renewable Generation Policy

2.12.1 November 17, 2016 Period review and update; Addition of Grandfathered Facilities List to Distributed and Renewable Generation Policy

2.12.2 January 19, 2017 Modifications to Distributed and Renewable Generation Policy including renaming as Renewable Distributed Generation Policy

2.13 May 18, 2017 Periodic review and update 2.14 August 17, 2017 Update to Renewable Distributed Generation Policy 2.15 November 16, 2017 Update to Renewable Distributed Generation Policy

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3.0 August 16, 2018 Periodic review and update

4.0 May 23, 2019 Modifications to provisions regarding unit operations and unit capability testing; Addition of Point of Delivery provisions; Clarification of applicable Energy Charge rate for compensation; Housekeeping changes

5.0 ___________, 2019 Modifications to reflect delegation of duties of the Management Committee to the MEAN Board of Directors effective ______________, 2019; Housekeeping changes

8377 Glynoaks Drive • Lincoln, NE 68516 • Phone: (402) 474-4759 • Fax: (402) 474-0473 • NMPPenergy.org

Service MEAN NMPP Notes American Public Power Agency (APPA) and APPA Demonstration of Energy & Efficiency Developments (DEED) Dues

X Service Schedule M (SSM) + Service Schedule K (SSK) Participants)

Commercial Energy Audits X Energy audits for commercial/industrial customers (formerly known as the Energy Management Circuit Rider (EMCR) program).

MEAN Scholarship Program (General and Line Worker training and APPA National Conference)

X SSM + SSK Participants

MEAN LED Commercial Lighting Program

X Cash incentives paid directly to commercial customers to help cover the cost of indoor, existing LED upgrades and replacements. Up to $2,500 per customer per program year. Open to SSM, SSK and Service Schedule (SSJ) Participants.

MEAN Residential Energy Efficiency Programs

X Cash incentives paid directly to customers to help cover the cost of energy efficient upgrades including smart thermostat installation, attic insulation and cooling system tune-ups. Open to SSM, SSK and SSJ Participants.

Education/Learning Management System

X

Metering X MEAN installs data recorder from which to schedule the load and/or generation. Costs of MEAN equipment, maintenance and communication with MEAN’s telemetry will be borne by MEAN.

Economic Development X Staff provides developmental tools and resource information to help MEAN communities create quality living and steady growth in your community.

Integrated Resource Planning (IRP)

X X MEAN completes on behalf of MEAN’s Total Requirements Participants every 5 years; available through NMPP as a separate contract for members of NMPP

NMPP Energy Annual Conference; Periodic Workshops

X X Workshops, retreats and forums covering a variety of topics for member communities and their development. Past workshops topics include load management, smart grid operations, net metering, energy efficiency, economic development, and business retention and expansion.

Meeting Attachment E

8377 Glynoaks Drive • Lincoln, NE 68516 • Phone: (402) 474-4759 • Fax: (402) 474-0473 • NMPPenergy.org

Service MEAN NMPP Notes Cost of Service/Rate Design Studies (COS)

X X MEAN pays ½ of electric COS performed by NMPP for SSM and SSK Participants

Net Metering X X MEAN Provides Customer Owned Generation (COG) Resource Guide to SSM, SSK and SSJ Participants; available as a separate contract for non-MEAN members of NMPP

Lobbying/Legislative Advocacy X X Included with NMPP dues. MEAN also contracts with outside lobbyists. Outside lobbyists and staff continually monitor issues and advocate on behalf of the membership, keeping the value of local control at the heart of its philosophy.

Meter Verification Audit Service X Provides utilities useful information about large account electric meters. Newsletter Service X Training Groups X Safety and distribution system related workshops Mutual Aid X Included with dues Regulatory Assistance X EIA/NDEQ Reporting Services Essent Subscription X All NMPP members receive complimentary copies of the monthly Essent newsletter that

covers news and pertinent information to the membership of NMPP. Energy Research & Development Fund (ERDF)

X Voluntary program available to all NMPP Members – per capita contribution annually

Infrared Audit X Identifies abnormal heat in electrical and mechanical systems, helps predict equipment trouble and revenue loss. Price based on population - $750-$2,100

Annual Rate Survey X Distributed to all NMPP members annually Electric Distribution Services (EDS) X Includes drive thru general evaluation of system and report; infrared camera inspection;

metering verification audit; general consulting within contract hours. Pricing based on annual KWH sales.

Computer Services Computer Software Programs X NMPP Computer Software Value Support Plan

X X MEAN pays support portion for NMPP VSP for SSM and SSK Participants

Computer Support X As needed support Utility Billing Supplies X Training/Refresher Courses X 1 free training for each VSP participant, $75 for each additional registrant.

*Services, pricing and availability reviewed regularly by staff for Board of Directors approval.

Board of Directors and Management Municipal Energy Agency of Nebraska Lincoln, Nebraska

As part of our audit of the financial statements of Municipal Energy Agency of Nebraska (MEAN) as of and for the year ended March 31, 2019, we wish to communicate the following to you.

AUDIT SCOPE AND RESULTS

Auditor’s Responsibility Under Auditing Standards Generally Accepted in the United States of America and the Standards Applicable to Financial Audits Contained in Government Auditing Standards Issued by the Comptroller General of the United States

An audit performed in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards issued by the Comptroller General of the United States is designed to obtain reasonable, rather than absolute, assurance about the financial statements. In performing auditing procedures, we establish scopes of audit tests in relation to the financial statements taken as a whole. Our engagement does not include a detailed audit of every transaction. Our engagement letter more specifically describes our responsibilities.

These standards require communication of significant matters related to the financial statementaudit that are relevant to the responsibilities of those charged with governance in overseeing the financial reporting process. Such matters are communicated in the remainder of this letter or have previously been communicated during other phases of the audit. The standards do not require the auditor to design procedures for the purpose of identifying other matters to be communicated with those charged with governance.

An audit of the financial statements does not relieve management or those charged with governance of their responsibilities. Our engagement letter more specifically describes your responsibilities.

Meeting Attachment F

2

Qualitative Aspects of Significant Accounting Policies and Practices

Significant Accounting Policies

MEAN’s significant accounting policies are described in Note 1 of the audited financial statements. The following accounting policies and practices are of significant importance to MEAN’s financial statements:

Productive capacity and capital assets, including determination of estimated useful livesand depreciation methods

Accounting for the deferral of certain revenues and costs in accordance withGovernmental Accounting Standards Board (GASB) Codification Section Re10,Regulated Operations

Recognition and deferral of revenues for rate stabilization Recognition of revenues and costs for transactions within regional transmission

organization (RTO) and independent system operator (ISO) energy markets

Alternative Accounting Treatments

We had discussions with management regarding alternative accounting treatments within accounting principles generally accepted in the United States of America for policies and practices for material items, including recognition, measurement and disclosure considerations related to the accounting for specific transactions as well as general accounting policies, as follows:

Proper accounting treatment for the deferral of revenues and costs, in accordance withGovernmental Accounting Standards Board (GASB) Codification Section Re 10

Management Judgments and Accounting Estimates

Accounting estimates are an integral part of financial statement preparation by management, based on its judgments. The following areas involve significant areas of such estimates for which we are prepared to discuss management’s estimation process and our procedures for testing the reasonableness of those estimates:

Estimated useful lives of productive capacity and capital assets, and the relateddepreciation methods

Deferral of certain revenues and costs, including amortization periods Recognition and deferral of revenues relating to the rate stabilization account

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Financial Statement Disclosures

The following areas involve particularly sensitive financial statement disclosures for which we are prepared to discuss the issues involved and related judgments made in formulating those disclosures:

Transactions with coalition members (related parties) Environmental regulations

Audit Adjustments

During the course of any audit, an auditor may propose adjustments to financial statement amounts. Management evaluates our proposals and records those adjustments which, in its judgment, are required to prevent the financial statements from being materially misstated. No adjustments were identified as a result of our audit engagement.

Auditor’s Judgments About the Quality of the Entity’s Accounting Principles

No matters are reportable.

Disagreements with Management


Difficulties Encountered in Performing the Audit


Other Material Communication

Listed below is another material communication between management and us related to the audit:

Management representation letter (attached)

OTHER MATTERS

We offer these comments and suggestions with respect to matters which came to our attention during the course of the audit of the financial statements. Our audit procedures are designed primarily to enable us to form an opinion on the financial statements and, therefore, may not bring to light all weaknesses in policies and procedures that may exist. However, these matters are offered as constructive suggestions for the consideration of management as part of the ongoing process of modifying and improving financial and administrative practices and procedures. We can discuss these matters further at your convenience and may provide implementation assistance for changes or improvements.

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GASB Statement No. 83, Certain Asset Retirement Obligations

GASB Statement No. 83 establishes uniform criteria for governments to recognize and measure certain asset retirement obligations (AROs). An ARO is defined as a legally enforceable liability associated with the retirement of a tangible capital asset. Examples could be costs associated with decommissioning a nuclear power plant, disposal of wind turbines in a wind farm, or retirement and disposal of another capital asset. An ARO is recognized when the liability is incurred, which is manifested by the occurrence of both an external obligating event (such as a legally binding contract or a court judgment) and an internal obligating event (such as placing a tangible capital asset into service). A government also recognizes a deferred outflow of resources when it recognizes an ARO liability. The ARO is measured at the best estimate of the current value of outlays expected to be incurred. Additional note disclosure are also required.

This statement is effective for MEAN’s fiscal year ending March 31, 2020.

GASB Statement No. 84, Fiduciary Activities

GASB Statement No. 84 establishes criteria for identifying fiduciary activities. It presents separate criteria for evaluating component units, pension and other postemployment benefit arrangements, and other fiduciary activities. The focus is on a government controlling the assets of the fiduciary activity and identification of the beneficiaries of those assets. Fiduciary activities are reported in one of four types of funds: pension (and other employee benefit) trust funds, investment trust funds, private-purpose trust funds, or custodial funds. Custodial funds are used to report fiduciary activities that are not held in a trust. The agency fund designation will no longer be used. GASB 84 also provides guidance on fiduciary fund statements and timing of recognition of a liability to beneficiaries.

This statement will be effective for MEAN’s fiscal year ending March 31, 2020.

GASB Statement No. 88, Certain Disclosures Related to Debt, including Direct Borrowings and Direct Placements

GASB Statement No. 88 specifies disclosures that should be made in the financial statements related to debt. It also provides a definition of debt to clarify which types of liabilities should be included in those disclosures. If a government has direct borrowings or direct placements, disclosures related to these should be provided separately from disclosures related to other types of debt.


GASB Statement No. 89, Accounting for Interest Cost Incurred before the End of a Construction Period

GASB Statement No. 89 requires that interest costs incurred before the end of a construction period be recognized as expenses in the period in which the costs are incurred. As a result, the interest cost incurred before the end of a construction period will not be included in the historical cost of a capital asset reported in a business-type activity or enterprise fund

5


*****

This communication is intended solely for the information and use of management, the Board of Directors, and others within the organization and is not intended to be and should not be used by anyone other than these specified parties.

June 14, 2019

8377 Glynoaks Drive • Lincoln, NE 68516 • Phone: (402) 474‐4759 • Fax: (402) 474‐0473 • NMPPenergy.org

June 14, 2019

BKD, LLP

Certified Public Accountants 1248 “O” Street, Suite 1040 Lincoln, Nebraska 68508

We are providing this letter in connection with your audits of our financial statements of Municipal Energy Agency of Nebraska (MEAN) as of and for the years ended March 31, 2019 and 2018. We confirm that we are responsible for the fair presentation of the financial statements in conformity with accounting principles generally accepted in the United States of America. We are also responsible for adopting sound accounting policies, establishing and maintaining effective internal control over financial reporting, operations and compliance, and preventing and detecting fraud.

Certain representations in this letter are described as being limited to matters that are material. Items are considered material, regardless of size, if they involve an omission or misstatement of accounting information that, in light of surrounding circumstances, makes it probable that the judgment of a reasonable person relying on the information would be changed or influenced by the omission or misstatement.

We confirm, to the best of our knowledge and belief, the following:

1. We have fulfilled our responsibilities, as set out in the terms of our engagementletter dated January 14, 2019 for the preparation and fair presentation of thefinancial statements in accordance with accounting principles generally acceptedin the United States of America.

2. We acknowledge our responsibility for the design, implementation andmaintenance of internal control relevant to the preparation and fair presentation offinancial statements that are free from material misstatement, whether due tofraud or error.

3. We acknowledge our responsibility for the design, implementation andmaintenance of internal control to prevent and detect fraud.

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4. We have provided you with:

(a) Access to all information of which we are aware that is relevant to thepreparation and fair presentation of the financial statements such as records,documentation and other matters.

(b) Additional information that you have requested from us for the purpose ofthe audit.

(c) Unrestricted access to persons within the entity from whom you determinedit necessary to obtain audit evidence.

(d) All minutes of meetings of the Board of Directors and Joint OperatingCommittee held through the date of this letter.

(e) All significant contracts and grants.

5. All transactions have been recorded in the accounting records and are reflected inthe financial statements.

6. We have informed you of all current risks of a material amount that are notadequately prevented or detected by entity procedures with respect to:

(a) Misappropriation of assets.

(b) Misrepresented or misstated assets, liabilities or net position.

7. We have no knowledge of any known or suspected:

(a) Fraudulent financial reporting or misappropriation of assets involvingmanagement or employees who have significant roles in internal control.

(b) Fraudulent financial reporting or misappropriation of assets involving othersthat could have a material effect on the financial statements.

8. We have no knowledge of any allegations of fraud or suspected fraud affectingMEAN received in communications from employees, customers, regulators,suppliers or others.

9. We have disclosed to you the identity of the entity’s related parties and all therelated party relationships and transactions of which we are aware. Related partyrelationships and transactions have been appropriately accounted for anddisclosed in accordance with accounting principles generally accepted in theUnited States of America. We understand that the term related party refers to anaffiliate; management, and members of their immediate families, componentunits; and any other party with which the entity may deal if it can significantlyinfluence, or be influenced by, the management or operating policies of the other.

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The term affiliate refers to a party that directly or indirectly controls, or is controlled by, or is under common control with us.

10. Except as reflected in the financial statements, there are no:

(a) Plans or intentions that may materially affect carrying values orclassifications of assets and liabilities.

(b) Material transactions omitted or improperly recorded in the financialstatements.

(c) Material gain/loss contingencies requiring accrual or disclosure, includingthose arising from environmental remediation obligations.

(d) Events occurring subsequent to the balance sheet date through the date ofthis letter requiring adjustment or disclosure in the financial statements.

(e) Agreements to purchase assets previously sold.

(f) Restrictions on cash balances or compensating balance agreements.

(g) Guarantees, whether written or oral, under which MEAN is contingentlyliable.

11. We have disclosed to you all known instances of noncompliance or suspectednoncompliance with laws and regulations whose effects should be consideredwhen preparing financial statements.

12. We are not aware of any pending or threatened litigation or claims whose effectsshould be considered when preparing the financial statements. We have notsought or received attorney’s services related to pending or threatened litigationor claims during or subsequent to the audit period. Also, we are not aware of anylitigation or claims, pending or threatened, for which legal counsel should besought.

13. Adequate provisions and allowances have been accrued for any material lossesfrom:

(a) Uncollectible receivables.

(b) Reducing obsolete or excess inventories to estimated net realizable value.

(c) Sales commitments, including those unable to be fulfilled.

(d) Purchase commitments in excess of normal requirements or aboveprevailing market prices.

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14. Except as disclosed in the financial statements, we have:

(a) Satisfactory title to all recorded assets, and they are not subject to any liens,pledges or other encumbrances.

(b) Complied with all aspects of contractual and grant agreements, for whichnoncompliance would materially affect the financial statements.

15. We have not been designated as a potentially responsible party (PRP or equivalentstatus) by the Environmental Protection Agency (EPA) or other cognizantregulatory agency with authority to enforce environmental laws and regulations.

16. We have notified you of any instances of noncompliance with applicabledisclosure requirements of the SEC Rule 15c2-12 and applicable state laws.

17. With regard to deposit and investment activities:

(a) All deposit and investment transactions have been made in accordance withlegal and contractual requirements.

(b) Disclosures of deposit and investment balances and risks in the financialstatements are consistent with our understanding of the applicable lawsregarding enforceability of any pledges of collateral.

(c) We understand that your audit does not represent an opinion regarding theenforceability of any collateral pledges.

18. With respect to any nonattest services you have provided us during the yearincluding assistance with formatting, printing and binding of the financialstatements:

(a) We have designated a qualified management-level individual to beresponsible and accountable for overseeing the nonattest services.

(b) We have established and monitored the performance of the nonattestservices to ensure that they meet our objectives.

(c) We have made any and all decisions involving management functions withrespect to the nonattest services and accept full responsibility for suchdecisions.

(d) We have evaluated the adequacy of the services performed and any findingsthat resulted.

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19. We acknowledge that we are responsible for compliance with applicable laws,regulations and provisions of contracts and grant agreements.

20. We have identified and disclosed to you all laws, regulations and provisions ofcontracts and grant agreements that have a direct and material effect on thedetermination of amounts in our financial statements or other financial datasignificant to the audit objectives.

21. We have identified and disclosed to you any violations or possible violations oflaws, regulations and provisions of contracts and grant agreements whose effectsshould be considered for recognition and/or disclosure in the financial statementsor for your reporting on noncompliance.

22. We have taken or will take timely and appropriate steps to remedy any fraud,abuse, illegal acts or violations of provisions of contracts or grant agreements thatyou or other auditors report.

23. We have a process to track the status of audit findings and recommendations.

24. We have identified to you any previous financial audits, attestation engagements,performance audits or other studies related to the objectives of your audit and thecorrective actions taken to address any significant findings and recommendationsmade in such audits, attestation engagements or other studies.

25. The financial statements disclose all significant estimates and materialconcentrations known to us. Significant estimates are estimates at the balancesheet date which could change materially within the next year. Concentrationsrefer to volumes of business, revenues, available sources of supply, or markets forwhich events could occur which would significantly disrupt normal financeswithin the next year. Significant assumptions used by us in making accountingestimates, including those measured at fair value, are reasonable.

26. The fair values of financial and nonfinancial assets and liabilities, if any,recognized in the financial statements or disclosed in the notes thereto arereasonable estimates based on the methods and assumptions used. The methodsand significant assumptions used result in measurements of fair value appropriatefor financial statement recognition and disclosure purposes and have been appliedconsistently from period to period, taking into account any changes incircumstances. The significant assumptions appropriately reflect marketparticipant assumptions.

27. The supplementary information required by the Governmental AccountingStandards Board, consisting of management’s discussion and analysis, has beenprepared and is measured and presented in conformity with the applicable GASBpronouncements, and we acknowledge our responsibility for the information. Theinformation contained therein is based on all facts, decisions and conditions

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currently known to us and is measured using the same methods and assumptions as were used in the preparation of the financial statements. We believe the significant assumptions underlying the measurement and/or presentation of the information are reasonable and appropriate. There has been no change from the preceding period in the methods of measurement and presentation.

28. The allocation of salary, related payroll costs, and other administrative andgeneral costs of MEAN that is administered through Nebraska Municipal PowerPool is reasonable based upon service and/or benefit provided to each entity andconsistent with the approved allocation of the Joint Operating Committee.

29. MEAN incurred expenses of approximately $7,720,000 for administrativeservices provided by coalition members during 2019. MEAN billed coalitionmembers approximately $97,000 for the use of the operations and managementfacility, equipment and furniture during 2019. During 2019, MEAN also paidNMPP, on behalf of MEAN’s participants, approximately $158,000 for theportion of the cost of computer software value support plans and cost of servicestudies purchased by qualifying MEAN participants from NMPP.

30. MEAN shares personnel and facilities within its affiliated group, as well as entersinto agreements for certain products and services. Amounts due to/from coalitionmembers related to this activity at March 31, 2019 is as follows:

2019 Due to NMPP $ 805,701 Due from NPGA $ 1,433 Due from ACE $ 1,836

31. We believe MEAN may incur significant costs in the future as a result of theadvanced technological improvements that may be required under proposedenvironmental regulations. Although initial estimates of these costs have beencalculated, the level of regulatory and legal uncertainty related to these facilitiesmakes it impractical to quantify the specific potential financial impacts at thistime.

Tim Sutherland Director of Wholesale Electric Operations

Jamie L. Johnson Director of Finance and Accounting

1

ANNUAL COMPLIANCE REPORT RE: BOND COMPLIANCE AND MANAGEMENT POLICY

To: Board of Directors of MEAN

Pursuant to its responsibilities as set forth in MEAN’s Bond Compliance Policy, as amended (the “Policy”), the Director of Finance and Accounting (the “Compliance Officer”), as designee of the Executive Director of MEAN, has conducted the annual review required by the Policy and has prepared this report to determine whether the Bonds (as defined in the Policy) comply with covenants and other ongoing requirements applicable to each issue of Bonds. The following sets forth a summary demonstrating MEAN’s compliance with such covenants and requirements.

RECORDS

The Legal Department has all of the records required under the Policy.

TAX COMPLIANCE

(a) Arbitrage Rebate Liability. At this time, MEAN does not have any rebateliability to the U.S. Treasury.

(b) Contract Review. The Legal Department has reviewed copies of allcontracts and agreements of MEAN, including any leases, with respect to the use of any property owned by MEAN and acquired, constructed or otherwise financed or refinanced with the proceeds of the Bonds and other records. At this time, each issue of the Bonds complies with the federal tax requirements applicable to such issue, including restrictions on private business use and private loans.

(c) IRS Examinations or Inquiries. The Internal Revenue Service (the “IRS”)has not commenced an examination of any issue of the Bonds. The IRS has not requested a response to a compliance check, questionnaire or other inquiry.

CONTINUING DISCLOSURE

(a) The Compliance Officer has reviewed the agreements of MEAN withrespect to each issue of Bonds to determine whether the Annual Financial Information and Audited Financial Statements were filed in a timely manner.

All such information was filed within the times required by all Undertakings. Filings for the fiscal year ended March 31, 2019 were posted to Electronic Municipal Market Access (EMMA) by Wells Fargo as MEAN’s dissemination agent on July 5, 2019.

Meeting Attachment G

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(b) The Compliance Officer has conducted a review of all Reportable EventDisclosure made this year.

No Reportable Event Disclosure has been required.

OTHER COVENANTS AND REQUIREMENTS

All issues of Bonds are in compliance with all other covenants and other ongoing requirements applicable to each such issue under the related Bond documents.

Based upon the foregoing, the Compliance Officer believes that no further action is necessary at this time.

COMPLIANCE WITH POLICY

All issues of Bonds are in compliance with all requirements of the Policy applicable to each such issue.

Based upon the foregoing, the Compliance Officer believes that no further action is necessary at this time.

TRAINING

The Compliance Officer reviewed the requirements of the Best Practices – Training section of the Policy.

The Compliance Officer and other MEAN staff are in compliance with the requirements of the Best Practices – Training section of the Policy.

The Compliance Officer and other MEAN Personnel involved in disclosure matters participated in annual training regarding the requirements of federal securities laws in calendar year 2018 and 2019. The Compliance Officer worked with Bond Counsel to provide an annual update to the Compliance Officer and MEAN Personnel on November 15, 2018. Bond Counsel also provided training on June 17, 2019.

The Compliance Officer receives and reviews periodic information from Bond Counsel and the Municipal Securities Rulemaking Board.

Annual training on such topics was provided to the Board and other MEAN Personnel involved in disclosure matters on November 15, 2018.

EFFECTIVENESS OF THE POLICY

The Compliance Officer has consulted with other staff, counsel, the financial advisor, and other professionals in order to evaluate the effectiveness of the Policy.

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The Compliance Officer has no recommendations for change in the Policy as of the date of this report.

DELIVERY OF THIS REPORT

This report will be entered into the records of the Board and made available to all members of the Board at the next regular meeting thereof.

Respectfully submitted this 31st day of July, 2019.

COMPLIANCE OFFICER

BY



Date Approved: August 15, 2019 Effective date of this Schedule of Rates and Charges: September 1, 2019

By: _____________________________________ Supersedes Schedule of Rates and Charges dated Effective April 1, 2019

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This Schedule of Rates and Charges supplied to the City by MEAN is a part of the Bulk Power Participation, Service Schedule K and K-1 between MEAN and the City.

SECTION 1. SERVICES TO BE PROVIDED

1.01 This schedule applies to the Bulk Power Participation provided to the City.

SECTION 2. BILLING ENERGY

2.01 The Total Metered Energy shall be equal to the energy measured by metering equipment installed at the City in accordance with Article XIV of the Electrical Resources Pooling Agreement between MEAN and the City, adjusted for losses to the point or points where the City interconnects with the delivering transmission system.

2.02 Monthly Western Area Power Administration Energy Allocation

a. If the City has a Western Area Power Administration (“WAPA”) EnergyAllocation(s), Monthly WAPA Energy Allocation is equal to the firm energyallocation supplied by WAPA to the City through any of the following regions:WAPA Pick-Sloan Missouri Basin Project (“WAPA UGP”), WAPA Loveland AreaProjects (“WAPA LAP”), or WAPA Salt Lake City Area Integrated Projects (“WAPASLCA”), for that month.

b. In the event the Monthly WAPA Energy Allocation exceeds the Total MeteredEnergy, the Monthly WAPA Energy Allocation shall be equal to the Total Metered Energy for MEAN billing purposes.

2.03 Monthly MEAN Energy is equal to Total Metered Energy, less Monthly WAPA Energy Allocation, less any energy delivered pursuant to any Supplemental Agreement for Wind-Generated Energy Purchase between MEAN and the City (“Contracted Wind”).

SECTION 3. SCHEDULE OF RATES AND CHARGES

3.01 Fixed Cost Recovery Charge

a. The Fixed Cost Recovery Charge consists of costs related primarily to MEAN’sownership of generation, contracted purchase of generating capacity and theoperation of MEAN. The total Fixed Cost Recovery Charge is evaluated annually as part of the fiscal year budget process. The Fixed Cost Recovery Charge shall be

Meeting Attachment H

Deleted: , less any Support Energy as defined in Section 4.01…



Date Approved: August 15, 2019 Effective date of this Schedule of Rates and Charges: September 1, 2019

By: _____________________________________ Supersedes Schedule of Rates and Charges dated Effective April 1, 2019

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allocated based on a three-year historical average non-coincident monthly peak demand (supplied by MEAN), by Participant. The Annual Period used for historical average non-coincident peak demand in the calculation is October – September. A five percent (5%) differential for Schedule K Participants is maintained within the fixed cost recovery structure. The calculated allocation may be adjusted at the discretion of the MEAN Management Committee. The Fixed Cost Recovery Charge shall be billed to City in an amount as follows:

Fixed charge per City as shown on Attachment 1 to this Revised Section III.

3.02 Energy Charge

a. The Energy Charge per kilowatt-hour shall apply to MEAN Energy and shall be billed at a rate equal to the then-current Service Schedule M Energy Charge perkilowatt-hour as defined in Section 3.02 of the Schedule of Rates and Charges forSchedule M plus five percent (5%) and applicable rounding. The billing rate for Schedule K and Schedule K-1 as of the effective date of this Schedule of Rates and Charges, is as follows:

$0.04017

b. The Energy Charge for MEAN Energy is also subject to Section 3.04, Pooled Energy Adjustment (PEA) of this Schedule of Rates and Charges.

3.03 Customer Charge (applicable directly to City as customer) $0.00 per month

3.04 Pooled Energy Adjustment (“PEA”). The purpose of the PEA is to allow MEAN the ability to recover the costs on a monthly basis for energy purchased and generated whenever the actual monthly energy costs to MEAN exceed the budgeted monthly energy costs. The positive difference (“PEA Amount”) for the month will be applied to the Monthly MEAN Energy as defined in Section 2.03 for that month and may be billed during the succeeding billing period.

3.05 Power Factor. If the City's power factor at any Point of Delivery is less than 95%, the City's Fixed Cost Recovery Charge may be adjusted to reflect a 95% power factor and any third-party charges, fines or penalties will be passed through to City.

Deleted: Monthly Support Energy as defined in Section 4.01 for that month and



Date Approved: August 15, 2019 Effective date of this Schedule of Rates and

Charges: September 1, 2019

By: _____________________________________

Supersedes Schedule of Rates and Charges dated Effective April 1, 2019

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3.06 The rates and charges established in this Revised Section III may be modified from time to time by MEAN pursuant to the terms of the Agreement and shall become effective pursuant to such terms.

SECTION 4. CAPACITY COMMITMENT COMPENSATION

4.01 The City shall be reimbursed for the commitment of its accredited generation facilities as follows:

a. Demand Rate for each kilowatt of committed accredited capacity, $1.50 per month.

b. Energy Rate shall be determined by, and may be modified from time to time by, the MEAN Management Committee. The Energy Rate is currently set forth in the Electrical Resources Pooling Agreement Policies and Procedures.

SECTION 5. TRANSMISSION AND SUBTRANSMISSION CHARGES

5.01 Transmission service charges, including applicable ancillary service charges other than operating reserves, for delivery of demand and Billing Energy under the Agreement and Section 2 of this Revised Section III, plus any other contracted transmission service for delivery of City's WAPA power, shall be billed at the transmission service provider's then-current transmission rates.

5.02 In the event that delivery voltages lower than 115 KV or additional transformation or sub-transmission facilities are required to make deliveries to the City, the City shall be required to pay such additional amounts equal to those incurred by MEAN to make such deliveries at that voltage.

5.03 City shall reimburse MEAN for any other expenses incurred by MEAN in accordance with specific agreements between the City and MEAN.

SECTION 6. INTEREST ON LATE PAYMENTS

6.01 Unpaid balances on billings shall accrue interest from the due date until paid at the rate of 12% per annum.

Deleted: SECTION 4. SUPPORT ENERGY¶4.01 Monthly Support Energy is equal to Monthly WAPA Energy, as defined in Section 4.02, minus Monthly WAPA Energy Allocation, as defined in Section 2.02.¶4.02 Monthly WAPA Energy is equal to the following:¶a. If City has an allocation from the WAPA UGP, the Monthly WAPA Energy shall be equal to the firm energy allocation supplied by WAPA for that month.¶b. If City has an allocation of energy from the WAPA LAP, the City’s Monthly WAPA Energy shall be equal to the Monthly WAPA LAP Energy, which is equal to the Total Metered Energy less Contracted Wind, multiplied by the ratio of the firm WAPA LAP demand allocation divided by the City’s non-coincident peak demand in that month.¶c. If City has an allocation of energy from the WAPA SLCA, the Monthly WAPA Energy shall be equal to the Monthly WAPA SLCA Energy, which is equal to the firm WAPA SLCA demand allocation multiplied by the number of hours in the month.¶d. If City has an allocation from both WAPA LAP and WAPA SLCA, the Monthly WAPA Energy is equal to the sum of the City’s Monthly WAPA LAP Energy and Monthly WAPA SLCA Energy.¶4.03 Support Energy Charge ¶a. City shall pay MEAN for Support Energy, as defined in Section 4.01, at the Support Energy Rate which shall be equal to the then-current MEAN Service Schedule M Energy Charge per kilowatt-hour. ¶ ...Deleted: 5

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Documents

Meeting Attachment A