Units Most Likely To Participate Methodology
Monthly Up to $11,317/MW
Weekly Up to $2,612/MW
Daily Up to $522/MW, provided, however, that the Daily rate of $522/MW shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $2,612/MW.
Hourly Up to $32.64/MW, provided, however, that the hourly rate of $32.64/MW shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum daily demand charge of $522/MW, and also not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $2,612/MW.
(ii) Energy Charge of 100% of SIC, plus up to 10% of SIC; and (iii) All charges incurred for transmission service, ancillary services, and transmission losses.
3. If PacifiCorp enters into a purchased power transaction specifically for the purpose of reselling such power hereunder, the rates shall not exceed the sum of the following:
.
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Item 14 Page 207 of 230
(i) PacifiCorp’s out-of-pocket costs of purchasing such capacity and/or energy, including all related charges incurred for transmission service, ancillary services, transmission losses and any applicable taxes or other similar governmental impositions; and
(ii) $1.00 per megawatt-hour multiplied by the total megawatt-hours scheduled.
4. System Incremental Costs (“SIC”) means all reasonably forecasted costs of such power and/or energy and which otherwise would not have been incurred by PacifiCorp including, but not limited to, costs associated with fuel, labor, variable operation and maintenance, start-up, shut-down, fuel handling, taxes or other similar governmental impositions, regulatory commission charges, emission allowances and other environmental compliance costs.
5. Purchasers in cost-based transactions shall also be responsible for any taxes, purchased power costs, and for any other costs incurred by PacifiCorp in fulfilling its obligations for the provision of power and/or energy under the WSPP Agreement, which cost would otherwise not have been incurred, had such service not been provided. .
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WSPP AGREEMENT SCHEDULE Q FOR NEVADA POWER COMPANY
Determination of Ceiling Rates Applicable to Cost-Based Sales Made by Nevada Power Company
1. The following rates shall be applicable to any cost-based sale of power and/or energy made by Nevada Power Company, d/b/a NV Energy (“Nevada Power”) (1) pursuant to the applicable terms and conditions of the WSPP Agreement, including under Service Schedule A (Economy Energy Service), Service Schedule B (Unit Commitment Service), and Service Schedule C (Firm Capacity/Energy Sale or Exchange Service), (2) at a delivery point located within the Nevada Power balancing authority area, and (3) for a term of less than one year.
2. The rates for any cost-based power and/or energy sale made by Nevada Power pursuant to the applicable terms and conditions of the WSPP Agreement from Nevada Power’s generating resources shall not exceed the following:
(i) Maximum Demand Charge:
The Maximum Demand Charge shall be capped using the following methodology:
Units Most Likely To Participate Methodology
Monthly Up to $8,390/MW
Weekly Up to $1,940/MW
Daily Up to $390/MW, provided, however, that the Daily rate of $390/MW shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $1,940/MW.
Hourly Up to $24.40/MW, provided, however, that the hourly rate of $24.40/MW shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum daily demand charge of $390/MW, and also not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $1,940/MW.
(ii) Energy Charge of 100% of SIC, plus up to 10% of SIC; and (iii) All charges incurred for transmission service, ancillary services, and transmission losses.
3. If Nevada Power enters into a purchased power transaction specifically for the purpose of reselling such power hereunder, the rates shall not exceed the sum of the following:
(i) Nevada Power’s out-of-pocket costs of purchasing such capacity and/or energy, including all related charges incurred for transmission service, ancillary services, transmission losses and any applicable taxes or other similar governmental impositions; and
. (ii) $1.00 per megawatt-hour multiplied by the total megawatt-hours scheduled. .
Item 14 Page 209 of 230
4. System Incremental Costs (“SIC”) means all reasonably forecasted costs of such power and/or energy and which otherwise would not have been incurred by Nevada Power including, but not limited to, costs associated with fuel, labor, variable operation and maintenance, start-up, shut-down, fuel handling, taxes or other similar governmental impositions, regulatory commission charges, emission allowances and other environmental compliance costs.
5. Purchasers in cost-based transactions shall also be responsible for any taxes, purchased power costs, and for any other costs incurred by Nevada Power Company in fulfilling its obligations for the provision of power and/or energy under the WSPP Agreement, which cost would otherwise not have been incurred, had such service not been provided. .
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WSPP AGREEMENT SCHEDULE Q FOR PUBLIC SERVICE COMPANY OF
COLORADO
Determination of Ceiling Rates Applicable to Sales Made by Public Service Company of Colorado under the WSPP Agreement
1. The following rates shall be applicable to any cost-based sale of power and/or energy made by Public Service Company of Colorado (“Public Service”) (1) pursuant to the WSPP Agreement, including under Service Schedule A (Economy Energy Service), Service Schedule B (Unit Commitment Service), and Service Schedule C (Firm Capacity/Energy Sale or Exchange Service) and (2) at a delivery point located within the Public Service balancing authority area.
2. The rates for any cost-based power and/or energy sale made pursuant to the WSPP Agreement from certain Public Service generation resources shall not exceed the following:
Maximum Demand Charge:
The Maximum Demand Charge shall be capped at either of the following methodologies:
Units Most Likely to Participate Methodology
Annual $123.73/kW
Monthly $10.62/kW
Weekly $2.45/kW
Daily $0.49/kW, provided, however, that the Daily rate of $0.49/kW shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $2.45/kW.
Hourly $0.0306/kW, provided, however, that the hourly rate of $0.0306/kW shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum daily demand charge of $0.49/kW, and also not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $2.45/kW.
Unit Revenue Constraint Methodology
Annual $265.72/kW
Monthly $22.14/kW
Weekly $5.11/kW
Daily $1.02/kW, provided, however, that the Daily rate of $1.02/kW shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $5.11/kW.
Hourly $0.0639/kW, provided, however, that the hourly rate of $0.0639/kW .
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Item 14 Page 211 of 230
shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum daily demand charge of 1.02/kW, and also not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $5.11/kW.
Note: The total amount of Power available for cost-based sales by Public Service based on the costs of Comanche 3 under the WSPP Agreement and under other Public Service tariffs and arrangements, for which the agreed upon demand charge is determined based on Comanche 3, is limited to 500 MWs on an hourly basis.
Plus:
Energy Charge:
(a) no less than 100% of Public Service’s System Incremental Costs (SIC); plus (b) up to 10% of SIC, provided, however, that whenever the SIC for an hour is based on purchased power, the 10% mark up shall be limited to one mill/kWh.
Note: The total charges for any sale by Public Service using the Maximum Demand Charge as determined based on the Unit Revenue Constraint Methodology shall not exceed (1) the product of the requested demand (kW) multiplied by the applicable Maximum Demand Charge using the Unit Revenue Constraint Methodology as specified above, plus the variable costs of Comanche 3 (based on the most recent historical month where Comanche 3 was operational at least 80 percent of the time), and (2) be lower than a floor equal to 100% of Public Service’s System Incremental Cost.
3. When a cost-based sale of power and/or energy made by Public Service under the WSPP Agreement is conditioned upon Public Service acquiring purchased power, Purchaser shall pay the following amounts to Public Service for power and energy:
(a) Public Service’s actual purchased power costs; plus (b) a one mill adder for transactions of less than one year in duration.
4. Purchasers in cost-based transactions shall also be responsible for any taxes, purchased power costs, and for any other costs incurred by Public Service in fulfilling its obligations for the provision of power and/or energy under the WSPP Agreement, which otherwise would not have been incurred, had such service not been provided.
5. For purposes of this Schedule Q, “Purchased Power” means the Power and Energy purchased from a third party by Public Service and shall consist of the total amount paid therefor by Public Service associated with such purchase, plus any cost which otherwise .
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would not have been incurred, including, but not limited to, regulatory commission charges, transmission losses, third-party transmission charges, and taxes, fees or assessments related to such transactions. Tax expenses shall include the expenses that are incurred as taxes either in connection with the sale or production of such Power and Energy.
The term Purchased Power shall not apply to long-term purchases that are secured to supply Public Service’s obligation load requirements as a system resource or to meet other regulatory requirements.
6. For purposes of this Schedule Q, System Incremental Costs (“SIC”)1 shall be determined as follows:
SIC are any costs forecasted to be incurred by Public Service solely by reason of its provision of an incremental amount of coordination-type energy to supply to another company, including but not limited to, costs for fuel, reactant, labor, operation, maintenance, start-up, fuel handling, taxes, emission allowances, and services provided by RTOs, ISOs, or other transmission providers such as transmission and ancillary services and losses. Such costs may also include costs paid to third parties where Public Service has an existing contractual entitlement to purchase energy. • For intraday (real-time) transactions, incremental cost is determined through a review of hourly system characteristics.
• For non-intraday transactions, incremental cost is determined by using a resource optimization model such as, but not limited to ProSym or GenTrader.
The forecasted incremental cost represents the relative increase in total variable cost, in comparison to the previously determined base variable cost. Public Service forecasts incremental costs on a monthly, daily and hourly basis in order to evaluate whether it would be economic to engage in a wholesale sale of coordination energy.2 In order for Public Service to transact, and sell power to another entity, the purchaser must be willing to pay no less than the forecasted incremental cost for the period during which the energy is sold. It is necessary to use forecasted costs because transactions are entered into in the market in advance. The forecast incremental costs for Public Service utilize its unique portfolio resources, applicable fuel costs and generation characteristics.
Monthly forecasted incremental variable costs are developed utilizing an optimization and unit commitment model. Generation characteristics such as forecasted fuel prices, effective heat rates, system penalty factors, start-up costs, unit parameters (e.g., minimum run time, dispatch minimum, dispatch maximum), variable O&M, and tolling costs are utilized in the model to establish the base cost to serve a forecasted amount of obligation (load and the net of applicable firm purchase and sales transactions). Planned and forced outages are also considered in the model. Additional obligations are added to the model (consistent with blocks traded in the market), and the optimized costs are returned. The difference in costs between the first and second run, i.e., with and without an incremental transaction or load addition, will represent the incremental cost to serve the additional obligation. The .
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Item 14 Page 213 of 230
forecasted incremental cost to serve the additional obligation will establish the minimum price required in order to engage in a sale of similar energy volume.
Daily forecasted incremental costs are developed utilizing a unit commitment and optimization program. The best available generation characteristics are utilized in the model to forecast the base cost to serve the next-day obligation. Additional obligations are applied and system costs evaluated to establish the forecasted cost to serve a potential incremental sale.
On an hourly basis, the system operator forecasts the incremental cost to serve an additional obligation by evaluating current and short-term forecast system conditions and the resources that are not previously allocated to meet established obligations. If additional portfolio resources are available (not allocated for native load requirements), the system operator will evaluate the comprehensive cost to produce the quantity of energy needed for an incremental sale.
If the Parties to a transaction under this WSPP Agreement expressly agree in a transaction agreement, incremental costs may be determined in the same manner as specified above, but on an after-the-fact, actual basis.
Note 1: The Commission previously accepted this incremental rate methodology in Xcel Energy Services, Inc., et al., 117 FERC ¶ 61,180, at PP 45-49 (2006).
Note 2: The Commission has found this approach to be acceptable. See, e.g., Western Systems Power Pool, 55 FERC ¶ 61,495, at 62,718 (1991) (noting that incremental cost “may be forecasted hourly, weekly, or monthly”).
.
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Item 14 Page 214 of 230
WSPP AGREEMENT SCHEDULE Q FOR SIERRA PACIFIC POWER COMPANY Determination of Ceiling Rates Applicable to Cost-Based Sales Made by Sierra Pacific Power Company
1. The following rates shall be applicable to any cost-based sale of power and/or energy made by Sierra Pacific Power Company, d/b/a NV Energy (“Sierra”) (1) pursuant to the applicable terms and conditions of the WSPP Agreement, including under Service Schedule A (Economy Energy Service), Service Schedule B (Unit Commitment Service), and Service Schedule C (Firm Capacity/Energy Sale or Exchange Service), (2) at a delivery point located within the Nevada Power Company balancing authority area (“NEVP”), and (3) for a term of less than one year.
2. The rates for any cost-based power and/or energy sale made by Sierra pursuant to the applicable terms and conditions of the WSPP Agreement from Sierra’s generating resources shall not exceed the following:
(i) Maximum Demand Charge:
The Maximum Demand Charge shall be capped using the following methodology:
Units Most Likely To Participate Methodology
Monthly Up to $9,810/MW
Weekly Up to $2,260/MW
Daily Up to $450/MW, provided, however, that the Daily rate of $450/MW shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $2,260/MW.
Hourly Up to $28.10/MW, provided, however, that the hourly rate of $28.10/MW shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum daily demand charge of $450/MW, and also not exceed the product of the number of kilowatts sold for a week multiplied by the maximum weekly demand charge of $2,260/MW.
(ii) Energy Charge of 100% of SIC, plus up to 10% of SIC; and (iii) All charges incurred for transmission service, ancillary services, and transmission losses.
3. If Sierra enters into purchased power transaction specifically for the purpose of reselling such power hereunder, the rates shall not exceed the sum of the following:
(i) Sierra’s out-of-pocket costs of purchasing such capacity and/or energy, including all related charges incurred for transmission service, ancillary services, transmission losses and any applicable taxes or other similar governmental .
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Item 14 Page 215 of 230
impositions; and
(ii) $1.00 per megawatt-hour multiplied by the total megawatt-hours scheduled.
4. System Incremental Costs (“SIC”) means all reasonably forecasted costs of such power and/or energy and which otherwise would not have been incurred by Sierra including, but not limited to, costs associated with fuel, labor, variable operation and maintenance, startup, shut-down, fuel handling, taxes or other similar governmental impositions, regulatory commission charges, emission allowances and other environmental compliance costs.
5. Purchasers in cost-based transactions shall also be responsible for any taxes, purchased power costs, and for any other costs incurred by Nevada Power Company in fulfilling its obligations for the provision of power and/or energy under the WSPP Agreement, which cost would otherwise not have been incurred, had such service not been provided. .
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Item 14 Page 216 of 230
WSPP AGREEMENT SCHEDULE Q FOR SOUTHWESTERN PUBLIC SERVICE
COMPANY
Determination of Ceiling Rates Applicable to Sales Made by Southwestern Public Service Company under the WSPP Agreement
1. The following rates shall be applicable to any cost-based sale of power and/or energy made by Southwestern Public Service Company (“SPS”) (1) pursuant to the WSPP Agreement, including under Service Schedule A (Economy Energy Service), Service Schedule B (Unit Commitment Service), and Service Schedule C (Firm Capacity/Energy Sale or Exchange Service and (2) at a delivery point located within the SPS balancing authority area.
2. The rates for any cost-based power and/or energy sale made pursuant to the WSPP Agreement from SPS generation resources shall not exceed the following:
Maximum Demand Charge:
Monthly $ 7.56/kW
Weekly $ 1.745/kW
Daily (On-peak) $ 0.349/kW, provided, however, that the Total Weekly charges for a customer paying the Daily rate of $0.349/kW (on-peak) or $0.249 (off-peak) shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum Weekly demand charge of $1.745/kW.
Daily (Off-peak) $ 0.249/kW
Hourly $ 21.813/MW, provided, however, that the Total Daily charges for a customer paying the Hourly rate of $21.813/MW shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum Daily (on-peak) demand charge, and total Weekly charges for such a customer shall not exceed the product of the number of kilowatts sold for a week multiplied by the maximum Weekly demand charge of $1.745/kW.
plus
Energy Charge:
(a) no less than 100% of SPS’s System Incremental Costs (SIC); plus (b) up to 10% of SIC, provided, however, that whenever the SIC for an hour is based on purchased power, the 10% mark up shall be limited to one mill/kWh.
Note A: The total charges for any cost-based sale under the WSPP Agreement shall not exceed the product of the requested demand (kW) multiplied by the applicable Maximum Demand Charge in this Section 1, plus the variable costs of Lea Power Partners (based on the second previous month’s cost data), and not withstanding .
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Item 14 Page 217 of 230
the foregoing, a floor equal to 100% of SPS’s System Incremental Cost.
Note B: The total amount of Power available for cost-based sales by SPS under the WSPP Agreement and under other SPS tariffs and agreements for which the agreed upon demand charge is determined based on Lea Power Partners is limited to 600 MWs on an hourly basis.
3. When a cost-based sale of power and/or energy made by SPS under the WSPP Agreement is conditioned upon SPS acquiring Purchased Power, Purchaser shall pay the following amounts to SPS for power and energy:
(a) SPS’s actual Purchased Power costs; plus
(b) a one mill adder for transactions of less than one year in duration.
4. Purchasers in cost-based transactions shall also be responsible for any taxes, purchased power costs, and for any other costs incurred by SPS in fulfilling its obligations for the provision of power and/or energy under the WSPP Agreement, which otherwise would not have been incurred, had such service not been provided.
5. For purposes of the WSPP Agreement, System Incremental Costs (“SIC”) shall be determined as follows:
SIC are any costs forecasted to be incurred by SPS solely by reason of its provision of an incremental amount of coordination-type energy to supply to another company, including but not limited to costs for fuel, reactant, labor, operation, maintenance, start-up, fuel handling, taxes, emission allowances, and services provided by RTOs, ISOs, or other transmission providers such as transmission and ancillary services and losses. Such costs may also include costs paid to third parties where the SPS has an existing contractual entitlement to purchase energy.
• For intraday (real-time) transactions, incremental cost is determined through a review of hourly system characteristics.
• For non-intraday transactions, incremental cost is determined by using a resource optimization model such as, but not limited to ProSym, Couger or GenTrader.
The forecasted incremental cost represents the relative increase in total variable cost, in comparison to the previously determined base variable cost. SPS forecasts incremental costs on a monthly, daily and hourly basis in order to evaluate whether it would be economic to engage in a wholesale sale of energy.2 In order for SPS to transact, and sell power to another entity, the purchaser must be willing to pay no less than the forecasted incremental cost for the period during which the energy is sold. It is necessary to use forecasted costs because transactions are entered into in the market in advance. The forecast incremental costs for SPS 2 The Commission has found this approach to be acceptable. See, e.g., Western Systems Power Pool, 55 FERC ¶ 61,495 at 62,718 (1991) (noting that incremental cost “may be forecasted hourly, weekly, or monthly”). .
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Item 14 Page 218 of 230
utilize its unique portfolio resources, applicable fuel costs and generation characteristics.
Monthly forecasted incremental variable costs are developed utilizing an optimization and unit commitment model. Generation characteristics such as forecasted fuel prices, effective heat rates, system penalty factors, start-up costs, unit parameters (e.g., minimum run time, dispatch minimum, dispatch maximum), variable O&M, and tolling costs are utilized in the model to establish the base cost to serve a forecasted amount of obligation (load and the net of applicable firm purchase and sales transactions). Planned and forced outages are also considered in the model. Additional obligations are added to the model (consistent with blocks traded in the market), and the optimized costs are returned. The difference in costs between the first and second run, i.e., with and without an incremental transaction or load addition, will represent the incremental cost to serve the additional obligation. The forecasted incremental cost to serve the additional obligation will establish the minimum price required in order to engage in a sale of similar energy volume.
Daily forecasted incremental costs are developed utilizing a unit commitment and optimization program. The best available generation characteristics are utilized in the model to forecast the base cost to serve the next-day obligation. Additional obligations are applied and system costs evaluated to establish the forecasted cost to serve a potential incremental sale.
On an hourly basis, the system operator forecasts the incremental cost to serve an additional obligation by evaluating current system conditions and the resources that are not previously allocated to meet established obligations. If additional portfolio resources are available (not allocated for native load requirements), the system operator will evaluate the comprehensive cost to produce the quantity of energy needed for an incremental sale. .
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Item 14 Page 219 of 230
WSPP AGREEMENT SCHEDULE Q FOR WESTAR ENERGY
Determination of Ceiling Rates Applicable to Cost-Based Sales Made by Westar Energy under the WSPP Agreement
1. The following rates shall be applicable to any cost-based sale of power and/or energy made by Westar Energy (“Westar”) (1) pursuant to the applicable terms and conditions of the WSPP Agreement, including under Service Schedule A (Economy Energy Service), Service Schedule B (Unit Commitment Service), and Service Schedule C (Firm Capacity/Energy Sale or Exchange Service) and (2) at a delivery point located within the Westar Energy balancing authority area.
2. The rates for any cost-based power and/or energy sale made by Westar Energy pursuant to the applicable terms and conditions of the WSPP Agreement from Westar Energy's generating resources shall not exceed the following:
(i) Maximum Demand Charge:
The Maximum Demand Charge shall be capped at either of the following methodologies:
Units Most Likely To Participate Methodology
Monthly Up to $13,520/MW
Weekly Up to $3,120/MW
Daily Up to $624/MW, provided, however, that the Daily rate of $624/MW shall not exceed the product of the number of
kilowatts sold for a week multiplied by the maximum
weekly demand charge of $3,120/MW.
Hourly Up to $39.00/MW, provided, however, that the hourly rate of $39.00/MW shall not exceed the product of the number of kilowatts sold for a day multiplied by the maximum daily demand charge of $624/MW, and also not exceed the
product of the number of kilowatts sold for a week
multiplied by the maximum weekly demand charge of
$3,120/MW.
(ii) Energy Charge of no less than 100% of SIC, plus up to 10% of SIC; and (iii) All charges incurred for transmission service, ancillary services, and transmission losses.
3. If Westar Energy enters into a purchased power transaction specifically for the purpose of reselling such power hereunder, the rates shall not exceed the sum of the following:
.
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Item 14 Page 220 of 230
(i) Westar Energy's out-of-pocket costs of purchasing such capacity and/or energy, including all related charges incurred for transmission service, ancillary services, transmission losses and any applicable taxes or other similar governmental impositions; and
(ii) $1.00 per megawatt-hour multiplied by the total megawatt-hours scheduled.
4. System Incremental Costs (“SIC”) means all reasonably forecasted costs of such power and/or energy and which otherwise would not have been incurred by Westar Energy including, but not limited to, costs associated with fuel, labor, variable operation and maintenance, start-up, shut-down, fuel handling, taxes or other similar governmental impositions, regulatory commission charges, emission allowances and other environmental compliance costs.
5. Purchasers in cost-based transactions shall also be responsible for any taxes, purchased power costs, and for any other costs incurred by Westar Energy in fulfilling its obligations for the provision of power and/or energy under the WSPP Agreement, which cost would otherwise not have been incurred, had such service not been provided. .
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Item 14 Page 221 of 230
LIST OF MEMBERS
26SB 8me LLC
45MG 8me LLC
90FI 8me LLC
92JT 8me LLC
100RD 8me LLC
3 Phases Renewables Inc.
3PR Trading, Inc.
AEP Energy Partners, Inc.
AES Marketing and Trading, LLC
AES Redondo Beach, LLC
Aha Macav Power Service
Alameda Municipal Power
AlbertaEX, L.P.
Albertsons Companies, Inc.
Alcoa Power Marketing LLC
AltaGas Ripon Energy Inc.
Altop Energy Trading LLC
American Electric Power Service Corporation as agent for Indiana Michigan Power Company American Electric Power Service Corporation as agent for Public Service Company of Oklahoma and Southwestern Electric Power Company
Anahau Energy, LLC
Arizona Electric Power Cooperative, Inc.
Arizona Public Service Company
Arkansas Electric Cooperative Corp.
Associated Electric Cooperative, Inc.
ATCO Energy Ltd.
ATNV Energy, LP
Ava Community Energy Authority
Avangrid Power, LLC
Avista Corporation
Basin Electric Power Cooperative
Bear Valley Electric Service, Inc.
BigBeau Solar, LLC
Black Hills Colorado Electric LLC
Black Hills Power Inc.
Black Hills Wyoming, Inc.
Blythe Energy Inc.
BOCA bn, LLC
Bolt Energy Marketing, LLC
Bonneville Power Administration
Boston Energy Trading and Marketing LLC
BP Energy Company
bp Energy Retail Company California LLC
Brookfield Renewable Trading and Marketing LP
Caballero CA Storage, LLC
.
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Item 14 Page 222 of 230
California Choice Energy Authority
California Department of Water Resources
California Power Holdings, LLC
CalPeak Power LLC
Calpine Energy Services, L.P.
Calpine Energy Solutions, LLC
Cargill Power Markets, LLC
Castanea Project, LLC
Castleton Commodities Merchant Trading L.P.
Central Arizona Water Conservation District
Central Coast Community Energy
CFE International LLC
Chevron Power Holdings Inc.
Cheyenne Light, Fuel and Power
Citadel Energy Marketing LLC
Citigroup Energy Inc.
City and County of San Francisco
City of Anaheim, Public Utilities Dept.
City of Azusa, California
City of Banning, California
City of Burbank, California
City of Cerritos (Cerritos Electric Utility)
City of Colton, California
City of Corona Utilities Department
City of Farmington, New Mexico
City of Gillette
City of Glendale, California
City of Independence, Missouri
City of Industry
City of Iola, Kansas
City of Lancaster
City of Lodi Electric Utility
City of Mesa, Arizona
City of Moreno Valley, California
City of Palo Alto, California
City of Pasadena, California
City of Rancho Cucamonga, California
City of Redding, California
City of Riverside, California
City of Roseville, California
City of San José
City of Shasta Lake
City of Sikeston, Board of Municipal Utilities
City of St. George Energy Service Department
City of Vernon, California
City of Wathena, Kansas ..
Item 14 Page 223 of 230
Clatskanie People’s Utility District
Clean Energy Alliance
Clean Power Alliance of Southern California
Cleco Power LLC
Coast Mountain Hydro Limited Partnership
Colorado River Commission of Nevada
Colorado Springs Utilities
Colton Power L.P.
Columbia Power Corporation
Comision Federal de Electricidad
Commercial Energy of Montana Inc.
Condon Wind Power, LLC
ConocoPhillips Company
Constellation Energy Generation, LLC
Constellation NewEnergy, Inc.
Cooperative Energy, a Mississippi electric cooperative
CORE Electric Coop
Coso Geothermal Power Holdings, LLC
Covanta Energy Marketing, LLC
CP Energy Marketing (US) Inc.
Credit Suisse Energy LLC
CWP Energy, Inc.
CXA La Paloma, LLC
Deseret G&T
Desert Harvest II, LLC
Direct Energy Business, LLC
DRW Energy Trading LLC
DTE Energy Trading, Inc.
Dynasty Power Inc.
Dynegy Marketing and Trade, LLC
Dynegy Power Marketing, LLC
East Bay Municipal Utility District
East Texas Electric Cooperative, Inc.
EDF Renewable Windfarm V, Inc.
EDF Trading North America, LLC
Electrical District No. 3 of Pinal County, Arizona
El Paso Electric Company
Elk Hills Power, LLC
Empire District Electric Company
Enel Trading North America, LLC
Energy Development & Construction Corporation
Energy Keepers, Inc.
Energy Unlimited, Inc.
Enersponse Inc.
Engelhart CTP Energy Marketing LLC
Engelhart CTP (US) LLC
.
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Item 14 Page 224 of 230
ENGIE Energy Marketing NA, Inc.
ENMAX Energy Corporation
ENMAX Energy Marketing Inc.
Entergy Services, Inc. (also Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc.)
ETC Endure Energy L.L.C.
Eugene Water & Electric Board
Evergy Kansas Central, Inc.
Evergy Metro, Inc.
Evergy Missouri West, Inc.
Evolugen Trading and Marketing LP
Florida Power & Light Company
FortisBC Inc.
Freepoint Commodities LLC
Freeport-McMoRan Cooper & Gold Energy Services, LLC
GenOn Energy Management, LLC
Geysers Power Company, LLC
Goal Line, LP
Golden Spread Electric Cooperative, Inc.
Goldman Sachs Renewable Power Marketing LLC
Gonzaga Ridge Wind Farm, LLC
Google Energy LLC
Goose Prairie Solar LLC
Grand River Dam Authority
Grays Harbor Energy LLC
Great River Energy
Greenleaf Energy Unit 2, LLC
Gunvor USA LLC
Guzman Energy Partners LLC
Guzman Energy, LLC
Harquahala Sun 1, LLC
Hartree Partners, LP
Heartland Generation Ltd.
Hermiston Generating Company, L.P.
High Desert Power Project, LLC
Hinson Power Company, Inc.
Holy Cross Electric Association d/b/a Holy Cross Energy Idaho Falls Power
Idaho Power Company
Illinois Power Marketing Company
Imperial Irrigation District
Indigo Generation LLC
Inland Empire Energy Center LLC
Inland Power and Light
J. Aron & Company
J.P. Morgan Ventures Energy Corporation
.
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Item 14 Page 225 of 230
Jonesboro City Water and Light
Just Energy Solutions Inc.
Kaiser Aluminum Washington LLC
Kansas City Board of Public Utilities
Kansas Power Pool
Karbone Energy LLC
Kiowa Power Partners, LLC
Lafayette Utilities System
La Plata Electric Association, Inc.
Larkspur Energy LLC
Las Vegas Power Company, LLC
Leapfrog Power, Inc.
Lehi City, d/b/a/ Lehi City Corporation
Lincoln Electric System
Los Alamos County
Los Angeles Department of Water and Power
Louisiana Energy and Power Authority
Louisville Gas & Electric Company
Luminant Energy Company LLC
Macquarie Energy LLC
MAG Energy Solutions Inc.
Malaga Power, LLC
Manitoba Hydro
Marin Clean Energy
Mariposa Energy, LLC
Maverick Solar 4, LLC
Maverick Solar 7, LLC
McMinnville Water & Light
Merced Irrigation District
Mercuria Energy America, LLC
Merrill Lynch Commodities, Inc.
Mesquite Power, LLC
Metropolitan Water District of Southern California
MidAmerican Energy Company
Midway Peaking, LLC
Midwest Energy, Inc.
Missouri Joint Municipal Electric Utility Comm.
Modesto Irrigation District
Mohave Electric Cooperative, Inc.
Morgan Stanley Capital Group, Inc.
Mountain Parks Electric, Inc.
MRP San Joaquin Energy LLC
M-S-R Public Power Agency
Municipal Energy Agency of Nebraska
NaturEner Power Watch, LLC
Navajo Tribal Utility Authority ..
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Nebraska Public Power District
Nevada Cogeneration Associates No. 2
Nevada Gold Energy, LLC
Nevada Power Company
New Harquahala Generating Company, LLC
New-Indy Ontario LLC
New-Indy Oxnard LLC
New West Energy
Nexen Energy Marketing U.S.A. Inc.
NextEra Energy Marketing, LLC
Nexus Energy Inc.
NG Renewables Energy Marketing, LLC
Noble Americas Gas & Power Corp.
Northern California Power Agency
Northern States Power Company
Northern Wasco County People’s Utility District
NorthPoint Energy Solutions Inc.
NorthWestern Corporation dba NorthWestern Energy
NRG Business Marketing LLC
Occidental Power Services, Inc.
Oklahoma Gas & Electric Company
Oklahoma Municipal Power Authority
Omaha Public Power District
Ontario Power Generation Inc.
Orange County Power Authority
Otter Tail Power Company
Pacific Gas & Electric Company
Pacific Summit Energy LLC
PacifiCorp
Pattern Energy Management Services LLC
Patua Acquisition Company, LLC
Peninsula Clean Energy Authority
Phillips 66 Energy Trading LLC
Pilot Power Group, Inc.
Pioneer Community Energy
Pittsburg Power Company
Placer County Water Agency
Platte River Power Authority
Plumas-Sierra Rural Electric Cooperative
PNGC Power
Poblano Energy Storage, LLC
Port of Oakland
Portland General Electric
Power and Water Resources Pooling Authority
Power Company of America, L.P.
Power Resources Cooperative
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Powerex Corp.
Public Service Company of Colorado
Public Service Company of New Mexico
Public Utility District No. 1 of Benton County
Public Utility District No. 1 of Chelan County
Public Utility District No. 1 of Clark County
Public Utility District No. 1 of Cowlitz County
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Franklin County
Public Utility District No. 1 of Grays Harbor County
Public Utility District No. 1 of Klickitat County
Public Utility District No. 1 of Lewis County
Public Utility District No. 1 of Okanogan County
Public Utility District No. 1 of Pend Oreille County
Public Utility District No. 1 of Snohomish County
Public Utility District No. 2 of Grant County
Public Utility District No. 3 of Mason County
Puget Sound Energy
Quintessence, LLC
Rainbow Energy Marketing Corporation
Renewable Power Strategies LLC dba RPS Advisors
Resi Station, LLC
REV Energy Marketing, LLC
Rising Tree Wind Farm LLC
Royal Bank of Canada
RWE Trading Americas Inc.
Saavi Energy Solutions, LLC
Sacramento Municipal Utility District
Saguaro Power Company
Salt River Project Agricultural Improvement and Power District Salton Sea Power L.L.C.
San Diego Community Power
San Diego Gas & Electric Co.
San Gorgonio Farms, Inc.
Seattle City Light
Second Foundation US Trading, LLC
Sempra Gas & Power Marketing LLC
Sentinel Energy Center, LLC
Shell Energy North America (US), L.P.
Sierra Pacific Power Co.
Silicon Valley Clean Energy Authority
Silicon Valley Power
Silver State Energy Association
Skylar Energy Resources, LLC
Skylar Power Marketing, LLC
Skylar Resources, LP
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Solar of Alamosa LLC
Sonoma Clean Power Authority
Southern Calif. Edison Co.
Southern California Public Power Authority
Southern Company Services, Inc., as agent for: Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Southern Power Company Southern Energy Solution Group LLC
Southern Illinois Power Cooperative
Southern Nevada Water Authority
Southwest Public Power Agency, Inc.
Southwestern Power Administration
Southwestern Public Service Company
Sulphur Springs Valley Electric Cooperative, Inc.
Sunrise Power Company, LLC
Sun Streams 2, LLC
Suncor Energy Marketing Inc.
Sunflower Electric Power Corp.
Switched On, LLC
Tacoma Power
Talen Energy Marketing, LLC
Talen Montana, LLC
TC Energy Marketing Inc.
TEC Energy, Inc.
Teck Metals Ltd.
Tenaska Gateway Partners, LTD
Tenaska Power Services Co.
Tennessee Valley Authority
Tesoro Refining & Marketing Company, LLC
TGP Energy Management, LLC
The Energy Authority, Inc.
The Regents of the University of California
Tidal Energy Marketing (U.S.) L.L.C.
TotalEnergies Gas & Power North America, Inc.
Town of Apple Valley
Townsite Solar, LLC
Trafigura Trading LLC
TransAlta Energy Marketing (US) Inc.
TransCanada Energy Sales Ltd.
Trico Electric Cooperative, Inc.
Triolith Energy Fund, LP
Tri-State Generation and Transmission Association, Inc.
Tucson Electric Power Company
Turlock Irrigation District
Twin Eagle Resource Management, LLC
Umatilla Electric Cooperative
Union Electric Company d/b/a Ameren Missouri
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Union Power Partners, L.P.
Uniper Global Commodities North America LLC
United Power, Inc.
UNS Electric Inc.
Utah Associated Municipal Power Systems
Utah Municipal Power Agency
Valley Clean Energy Alliance
Valley Electric Association, Inc.
Vantage Wind Energy LLC
Victorville Municipal Utility Services
Vitol Inc.
WAPA-Colorado River Storage Project
WAPA-Desert Southwest Region
WAPA – Rocky Mountain Region (LAP)
WAPA-Sierra Nevada Region
WAPA-Upper Great Plains Region
Watson Cogeneration Company LLC
Wellhead Power EXchange, LLC
Western Community Energy
Western Farmers Electric Coop.
Western Power and Steam II, LLC
Western Power Services, Inc.
Westlands Grape, LLC
Westlands Solar Blue (OZ) Owner, LLC
WGP Redwood Holdings, LLC
WTMPA/City of Lubbock (Lubbock Power & Light)
Yuba County Water Agency
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City Council Agenda Report
Meeting Date: July 7, 2026
From: Brian Saeki, City Administrator
Department: City Administration
Submitted by: Lilia Hernandez, Deputy City Administrator Subject
City-wide Strategic Plan
Recommendation
Receive a presentation and adopt the City-wide Strategic Plan.
Background
As directed by the City Council, the City engaged Kelly Associates Management Group (Consultant) to assist with a goal-setting process, a priority for the Council as it shapes Vernon’s path forward. The Consultant was tasked with facilitating a goal-setting process, gathering stakeholder feedback, and assisting with the development of a City-wide Strategic Plan.
The goal-setting process began with the preparation of a SWOT analysis (Strengths, Weaknesses, Opportunities, and Threats), which was shared with the City Council, executive and other staff, and community stakeholders, including the Chamber of Commerce, and followed by interviews with these same stakeholders. In addition, the City hosted three community meetings to gather input from residents and businesses. Resident meetings were held on the evening of February 2, 2026, at the Vernon Village Park Apartments and on February 5, 2026 in the City Council Chambers at City Hall. A business breakfast at City Hall was also held on the morning of February 5, 2026.
Reponses from the SWOT analysis and feedback from the community meetings were compiled, summarized, and presented to the City Council at a Special Meeting on March 3, 2026. During the Special Meeting, the City Council was asked to identify key goals which were approved as follows:
1. Strengthen City Credibility and Partnerships
2. Promote Economic Growth and Revenue Generation
3. Advance Sustainability and Environmental Stewardship
4. Enhance Community Infrastructure and Facilities
5. Strengthen Organizational Efficiency and Financial Planning
6. Optimize Public Utility Operations to Ensure Affordable Services Based on the Council Goals noted above, the City’s Executive team worked with the Consultant to develop a list of specific objectives to achieve said goals. The objectives were presented to City Council at their meeting on April 21, 2026 and included a schedule, associated costs, and responsible City department. The City Council provided feedback on the proposed objectives.
Additionally, based on the feedback from Council and the community throughout the goal-setting process, the City’s Executive team worked with the Consultant to identify a set of Core Values, and formulate Mission and Vision Statements reflective of the input received. At the July 7, 2026 Council Meeting, staff will present the final City-wide Five-Year Strategic Plan for adoption.
The Final City of Vernon 2026-2031 Strategic Plan (Strategic Plan) comprises the City’s Mission Statement, Vision Statement, Core Values, Goals and Objectives. The Strategic Plan establishes .
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a vision for Vernon’s future, serves as a roadmap to guide decision-making at all levels throughout the City, and will help ensure that the City remains responsive to the needs of its stakeholders. Once adopted, the Strategic Plan will be shared with the City’s residents, business community, and City staff.
The Strategic Plan is essential to the City’s growth and stability over the next five years and, as a living document, may be modified at any time as new priorities arise. The Strategic plan will also be formally evaluated each year, typically during the budget process.
Fiscal Impact
There is no fiscal impact associated with this report. Strategic Plan tasks for Fiscal Year (FY) 2026-27 were included in the approved budget for the current fiscal year and tasks for subsequent years will be budgeted accordingly.
Attachments
1. City of Vernon Strategic Plan
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STRATEGIC PLAN
2026 - 2031
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“Industry. Community. Innovation.”
Vernon promotes a business-friendly
environment while providing excellent
public services and support for our
community.
MISSION
STATEMENT
VISION
STATEMENT
A dynamic City where trusted
partnerships, premier utilities, engaged
employees, and exemplary public
services drive innovation, economic
vitality, environmental stewardship, and
a strong community.
CITY of VERNON Strategic Plan 2026 2
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Integrity
We uphold transparency, ethical conduct, and
responsible stewardship of public resources.
Excellence
We deliver reliable, quality utility and public services with a commitment to efficiency, affordability, and
continuous improvement.
Collaboration
We build strong relationships with businesses,
residents, employees, and regional stakeholders to
advance shared goals and a thriving community.
Innovation
We continuously improve operations and encourage
creative approaches to proactively address
challenges.
Sustainable Growth
We promote economic vitality while protecting
environmental resources.
CORE
VALUES
CITY of VERNON Strategic Plan 2026 3
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Goal 1: Strengthen City Credibility and Partnerships 5
List of Goal 1 Objectives
Goal 2: Promote Economic Growth and Revenue Generation 10 List of Goal 2 Objectives
Goal 3: Advance Sustainability and Environmental Stewardship 13 List of Goal 3 Objectives
Goal 4: Enhance Community Infrastructure and Facilities 16 List of Goal 4 Objectives
Goal 5: Strengthen Organizational Efficiency and Financial Planning 18 List of Goal 5 Objectives
Goal 6: Optimize Public Utility Operations to Ensure Affordable Services 21 List of Goal 6 Objectives
TABLE OF CONTENTS
CITY of VERNON Strategic Plan 2026 4
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GOAL 1
Strengthen City
Credibility and
Partnerships
To Include:
• Building trust and credibility with the
public and other public agencies
• Pursuing collaborative opportunities
with regional partners to maximize
impact and resources
CITY of VERNON Strategic Plan 2026 5
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GOAL 1 OBJECTIVES
Strengthen City Credibility and Partnerships
CITY of VERNON Strategic Plan 2026 6
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GOAL 1 OBJECTIVES
Strengthen City Credibility and Partnerships
CITY of VERNON Strategic Plan 2026 7
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GOAL 1 OBJECTIVES
Strengthen City Credibility and Partnerships
CITY of VERNON Strategic Plan 2026 8
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GOAL 1 OBJECTIVES
Strengthen City Credibility and Partnerships
CITY of VERNON Strategic Plan 2026 9
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GOAL 2
Promote Economic
Growth and
Revenue
Generation
To Include:
• Attracting residential, retail, and
commercial development
• Providing services to surrounding cities
and exploring new revenue sources,
including green tech and digital
infrastructure
CITY of VERNON Strategic Plan 2026 10
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GOAL 2 OBJECTIVES
Promote Economic Growth and Revenue Generation
CITY of VERNON Strategic Plan 2026 11
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GOAL 2 OBJECTIVES
Promote Economic Growth and Revenue Generation
CITY of VERNON Strategic Plan 2026 12
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GOAL 3
Advance
Sustainability and
Environmental
Stewardship
To Include:
• Improving local air quality and reducing
environmental impacts, particularly in
SELA communities
• Positioning Vernon as a hub for cleantech and circular economy initiatives CITY of VERNON Strategic Plan 2026 13
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GOAL 3 OBJECTIVES
Advance Sustainability and Environmental Stewardship
CITY of VERNON Strategic Plan 2026 14
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GOAL 3 OBJECTIVES
Advance Sustainability and Environmental Stewardship
CITY of VERNON Strategic Plan 2026 15
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GOAL 4
Enhance
Community
Infrastructure and
Facilities
To Include:
• Developing parks, community centers,
libraries, and health clinics to meet
resident needs
• Investing in digital and physical
infrastructure that supports both
community and economic goals
• Exploring new funding mechanisms
to finance public infrastructure and
development projects
CITY of VERNON Strategic Plan 2026 16
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GOAL 4 OBJECTIVES
Enhance Community Infrastructure and Facilities
CITY of VERNON Strategic Plan 2026 17
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GOAL 5
Strengthen
Organizational
Efficiency and
Financial Planning
To Include:
• Streamlining City codes, policies, and
procedures, including purchasing
processes
• Streamlining City meetings to enhance
public engagement and efficiency
• Implementing long-term financial and
capital planning to ensure sustainability
and resilience
CITY of VERNON Strategic Plan 2026 18
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GOAL 5 OBJECTIVES
Strengthen Organizational Efficiency and Financial Planning CITY of VERNON Strategic Plan 2026 19
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GOAL 5 OBJECTIVES
Strengthen Organizational Efficiency and Financial Planning CITY of VERNON Strategic Plan 2026 20
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GOAL 6
Optimize Public
Utility Operations
to Ensure
Affordable Services
To Include:
• Prioritizing the efficient management of
the City’s power, gas, fiber, and water
systems
• Keeping utility costs low for residents
and businesses while maintaining
reliable, high-quality service
• Kern County property
CITY of VERNON Strategic Plan 2026 21
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GOAL 6 OBJECTIVES
Optimize Public Utility Operations to Ensure Affordable Services CITY of VERNON Strategic Plan 2026 22
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GOAL 6 OBJECTIVES
Optimize Public Utility Operations to Ensure Affordable Services CITY of VERNON Strategic Plan 2026 23
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