Public Hearing: Modesto Irrigation District Cost of Service Study and Electric Rates

Transcription

1 '{ ~ID ::.:::. ~ J...ITI Dlstrld BOARD AGENDA REPORT Wltlr M Powtt Complete all fields including resolution 1 if applicable. Meeting Date: December 4, 2018 Subject: Recommended Action: Background and Discussion: Public Hearing: Modesto Irrigation District Cost of Service Study and Electric Rates Resolution adopting Modesto Irrigation District's Cost of Service Study report and findings and Electric Rate Schedules. As a special district organized under the provision of the California Water Code establishing the authority to be a water and power provider, Modesto Irrigation District (MID) must comply with many requirements and mandates enacted by the State of California. These requirements range from rules that mandate a certain energy resource mix to laws that require MID to participate in energy efficiency and distributed generation programs. One such requirement- Proposition 26- was approved by the california electorate on November 2, Proposition 26 amended the State's Constitution to expand the definition of a "tax" to include "any levy, charge, or exaction of any kind imposed by a local government" with listed exceptions. Proposition 26 expressly excludes from its definition of a "tax" any fee for a product or service provided that does not exceed the reasonable costs to the local government of providing the service or product. The MID Board of Directors has full rate-making authority including setting rates and collecting charges from its customers. Based on this authority and in the spirit of transparency and openness, MID engaged with third-party, industry experts to review MID's rate-making practices to ensure compliance with Proposition 26 as it has been recently construed by the appellate courts. Bartle Wells Associates (Bartle Wells) and MRW & Associates, LLC (MRW) were retained by MID to perform an Electric Cost of Service (COS) and Revenue Allocation Study (Study} as part of a broader analysis of the cost of service for all of MID's lines of business. The goal of the Study was to determine revenue requirements to operate the separate lines of service (power, Irrigation, domestic water), update the electric COS and develop electric rates based on the Study. The attached reports and accompanying data sources provide the background and details for the Study. Today staff is requesting adoption of the Study along with associated electric rates. A list of the specific Electric Rate Schedules is shown below and details associated with these rates are included in the attachments. Electric Rate Schedules Schedule D- Residential Service Schedule DLS -Residential Life Support Service Schedule G5-1 -General Service Non Demand Schedule GS-2 -General Service Demand Schedule GS-TOU -General Service Commercial Time of Use Schedule GS-3 -General Service Industrial 2018 Public Rate H-ma.Docx Rev Do< 2010

2 ,~lt11d Modesto lrrl1allon... II! Dl1trlcl \"llttr 111d Pewtr BOARD AGENDA REPORT Alternatives, Pros and Cons of Each Alternative: Concurrence: Fiscal Impact: Recommendation: Attachments: Schedule IC-25 - Industrial Contract 25MW Minimum Demand Schedule Sll-Public Street, Highway, & Park lighting Service Schedule SL2- Private Outdoor Area Lighting Service (Dusk to Dawn Lighting) Schedule - P-3 Water Well Pumping and Agricultural Power Service Schedule - P-4 Interruptible Water Pumping Power Service Pro: Though rates will not change from those!"!ow in effect, readopting rates as Informed by the Study and COS prepared by third-party, independent review will provide valuable analysis and background to confirm MID's existing rates. Con: Status quo- Rates would remain the same, but wouldn't include the third-party analysis and background for current rate-making practices. Finance, Legal None. No change to MID rates Resolution adopting Modesto Irrigation District's Cost of Service Study report and findings and Electric Rates Schedules. Supporting documents attached: ~ Presentation 181 Other supporting docs D None attached Note: Original contracts and agreements are housed in the Board Secretary's Office, phone {209) Details listed above are accurate and complete to the best of my knowledge. Presenter Asst. Gene al Manager ~ Scott Van Vuren 2Dl8 Poblic Rate Hwinc.Ouu RevDeo2010

3 BOARD RESOLUTION RESOLUTION NO t... APPROVING MODESTO IRRIGATION DISTRICT'S COST OF SERVICE REPORT AND ACCOMPANYING ELECTRIC RATE SCHEDULES WHEREAS, staff presented its report to the Board of Directors at a duly noticed Public Hearing on December 4, 2018, on the Electric Cost of Service and Revenue Allocation Study as part of a broader study of the cost of service for all of MID's lines of business and an opportunity was provided for the public to comment on the proposed Study; and WHEREAS, the District's Board of Directors has considered the Study and all of the accompanying Electric Rate Schedules and all comments on the proposed Electric Rate Schedules. NOW, therefore, BE IT RESOLVED, That the Board of Directors of the Modesto Irrigation District does hereby approve the Modesto Irrigation District's Electric Rate Schedules as attached hereto effective January 1, Moved by Director J seconded by Director ---J that the foregoing resolution be adopted. The following vote was had: Ayes: Noes: Absent: 2018 Pubije Rate Hcarin&.Doox Re Oec2010

4 Electric Rate Schedule D Residential Service Page 1 of 2 Applicability This Schedule is applicable to individual family accommodations devoted primarily to residential, household and related purposes (as distinguished from commercial, professional and industrial purposes), to general farm service on a farm, where the residence on such farm is supplied through the same meter, and to public dwelling units as provided in Special Provision 1. Character of Service Alternating current at a frequency of approximately 60 Hertz: 120 volts, 120/208 volts or 120/240 volts, single phase, as specified by the District. Three phase service may be specified and supplied by the District at its option for residential heating and/or air conditioning loads. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Summer (May September) Winter (October April) Fixed Monthly... $20.00 Fixed Monthly... $20.00 Electric Usage (per kwh): Electric Usage (per kwh): First 500 kwh... $ First 500 kwh... $ Over 500 kwh... $ Over 500 kwh... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Special Provisions 1. Multiple Dwelling Units Apartment houses, or groups of apartments in the same building or on the same premises, which are not NEW BUILDINGS as that term is used in Section 113(b)(1) of the Public Utility Regulatory Policies Act of 1978 (PURPA), may receive service under this Schedule through one meter, provided that such energy is not resold by the apartment owner or any other agency. When service is thus taken, the customer shall be put on the applicable Residential D Rate. 2. Air Conditioning Controlled Load Service (S.T.E.P.) 1 Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning which, in the opinion of the District, is suitable for controlled service. 2.1 Written Consent Service under this Schedule shall be provided only upon the written consent of the customer and the owner of the air conditioning equipment (or their authorized agents). Written consent to stop service under this Provision shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. 2.2 Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision S.T.E.P. service under this Schedule is re-opened for new sign-ups effective January 1, 2001, and will remain open subject to the availability of load control equipment in the District s inventory. The District may terminate acceptance of new sign-ups without further notice if it determines that its inventory of load control equipment is or will be fully utilized. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule D, dated January 1,

5 Electric Rate Schedule D Residential Service Page 2 of Rate Discount The following discount will commence with the first billing period reflecting June consumption, and the following three consecutive billing periods. If electric service is terminated, the current available S.T.E.P. credit will be issued on a prorated basis. Monthly Discount June 1 to September 30: (Dollars per Controlled Load per Month) Central Air Conditioning Cycling... $ Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period. 2.5 Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District. 2.6 Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with multiple compressor units require the installation of District control equipment on all compressors. Multiple discounts apply to such installations. 2.7 Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision Installation, Maintenance and Removal Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 3. Energy Assistance Program A discount of 60% will be applied to the Fixed Monthly Charge and a discount of 23.1% will be applied to the first 850 kwh of Electric Usage for low income customers who meet eligibility requirements and are enrolled in the MID CARES program as outlined in Electric Service Rule No Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule D, dated January 1,

6 Electric Rate Schedule DLS Residential Life Support Service Page 1 of 3 Applicability This Schedule is applicable to individual family accommodations devoted primarily to residential, household and related purposes (as distinguished from commercial, professional and industrial purposes), to general farm service on a farm, where the residence on such farm is supplied through the same meter, and to public dwelling units as provided in Special Provision 1. Character of Service Alternating current at a frequency of approximately 60 Hertz: 120 volts, 120/208 volts or 120/240 volts, single phase, as specified by the District. Three phase service may be specified and supplied by the District at its option for residential heating and/or air conditioning loads. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Customers provided service on this Rate have been granted a fifty percent (50%) discount on the first 500 kilowatt-hours of usage per month. Remaining kilowatt-hours will be billed at the applicable Rate Schedule. All special conditions and minimum charges of the Residential Rate Schedule remain in force. Summer (May September) Winter (October April) Fixed Monthly... $20.00 Fixed Monthly... $20.00 Electric Usage (per kwh): Electric Usage (per kwh): First 500 kwh... $ First 500 kwh... $ Over 500 kwh... $ Over 500 kwh... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Special Provisions 1. Multiple Dwelling Units Apartment houses, or groups of apartments in the same building or on the same premises, which are not NEW BUILDINGS as that term is used in Section 113(b)(1) of the Public Utility Regulatory Policies Act of 1978 (PURPA), may receive service under this Schedule through one meter, provided that such energy is not resold by the apartment owner or any other agency. When service is thus taken, the customer shall be put on the applicable Residential D Rate. 2. Medical Life Support Discount Residential customers who provide the required physician s certification, approved by the District, will be able to apply for the discounted Medical Life Support Rate. To qualify, a physician licensed to practice medicine in the state of California must establish that a resident of the household is the doctor s patient and the resident is: a) Dependent uses an electric wheelchair, oxygen concentrator, in-home dialysis cycler or other life support device. Devices used for therapy rather than life support do not qualify. The device must be plugged in and not battery operated. b) A paraplegic, hemiplegic or quadriplegic person with special heating or air conditioning needs. c) A person with multiple sclerosis, scleroderma or has a compromised immune system, life threatening illness, or any other condition for which additional heating or cooling is medically necessary to sustain the person s life or prevent deterioration of the person s medical condition. d) The life support device(s) and/or condition requiring additional heating or cooling will be required for a minimum of 12 months. Eligibility for the Medical Life Support Rate must be approved by the Energy Services Supervisor and physician s confirmation is required annually, except when the patient is permanently disabled and income information is confirmed by official documentation, confirmation is required every two years. It is the responsibility of the District s customer to notify the District of a change of equipment or if the equipment is no longer needed. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule DLS, dated January 1, 2016April 1, 2013.

7 Electric Rate Schedule DLS Residential Life Support Service Page 2 of 3 To be eligible to receive this Rate, the customer must qualify under the eligibility criteria set forth herein and meet certification requirements thereof to the satisfaction of the District. Total gross annual income for all persons in the customer s household may not exceed the HUD median family income effective October 1 of the previous year (the higher of San Joaquin or Stanislaus counties). 3. Income Certification Customers must submit an application to the District or its designated certification agent(s) with proof of income satisfactory to the District including Internal Revenue Service Form 4506-T for all adults (18 years of age or greater) living in the residence. Eligibility will be determined based on this Rate Schedule. Customers suspected of providing incorrect or incomplete information for this Rate may be required to re-certify at any time. Further, the District reserves the right to conduct random audits to determine a customer s eligibility. Failure by any customer asked to provide proper proof of eligibility will result in disqualification of customer s eligibility to receive this Rate. It is the responsibility of the customer to immediately notify the District when the customer is no longer eligible for this Rate. 4. Air Conditioning Controlled Load Service (S.T.E.P.) 1 Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning which, in the opinion of the District, is suitable for controlled service. 4.1 Written Consent Service under this Schedule shall be provided only upon the written consent of the customer and the owner of the air conditioning equipment (or their authorized agents). Written consent to stop service under this Provision shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. 4.2 Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision Rate Discount The following discount will commence with the first billing period reflecting June consumption, and the following three consecutive billing periods. If electric service is terminated, the current available S.T.E.P. credit will be issued on a prorated basis. Monthly Discount June 1 to September 30: (Dollars per Controlled Load per Month) Central Air Conditioning Cycling... $ Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period. 4.5 Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District. 4.6 Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with multiple compressor units require the installation of District control equipment on all compressors. Multiple discounts apply to such installations. 4.7 Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision S.T.E.P. service under this Schedule is re-opened for new sign-ups effective January 1, 2001, and will remain open subject to the availability of load control equipment in the District s inventory. The District may terminate acceptance of new sign-ups without further notice if it determines that its inventory of load control equipment is or will be fully utilized. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule DLS, dated January 1, 2016April 1, 2013.

8 Electric Rate Schedule DLS Residential Life Support Service Page 3 of Installation, Maintenance and Removal Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 5. Energy Assistance Program A discount of 60% will be applied to the Fixed Monthly Charge and a discount of 23.1% will be applied to the first 850 kwh of Electric Usage for low income customers who meet eligibility requirements and are enrolled in the MID CARES program as outlined in Electric Service Rule No Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule DLS, dated January 1, 2016April 1, 2013.

9 Electric Rate Schedule GS-1 General Service Non Demand Page 1 of 2 Applicability This Schedule is applicable to general commercial customers having a demand of 20 kilowatts or less and multiple units for residential occupancy. Service to public dwelling units for residential occupancy is limited by Special Provision 1. Character of Service Alternating current at a frequency of approximately 60 Hertz: 120 volts, 120/208 volts or 120/240 volts, single phase or 240 volts, 240/120 volts, 208Y/120 volts, 480Y/277 volts, 480 volts, 4,160 volts, 12,000 volts, 17,200 volts, 69,000 volts or 115,000 volts three-phase, where and to the extent available, at the option of the District. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Summer (May September) Winter (October April) Fixed Monthly... $18.00 Fixed Monthly... $18.00 Electric Usage (per kwh)... $ Electric Usage (per kwh)... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Determination of Demand Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months or whenever, in the opinion of the District, as, for example, in the case of new customers, the demand is estimated to exceed 20 kilowatts, a meter to measure required demand will be installed and the customer will be served under Electric Rate Schedule GS-2. Such meter, once installed, will not be removed until the demand has fallen below 20 kilowatts for twelve consecutive months. Under certain circumstances, the District may, at its sole option, estimate the demand of the customer. This will usually be done (a) for new customers whose usage is not yet known; (b) when meter readings cannot be obtained; or (c) when a demand meter is required, but may not yet have been installed. Special Provisions 1. Multiple Metering Apartment houses, or groups of apartments in the same building or on the same premises, which are not NEW BUILDINGS as that term is used in Section 113(b)(1) of the Public Utility Regulatory Policies Act of 1978 (PURPA), may receive service under this Schedule through one meter, provided that such energy is not resold by the apartment owner or any other agency. 2. Air Conditioning Controlled Load Service (S.T.E.P.) 1 Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning which, in the opinion of the District, is suitable for controlled service. 2.1 Written Consent Service under this Schedule shall be provided only upon the written consent of the customer. If the customer is other than the landowner and the owner of the air conditioning equipment, the customer shall obtain the permission and authorization of the landowner and owner of the equipment to apply for and take service under this Rate Schedule, and to make the grants required hereunder to the District. Written consent to stop service under this Provision shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. 1 S.T.E.P. service under this Schedule is re-opened for new sign-ups effective January 1, 2001, and will remain open subject to the availability of load control equipment in the District s inventory. The District may terminate acceptance of new sign-ups without further notice if it determines that its inventory of load control equipment is or will be fully utilized. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-1, dated January 1,

10 Electric Rate Schedule GS-1 General Service Non Demand Page 2 of Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision Rate Discount The following discount will commence with the first billing period (June through September, inclusive) after the District control equipment is installed on the customer s air conditioning equipment. The discount is per ton of controlled air conditioner capacity, as determined by the District. Under no circumstance shall the monthly commercial S.T.E.P. credit exceed the monthly electric usage charge. If electric service is terminated, the current available S.T.E.P credit will be issued on a prorated basis. June 1 to September 30: Discount per Account per Month Central Air Conditioning Cycling... $ 2.00 per ton of controlled A/C capacity 2.4 Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period. 2.5 Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District. 2.6 Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with more than two compressor units require the installation of District control equipment on two-thirds of total air conditioning capacity. If there are two compressor units, both must be under load control. 2.7 Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision Installation, Maintenance and Removal Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 3. Energy Assistance Program A discount of 60% will be applied to the Fixed Monthly Charge and a discount of 23.1% will be applied to the Electric Usage for low income customers who meet eligibility requirements and are enrolled in the MID CARES program as outlined in Electric Service Rule No Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-1, dated January 1,

11 Electric Rate Schedule GS-2 General Service - Demand Page 1 of 5 Applicability This Schedule is applicable to general commercial customers having demands in excess of 20 kilowatts and less than 1,000 kilowatts, and public units for residential occupancy. Service to public dwelling units for residential occupancy is limited by Special Provision 1. Character of Service Alternating current at a frequency of approximately 60 Hertz: 120 volts, 120/208 volts or 120/240 volts, single-phase or 240 volts, 240/120 volts, 208Y/120 volts, 480Y/277 volts, 480 volts, 4,160 volts, 12,000 volts, 17,200 volts, 69,000 volts or 115,000 volts three-phase, where and to the extent available, at the option of the District. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Summer (May September) Winter (October April) Fixed Monthly... $45.00 Fixed Monthly... $45.00 Demand (per kw): Demand (per kw): Over 20 kw... $10.31 Over 20 kw... $10.31 Electric Usage (per kwh): Electric Usage (per kwh): First 20,000 kwh... $ First 20,000 kwh... $ Over 20,000 kwh... $ Over 20,000 kwh... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Determination of Demand Customer s Demand shall be the maximum 15-minute rate of taking in kilowatts measured by meter during the month. Should the customer s equipment be such as might impose intermittent or violently fluctuating loads on the District s system, customer s demand for billing purposes may, at the sole option of the District, be based on a 5-minute interval. (See Special Provision 4.) Whenever the monthly demand has fallen below 20 kilowatts for twelve consecutive months the customer will be served under Electric Rate Schedule GS-1. Under certain circumstances, the District may, at its sole option, estimate the demand of the customer. This will usually be done (a) for new customers whose usage is not yet known; (b) when meter readings cannot be obtained; or (c) when a demand meter is required, but may not yet have been installed. If an estimate is used for customer s demand, then that estimate will be used for customer s demand during the month. Special Provisions 1. Multiple Metering Apartment houses, or groups of apartments in the same building or on the same premises, which are not NEW BUILDINGS as that term is used in Section 113(b)(1) of the Public Utility Regulatory Policies Act of 1978 (PURPA), may receive service under this Schedule through one meter, provided that such energy is not resold by the apartment owner or any other agency. 2. Adjustment for Power Factor For customers whose demand exceeds 375 kilowatts, or in the District s judgment may exceed 375 kilowatts, the maximum 15- minute reactive kilovolt-ampere demand requirements will be measured by means of installed instruments, or by periodic tests. If determined by tests, the ratio of such reactive kilovolt-ampere demand requirements to the customer s kilowatt demand requirements at the time of the tests shall be used for computing the Power Factor Adjustment until a new test is made. In any month during which such customer s maximum 15-minute reactive kilovolt-ampere demand requirement is in excess of onehalf of the customer s maximum kilowatt demand requirement, an additional monthly charge of $1.43 will be made for each reactive kilovolt-ampere of such excess. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-2, dated January 1, 2017April 1, 2013.

12 Electric Rate Schedule GS-2 General Service - Demand Page 2 of 5 3. Delivery at Primary or Transmission Voltage When delivery is made at 4,160 volts, 12,000 volts or 17,200 volts, a discount of 10% will be applied to the amount of the demand charge computed as described under Monthly Charges above including any adjustments to the demand charge pursuant to Special Provisions 6 and 7. When delivery is made at 69,000 volts or above, a discount of 15% will be applied to the amount of the demand charge computed as described under Monthly Charges above including any adjustments to the demand charge pursuant to Special Provisions 6 and 7. For totalized accounts the voltage discount is only applicable to meters being served at transmission or primary voltage. 4. Large Demands of Short Duration Where a customer requires new service or modification to existing services to supply x-ray equipment, welding equipment or other equipment which presents large demands of short duration to the District s system, at the sole discretion of the District, such loads may be served through a separate meter and transformer. It is the customer s responsibility to pay for, in advance, such equipment to supply modified service. 5. Air Conditioning Controlled Load Service (S.T.E.P.) 1 Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning which, in the opinion of the District, is suitable for controlled service. 5.1 Written Consent Service under this Schedule shall be provided only upon the written consent of the customer. If the customer is other than the landowner and the owner of the air conditioning equipment, the customer shall obtain the permission and authorization of the landowner and owner of the equipment to apply for and take service under this Rate Schedule, and to make the grants required hereunder to the District. Written consent to stop service under this Provision shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. 5.2 Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision Rate Discount The following discount will commence with the first billing period (June through September, inclusive) after the District control equipment is installed on the customer s air conditioning equipment. The discount is per ton of controlled air conditioner capacity, as determined by the District. Under no circumstance shall the monthly commercial S.T.E.P. credit exceed the monthly electric usage charge. If electric service is terminated, the current available S.T.E.P credit will be issued on a prorated basis. June 1 to September 30: Discount per Account per Month Central Air Conditioning Cycling... $ 2.00 per ton of controlled A/C capacity 5.4 Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period. 5.5 Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District. 5.6 Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with more than two compressor units require the installation of District control equipment on two-thirds of total air conditioning capacity. If there are two compressor units, both must be under load control. 5.7 Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its 1 S.T.E.P. service under this Schedule is re-opened for new sign-ups effective January 1, 2001, and will remain open subject to the availability of load control equipment in the District s inventory. The District may terminate acceptance of new sign-ups without further notice if it determines that its inventory of load control equipment is or will be fully utilized. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-2, dated January 1, 2017April 1, 2013.

13 Electric Rate Schedule GS-2 General Service - Demand Page 3 of 5 other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision Installation, Maintenance and Removal 6. Interruptible Demand Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. The potential interruption period is limited to Monday through Friday, 3:00 p.m. to 6:00 p.m. during the District s Summer Billing Months (May through September). By April 1 of each year, the District will determine how much interruptible load that is required. Application for participation in the interruptible program will be taken up to the last working day in April of that calendar year. Applications will be accepted according to the following criteria: a) Priority will be given to loads that best fit District needs. b) Equivalent loads will be taken on a first come, first served basis until the target interruptible load is met. c) Past non-compliance in previous District interruptible programs may impact eligibility. After May 1 of that calendar year, if the interruptible target has not been met, the District will accept applications for participation in the interruptible program, up to the target, according to the criteria listed above. The Demand Reduction Credit (as described below) will be prorated. 6.1 Customer Eligibility To be eligible for the Interruptible Demand discount in any calendar year, a customer must sign up for the Interruptible Demand discount by the last working day in April of that calendar year. 6.2 Customer Interruptible Customer must reduce demand by the customer s designated kilowatt amount, Interruptible Demand, upon telephone notification by the District. A minimum of 2 hours notice will be provided to the customer prior to implementation of customer s required load reduction. Customer may, but is not required to, verify receipt of District s notice within 30 minutes of receiving such notice. District will provide, if possible, a non-binding notice to the customer by 12:00 noon the workday prior to any planned interruptions. District will have the right to a maximum of 3 interruptions per month per account. 6.3 Interruptible Demand The customer shall state in its application the amount of Interruptible Demand, in kilowatts, subject to interruption pursuant to this Rate, provided that: a) the Interruptible Demand for July and August shall be equal, and shall be at least 100 kilowatts for each month; b) the Interruptible Demand for May, June and September shall be at least fifty percent (50%) of the Interruptible Demand for July and August, but not greater than the Interruptible Demand for July and August; c) the maximum Interruptible Demand in any month shall be no greater than 90% of the customer s total demand for that same month of the previous year. To allow new customers to be eligible for this Provision, the District will estimate the monthly demands for customers without prior billing history with the District until actual billing demand data become available. 6.4 Demand Reduction In the event the District, in its sole judgment, determines that it must reduce load, and the District notifies a customer of the requirement to reduce its demand, the customer must reduce its demand by the amount of customer designated Interruptible Demand calculated as follows: The Demand Reduction for any particular day shall be deemed the difference from customer s greatest recorded 15-minute peak demand during the 2-hour period immediately preceding the commencement of the interruption period to the greatest 15-minute demand recorded within the Interruptible Demand period. 6.5 Demand Reduction Credit In a month in which no request for Interruptible Demand Reduction has been made, customer shall receive a credit to their monthly demand charges of $3.62 per kilowatt per month of customer designated Interruptible Demand. In a month in which the District has requested Demand Reduction, customer shall receive a credit of $3.62 per kilowatt per month of actual Demand Reduction achieved as described in Section 6.4, not to exceed the customer designated Interruptible Demand amount. In months in which multiple requests for Demand Reduction are made, customer credit shall be based on the occurrence in which the least amount of actual Demand Reduction was achieved. For billing purposes, the Interruptible Demand shall be the same as the customer s demand, if customer s demand is less than the Interruptible Demand. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-2, dated January 1, 2017April 1, 2013.

14 Electric Rate Schedule GS-2 General Service - Demand Page 4 of Non-Compliance Demand Charge A Non-Compliance Demand Charge will be imposed in the event that the customer fails to reduce its demand by the designated kilowatt amount during any 15-minute interval during an interruption period as required by the District pursuant to this Provision. The Non-Compliance Demand Charge will be based on the highest single Non-Compliance Demand incurred by the customer in the billing month for which the Non-Compliance Demand Charge is imposed. The Non-Compliance Demand Charge will be $3.62 per kilowatt multiplied by the number of kilowatts by which the customer failed to reduce its demand as described in Section 6.4, provided that the Non-Compliance Demand Charge shall not exceed $3.62 multiplied by the Interruptible Demand. Any customer failing to reduce its demand by the designated kilowatt amount on two or more occasions during any 12-month period will, at the District s option, become ineligible for this Provision and will not become eligible for the Provision for a period of 12 months. 6.7 Maintenance Outage Notice The customer shall have the right to waive all or part of its Interruptible Demand obligation for a maximum of one month per year. For the customer to waive all or part of its Interruptible Demand obligation in a month, written notice must be received by the District s Dispatching Supervisor at least five (5) working days prior to the month the customer wishes to waive all or part of its Interruptible obligation. This notice must specify the month a change is requested and the revised kilowatt amount of Interruptible Demand. Upon acceptance of the Maintenance Outage Notice, the customer will be obligated to reduce load, if called upon, by the revised amount specified in the notice. Customer Interruptible Demand Credit in that month will be based upon the revised Interruptible Demand as specified in the Maintenance Outage Notice. 7. Economic Development Discount Qualified customers locating or expanding in the District service territory which create new economic development and job opportunities in the community are eligible for a three-year rate discount. 7.1 Rate A three-year, five percent (5%) rate discount based on the energy, demand and fixed monthly charge portions of applicable Rate Schedule, excluding taxes. The discount will be determined prior to any credit for primary voltage discount. This discount will be given as an annual or monthly bill credit, at the option of the District. 7.2 Qualification Qualified customers are new customers with a minimum load requirement of 200 kilowatts, or existing customers who add a minimum 200 kilowatts of new load. For existing customers, only the additional new load will qualify for the discount and will be based on the customer s existing applicable Rate Schedule. Should the additional new load qualify the customer for another Rate Schedule under which this Provision is applicable, such Rate Schedule shall supersede the existing Schedule and shall become the basis from which the discount is calculated. When an existing facility has been out of operation or has experienced measurable reduction in electric power consumption, an increase in electrical use will only be considered net new load when the non-operation or measurable reduction has existed for at least one year. All new load shall be subject to verification and approval by the District. Qualifying new incremental loads that are seasonal in nature are eligible for the Economic Development Discount; however, the discounts shall apply only during the months during which the loads are in full operation. Qualified customers include those engaged in business classified under the North American Industrial Classification System (NAICS) codes through or through , inclusive, or any other customers eligible for service under this Rate Schedule that at the District s sole discretion may be determined to qualify for this discount. 7.3 Contract Qualifying customers must enter into a five (5) year contract with the District. After three (3) years the customer will have the option to choose other contract rate options available, if qualifying requirements are met. The discount period shall commence within 12 months following the date of execution of the contract for service and shall be designated by the customer therein. Customer must receive 100% of electric usage from the District for the term of this Contract. Connection of non-district electric generation during the term of this contract will forfeit all Economic Development Discounts received during the term of this contract. 7.4 Metering 8. Proration Separate electric metering for additional load may be required if, in the District s sole opinion, it is necessary to provide service under this Provision. The customer will be responsible for any costs associated with providing separate electric metering. When a customer switches from another Rate Schedule to this Rate Schedule, the change will take effect with the next billing period and there will be no proration. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-2, dated January 1, 2017April 1, 2013.

15 Electric Rate Schedule GS-2 General Service - Demand Page 5 of 5 9. Energy Assistance Program A discount of 60% will be applied to the Fixed Monthly Charge and a discount of 23.1% will be applied to the Electric Usage for low income customers who meet eligibility requirements and are enrolled in the MID CARES program as outlined in Electric Service Rule No Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-2, dated January 1, 2017April 1, 2013.

16 Electric Rate Schedule GS-TOU General Service Commercial, Time-of-Use Page 1 of 5 Applicability This Schedule is offered as an option to commercial customers having demands from 500 kilowatts up to 1,000 kilowatts in any month during the previous twelve (12) months. Character of Service Alternating current at a frequency of approximately 60 Hertz: 240 volts, 240/120 volts, 208Y/120 volts, 480Y/277 volts, 480 volts, 4,160 volts, 12,000 volts, 17,200 volts, 69,000 volts or 115,000 volts three phase, where and to the extent available, at the option of the District. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Summer (May September) Winter (October April) Fixed Monthly... $ Fixed Monthly... $ Demand (per kw)... $16.37 Demand (per kw)... $16.37 Electric Usage (per kwh): Electric Usage (per kwh): On Peak... $ On Peak... $ Partial Peak...$ Off Peak... $ Off Peak... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Determination of Demand Customer s Demand shall be the maximum 15-minute rate of taking in kilowatts measured by meter during the month. Should the customer s equipment be such as might impose intermittent or violently fluctuating loads on the District s system, customer s demand for billing purposes may, at the sole option of the District, be based on a 5-minute interval. (See Special Provision 6.) Under certain circumstances, the District may, at its sole option, estimate the demand of the customer. This will usually be done (a) for new customers whose usage is not yet known; (b) when meter readings cannot be obtained; or (c) when a demand meter is required, but may not yet have been installed. If an estimate is used for customer s demand, then that estimate will be used for customer s demand during the month. Special Provisions 1. Adjustment for Power Factor For customers on this Rate Schedule, the maximum 15-minute reactive kilovolt-ampere demand requirements will be measured by means of installed instruments, or by periodic tests, the ratio of such reactive kilovolt-ampere demand requirements to the customer s kilowatt demand requirements at the time of the tests shall be used for computing the Power Factor Adjustment until a new test is made. In any month during which such customer s maximum 15-minute reactive kilovolt-ampere demand requirement is in excess of onehalf of the customer s maximum kilowatt demand requirement, an additional monthly charge of $1.43 will be made for each reactive kilovolt-ampere of such excess. 2. Delivery at Primary or Transmission Voltage When delivery is made at 4,160 volts, 12,000 volts or 17,200 volts, a discount of 10% will be applied to the amount of the demand charge computed as described under Monthly Charges above including any adjustments to the demand charges pursuant to Special Provisions 8 and 10. When delivery is made at 69,000 volts or above, a discount of 15% will be applied to the amount of the demand charge computed as described under Monthly Charges above including any adjustments to the demand charges pursuant to Special Provisions 8 and 10. For totalized accounts the voltage discount is only applicable to meters being served at transmission or primary voltage. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-TOU, dated January 1, 2017April 1, 2013.

17 Electric Rate Schedule GS-TOU General Service Commercial, Time-of-Use Page 2 of 5 3. Availability Service under this Rate Schedule is available the first of the month following customer s selection to receive service under this Rate Schedule. Once established on the GS-TOU Rate, a customer may elect to receive service under a different Rate Schedule at any time by giving the District notice in writing at least thirty (30) days in advance of the effective date of the desired new Rate Schedule. In the event customer changes service from the GS-TOU Rate, such Rate Schedule shall not be available for a period of twelve months from the effective date of the new Rate. 4. Proration When a customer switches from another Rate Schedule to this Rate Schedule, the change will take effect with the next billing period and there will be no proration. 5. Time Periods Time periods are defined as follows Winter: (Service from October 1 through April 30) On Peak: 8:00 a.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Summer: (Service from May 1 through September 30) On Peak: 1:00 p.m. to 9:00 p.m. Monday through Friday, excluding holidays. Partial Peak: 8:00 a.m. to 1:00 p.m. and 9:00 p.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Holidays are: New Year s Day, President s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. 6. Large Demands of Short Duration Where a customer requires new service or modification to existing services to supply x-ray equipment, welding equipment or other equipment which presents large demands of short duration to the District s system, at the sole discretion of the District, such loads may be served through a separate meter and transformer. It is the customer s responsibility to pay for, in advance, such equipment to supply modified service. 7. Implementation Customers may take service under this Schedule following installation of metering equipment as specified by the District. 8. Interruptible Demand The potential interruption period is limited to Monday through Friday, 3:00 p.m. to 6:00 p.m. during the District s Summer Billing Months (May through September). By April 1 of each year, the District will determine how much interruptible load that is required. Application for participation in the interruptible program will be taken up to the last working day in April of that calendar year. Applications will be accepted according to the following criteria: a) Priority will be given to loads that best fit District needs. b) Equivalent loads will be taken on a first come, first served basis until the target interruptible load is met. c) Past non-compliance in previous District interruptible programs may impact eligibility. After May 1 of that calendar year, if the interruptible target has not been met, the District will accept applications for participation in the interruptible program, up to the target, according to the criteria listed above. The Demand Reduction Credit (as described below) will be prorated. 8.1 Customer Eligibility To be eligible for the Interruptible Demand discount in any calendar year, a customer must sign up for the Interruptible Demand discount by the last working day in April of that calendar year. 8.2 Customer Interruptible Customer must reduce demand by the customer s designated kilowatt amount, Interruptible Demand, upon telephone notification by the District. A minimum of 2 hours notice will be provided to the customer prior to implementation of customer s required load reduction. Customer may, but is not required to verify receipt of District s notice within 30 minutes of receiving such notice. District will provide, if possible, a non-binding notice to the customer by 12:00 noon the workday prior to any planned interruptions. District will have the right to a maximum of 3 interruptions per month per account. 8.3 Interruptible Demand The customer shall state in its application the amount of demand, in kilowatts, subject to interruption pursuant to this Rate, provided that: Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-TOU, dated January 1, 2017April 1, 2013.

18 Electric Rate Schedule GS-TOU General Service Commercial, Time-of-Use Page 3 of 5 a) the Interruptible Demand for July and August shall be equal, and shall be at least 100 kilowatts for each month; b) the Interruptible Demand for May, June and September shall be at least fifty percent (50%) of the Interruptible Demand for July and August, but not greater than the Interruptible Demand for July and August; c) the maximum interruptible demand in any month shall be no greater than 90% of the customer s total demand for that same month of the previous year. To allow new customers to be eligible for this Provision, the District will estimate the monthly demands for customers without prior billing history with the District until actual billing demand data become available. Customer shall receive a credit to their monthly demand charges of $3.62 per kilowatt per month for each kilowatt of Interruptible Demand selected. For billing purposes the Interruptible Demand shall be the same as the Customer s Demand, if Customer s Demand is less than the Interruptible Demand. 8.4 Demand Reduction In the event the District, in its sole judgment, determines that it must reduce load, and the District notifies a customer of the requirement to reduce its demand, the customer must reduce its demand in accordance with its Interruptible Demand, calculated as follows: The Demand Reduction for any particular day shall be the customer s 15-minute peak demand during the 2-hour period immediately preceding the commencement of the interruption period, less the Interruptible Demand set forth in the customer s application. 8.5 Non-Compliance Demand Charge A Non-Compliance Demand Charge will be imposed in the event that the customer fails to reduce its demand by the designated kilowatt amount during any 15-minute interval during an interruption period as required by the District pursuant to this Provision. The Non-Compliance Demand Charge will be based on the highest single Non-Compliance Demand incurred by the customer in the billing month for which the Non-Compliance Demand Charge is imposed. The Non-Compliance Demand Charge will be $3.62 per kilowatt multiplied by the number of kilowatts by which the customer failed to reduce its demand. Any customer failing to reduce its demand by the designated kilowatt amount on two or more occasions during any 12-month period will, at the District s option, become ineligible for this Provision and will not become eligible for the Provision for a period of 12 months. 8.6 Maintenance Outage Notice The customer shall have the right to waive all or part of its Interruptible Demand obligation for a maximum of one month per year. For the customer to waive all or part of its Interruptible Demand obligation in a month, written notice must be received by the District s Dispatching Supervisor at least five (5) working days prior to the month the customer wishes to waive all or part of its Interruptible obligation. This notice must specify the month a change is requested and the revised kilowatt amount of Interruptible Demand. Upon acceptance of the Maintenance Outage Notice, the customer will be obligated to reduce load, if called upon, by the revised amount specified in the notice. Customer Interruptible Demand Credit in that month will be based upon the revised Interruptible Demand as specified in the Maintenance Outage Notice. 9. Air Conditioning Controlled Load Service (S.T.E.P.) 1 Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning which, in the opinion of the District, is suitable for controlled service. 9.1 Written Consent Service under this Schedule shall be provided only upon the written consent of the customer. If the customer is other than the landowner and the owner of the air conditioning equipment, the customer shall obtain the permission and authorization of the landowner and owner of the equipment to apply for and take service under this Rate Schedule, and to make the grants required hereunder to the District. Written consent to stop service under this Provision shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. 9.2 Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision Rate Discount The following discount will commence with the first billing period (June through September, inclusive) after the District control equipment is installed on the customer s air conditioning equipment. The discount is per ton of controlled air conditioner capacity, as determined by the District. Under no circumstance shall the monthly commercial S.T.E.P. credit 1 S.T.E.P. service under this Schedule is re-opened for new sign-ups effective January 1, 2001, and will remain open subject to the availability of load control equipment in the District s inventory. The District may terminate acceptance of new sign-ups without further notice if it determines that its inventory of load control equipment is or will be fully utilized. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-TOU, dated January 1, 2017April 1, 2013.

19 Electric Rate Schedule GS-TOU General Service Commercial, Time-of-Use Page 4 of 5 exceed the monthly electric usage charge. If electric service is terminated, the current available S.T.E.P credit will be issued on a prorated basis. June 1 to September 30: Discount per Account per Month Central Air Conditioning Cycling... $ 2.00 per ton of controlled A/C capacity 9.4 Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period. 9.5 Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District. 9.6 Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with more than two compressor units require the installation of District control equipment on two-thirds of total air conditioning capacity. If there are two compressor units, both must be under load control. 9.7 Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision Installation, Maintenance and Removal Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 10. Economic Development Discount Qualified customers locating or expanding in the District service territory which create new economic development and job opportunities in the community are eligible for a three-year rate discount Rate A three-year, five percent (5%) rate discount based on the energy, demand and fixed charge portions of applicable Rate Schedule, excluding taxes. The discount will be determined prior to any credit for primary voltage discount. This discount will be given as an annual or monthly bill credit, at the option of the District Qualification Qualified customers are new customers with a minimum load requirement of 500 kilowatts, or existing customers who add a minimum 200 kilowatts of new load. For existing customers, only the additional new load will qualify for the discount and will be based on the customer s existing applicable Rate Schedule. Should the additional new load qualify the customer for another Rate Schedule under which this Provision is applicable, such Rate Schedule shall supersede the existing Schedule and shall become the basis from which the discount is calculated. When an existing facility has been out of operation or has experienced measurable reduction in electric power consumption, an increase in electrical use will only be considered net new load when the non-operation or measurable reduction has existed for at least one year. All new load shall be subject to verification and approval by the District. Qualifying new incremental loads that are seasonal in nature are eligible for the Economic Development Discount; however, the discounts shall apply only during the months during which the loads are in full operation. Qualified customers include those engaged in business classified under the Federal Standard Industrial Classification (SIC) secondary codes 2011 through 5199, inclusive, or any other customers eligible for service under this Rate Schedule that at the District s sole discretion may be determined to qualify for this discount Contract Qualifying customers must enter into a five (5) year contract with the District. After three (3) years the customer will have the option to choose other contract rate options available, if qualifying requirements are met. The discount period shall commence within 12 months following the date of execution of the contract for service and shall be designated by the customer therein. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-TOU, dated January 1, 2017April 1, 2013.

20 Electric Rate Schedule GS-TOU General Service Commercial, Time-of-Use Page 5 of 5 Customer must receive 100% of electric usage from the District for the term of this Contract. Connection of non-district electric generation during the term of this contract will forfeit all Economic Development Discounts received during the term of this contract Metering 11. Electric Service Rules Separate electric metering for additional load may be required if, in the District s sole opinion, it is necessary to provide service under this Provision. The customer will be responsible for any costs associated with providing separate electric metering. Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-TOU, dated January 1, 2017April 1, 2013.

21 Electric Rate Schedule GS-3 General Service - Industrial Page 1 of 5 Applicability This Schedule is applicable to industrial customers having demands of 1,000 kilowatts or greater in any month during the previous twelve (12) months. Character of Service Alternating current at a frequency of approximately 60 Hertz: 208Y/120 volts, 480Y/277 volts, 480 volts, 4,160 volts, 12,000 volts, 17,200 volts, 69,000 volts or 115,000 volts three phase, where and to the extent available, at the option of the District. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Summer (May September) Winter (October April) Fixed Monthly... $ Fixed Monthly... $ Demand (per kw)... $17.78 Demand (per kw)... $17.78 Electric Usage (per kwh): Electric Usage (per kwh): On Peak... $ On Peak... $ Partial Peak...$ Off Peak... $ Off Peak... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Determination of Demand Customer s Demand shall be the maximum 15-minute rate of taking in kilowatts measured by meter during the month. Should the customer s equipment be such as might impose intermittent or violently fluctuating loads on the District s system, customer s demand for billing purposes may, at the sole option of the District, be based on a 5-minute interval. (See Special Provision 6.) Under certain circumstances, the District may, at its sole option, estimate the demand of the customer. This will usually be done (a) for new customers whose usage is not yet known; (b) when meter readings cannot be obtained; or (c) when a demand meter is required, but may not yet have been installed. If an estimate is used for customer s demand, then that estimate will be used for customer s demand during the month. Special Provisions 1. Adjustment for Power Factor For customers on this Rate Schedule, the maximum 15-minute reactive kilovolt-ampere demand requirements will be measured by means of installed instruments, or by periodic tests, the ratio of such reactive kilovolt-ampere demand requirements to the customer s kilowatt demand requirements at the time of the tests shall be used for computing the Power Factor Adjustment until a new test is made. In any month during which such customer s maximum 15-minute reactive kilovolt-ampere demand requirement is in excess of onehalf of the customer s maximum kilowatt demand requirement, an additional monthly charge of $1.43 will be made for each reactive kilovolt-ampere of such excess. 2. Delivery at Primary or Transmission Voltage When delivery is made at 4,160 volts, 12,000 volts or 17,200 volts, a discount of 10% will be applied to the amount of the demand charge computed as described under Monthly Charges above including any adjustments to the demand charges pursuant to Special Provisions 8 and 10. When delivery is made at 69,000 volts or above, a discount of 15% will be applied to the amount of the demand charge computed as described under Monthly Charges above including any adjustments to the demand charges pursuant to Special Provisions 8 and 10. For totalized accounts the voltage discount is only applicable to meters being served at transmission or primary voltage. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-3, dated January 1, 2017April 1, 2013.

22 Electric Rate Schedule GS-3 General Service - Industrial Page 2 of 5 3. Availability Service under this Rate Schedule is available the first of the month following customer s selection to receive service under this Rate Schedule. Once established on the GS-3 Rate, a customer may elect to receive service under a different Rate Schedule at any time by giving the District notice in writing at least thirty (30) days in advance of the effective date of the desired new Rate Schedule. In the event customer changes service from the GS-3 Rate, such Rate Schedule shall not be available for a period of twelve months from the effective date of the new Rate. 4. Proration When a customer switches from another Rate Schedule to this Rate Schedule, the change will take effect with the next billing period and there will be no proration. 5. Time Periods Time periods are defined as follows Winter: (Service from October 1 through April 30) On Peak: 8:00 a.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Summer: (Service from May 1 through September 30) On Peak: 1:00 p.m. to 9:00 p.m. Monday through Friday, excluding holidays. Partial Peak: 8:00 a.m. to 1:00 p.m. and 9:00 p.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Holidays are: New Year s Day, President s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. 6. Large Demands of Short Duration Where a customer requires new service or modification to existing services to supply x-ray equipment, welding equipment or other equipment which presents large demands of short duration to the District s system, at the sole discretion of the District, such loads may be served through a separate meter and transformer. It is the customer s responsibility to pay for, in advance, such equipment to supply modified service. 7. Implementation Customers may take service under this Schedule following installation of metering equipment as specified by the District. 8. Interruptible Demand The potential interruption period is limited to Monday through Friday, 3:00 p.m. to 6:00 p.m. during the District s Summer Billing Months (May through September). By April 1 of each year, the District will determine how much interruptible load that is required. Application for participation in the interruptible program will be taken up to the last working day in April of that calendar year. Applications will be accepted according to the following criteria: a) Priority will be given to loads that best fit District needs. b) Equivalent loads will be taken on a first come, first served basis until the target interruptible load is met. c) Past non-compliance in previous District interruptible programs may impact eligibility. After May 1 of that calendar year, if the interruptible target has not been met, the District will accept applications for participation in the interruptible program, up to the target, according to the criteria listed above. The Demand Reduction Credit (as described below) will be prorated. 8.1 Customer Eligibility To be eligible for the Interruptible Demand discount in any calendar year, a customer must sign up for the Interruptible Demand discount by the last working day in April of that calendar year. 8.2 Customer Interruptible Customer must reduce demand by the customer s designated kilowatt amount, Interruptible Demand, upon telephone notification by the District. A minimum of 2 hours notice will be provided to the customer prior to implementation of customer s required load reduction. Customer may, but is not required to, verify receipt of District s notice within 30 minutes of receiving such notice. District will provide, if possible, a non-binding notice to the customer by 12:00 noon the workday prior to any planned interruptions. District will have the right to a maximum of 3 interruptions per month per account. 8.3 Interruptible Demand The customer shall state in its application the amount of Interruptible Demand, in kilowatts, subject to interruption pursuant to this Rate, provided that: Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-3, dated January 1, 2017April 1, 2013.

23 Electric Rate Schedule GS-3 General Service - Industrial Page 3 of 5 a) the Interruptible Demand for July and August shall be equal, and shall be at least 100 kilowatts for each month; b) the Interruptible Demand for May, June and September shall be at least fifty percent (50%) of the Interruptible Demand for July and August, but not greater than the Interruptible Demand for July and August; c) the maximum Interruptible Demand in any month shall be no greater than 90% of the customer s total demand for that same month of the previous year. To allow new customers to be eligible for this Provision, the District will estimate the monthly demands for customers without prior billing history with the District until actual billing demand data become available. 8.4 Demand Reduction In the event the District, in its sole judgment, determines that it must reduce load, and the District notifies a customer of the requirement to reduce its demand, the customer must reduce its demand by the amount of customer designated Interruptible Demand calculated as follows: The Demand Reduction for any particular day shall be deemed the difference from customer s greatest recorded 15-minute peak demand during the 2-hour period immediately preceding the commencement of the interruption period to the greatest 15-minute demand recorded within the Interruptible Demand period. 8.5 Demand Reduction Credit In a month in which no request for Interruptible Demand Reduction has been made, customer shall receive a credit to their monthly demand charges of $3.62 per kilowatt per month of customer designated Interruptible Demand. In a month in which the District has requested Demand Reduction, customer shall receive a credit of $3.62 per kilowatt per month of actual Demand Reduction achieved as described in Section 8.4, not to exceed the customer designated Interruptible Demand amount. In months in which multiple requests for Demand Reduction are made, customer credit shall be based on the occurrence in which the least amount of actual Demand Reduction was achieved. For billing purposes, the Interruptible Demand shall be the same as the customer s demand, if customer s demand is less than the Interruptible Demand. 8.6 Non-Compliance Demand Charge A Non-Compliance Demand Charge will be imposed in the event that the customer fails to reduce its demand by the designated kilowatt amount during any 15-minute interval during an interruption period as required by the District pursuant to this Provision. The Non-Compliance Demand Charge will be based on the highest single Non-Compliance Demand incurred by the customer in the billing month for which the Non-Compliance Demand Charge is imposed. The Non-Compliance Demand Charge will be $3.62 per kilowatt multiplied by the number of kilowatts by which the customer failed to reduce its demand as described in Section 8.4, provided that the Non-Compliance Demand Charge shall not exceed $3.62 multiplied by the Interruptible Demand. Any customer failing to reduce its demand by the designated kilowatt amount on two or more occasions during any 12-month period will, at the District s option, become ineligible for this Provision and will not become eligible for the Provision for a period of 12 months. 8.7 Maintenance Outage Notice The customer shall have the right to waive all or part of its Interruptible Demand obligation for a maximum of one month per year. For the customer to waive all or part of its Interruptible Demand obligation in a month, written notice must be received by the District s Dispatching Supervisor at least five (5) working days prior to the month the customer wishes to waive all or part of its Interruptible obligation. This notice must specify the month a change is requested and the revised kilowatt amount of Interruptible Demand. Upon acceptance of the Maintenance Outage Notice, the customer will be obligated to reduce load, if called upon, by the revised amount specified in the notice. Customer Interruptible Demand Credit in that month will be based upon the revised Interruptible Demand as specified in the Maintenance Outage Notice. 9. Air Conditioning Controlled Load Service (S.T.E.P.) 1 Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning which, in the opinion of the District, is suitable for controlled service. 9.1 Written Consent Service under this Schedule shall be provided only upon the written consent of the customer. If the customer is other than the landowner and the owner of the air conditioning equipment, the customer shall obtain the permission and authorization of the landowner and owner of the equipment to apply for and take service under this Rate Schedule, and to make the grants required hereunder to the District. Written consent to stop service under this Provision shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. 1 S.T.E.P. service under this Schedule is re-opened for new sign-ups effective January 1, 2001, and will remain open subject to the availability of load control equipment in the District s inventory. The District may terminate acceptance of new sign-ups without further notice if it determines that its inventory of load control equipment is or will be fully utilized. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-3, dated January 1, 2017April 1, 2013.

24 Electric Rate Schedule GS-3 General Service - Industrial Page 4 of Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision Rate Discount The following discount will commence with the first billing period (June through September, inclusive) after the District control equipment is installed on the customer s air conditioning equipment. The discount is per ton of controlled air conditioner capacity, as determined by the District. Under no circumstance shall the monthly commercial S.T.E.P. credit exceed the monthly electric usage charge. If electric service is terminated, the current available S.T.E.P credit will be issued on a prorated basis. June 1 to September 30: Discount per Account per Month Central Air Conditioning Cycling... $ 2.00 per ton of controlled A/C capacity 9.4 Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period. 9.5 Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District. 9.6 Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with more than two compressor units require the installation of District control equipment on two-thirds of total air conditioning capacity. If there are two compressor units, both must be under load control. 9.7 Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision Installation, Maintenance and Removal Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 10. Economic Development Discount Qualified customers locating or expanding in the District service territory which create new economic development and job opportunities in the community are eligible for a three-year rate discount Rate A three-year, five percent (5%) rate discount based on the energy, demand and fixed monthly charge portions of applicable Rate Schedule, excluding taxes. The discount will be determined prior to any credit for primary voltage discount. This discount will be given as an annual or monthly bill credit, at the option of the District Qualification Qualified customers are new customers with a minimum load requirement of 200 kilowatts, or existing customers who add a minimum 200 kilowatts of new load. For existing customers, only the additional new load will qualify for the discount and will be based on the customer s existing applicable Rate Schedule. Should the additional new load qualify the customer for another Rate Schedule under which this Provision is applicable, such Rate Schedule shall supersede the existing Schedule and shall become the basis from which the discount is calculated. When an existing facility has been out of operation or has experienced measurable reduction in electric power consumption, an increase in electrical use will only be considered net new load when the non-operation or measurable reduction has existed for at least one year. All new load shall be subject to verification and approval by the District. Qualifying new incremental loads that are seasonal in nature are eligible for the Economic Development Discount; however, the discounts shall apply only during the months during which the loads are in full operation. Qualified customers include those engaged in business classified under the North American Industrial Classification System (NAICS) codes through , inclusive, or any other customers Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-3, dated January 1, 2017April 1, 2013.

25 Electric Rate Schedule GS-3 General Service - Industrial Page 5 of 5 eligible for service under this Rate Schedule that at the District s sole discretion may be determined to qualify for this discount Contract Qualifying customers must enter into a five (5) year contract with the District. After three (3) years the customer will have the option to choose other contract rate options available, if qualifying requirements are met. The discount period shall commence within 12 months following the date of execution of the contract for service and shall be designated by the customer therein. Customer must receive 100% of electric usage from the District for the term of this Contract. Connection of non-district electric generation during the term of this contract will forfeit all Economic Development Discounts received during the term of this contract Metering 11. Electric Service Rules Separate electric metering for additional load may be required if, in the District s sole opinion, it is necessary to provide service under this Provision. The customer will be responsible for any costs associated with providing separate electric metering. Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule GS-3, dated January 1, 2017April 1, 2013.

26 Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 1 of 7 Applicability A) This Schedule is applicable to industrial customers having demands of 25,000 kilowatts or greater in the District s service territory in any month during the calendar year 2004, or in the case of a new customer estimated demands of 25,000 kw or greater in the District s service territory. B) Service provided hereunder shall not be sold for resale or exchange or shared with others. Service provided hereunder shall not be used in parallel with other sources of electric power, except service may be used in parallel with co-generation equipment that was in commercial operation at its present site prior to December 20, Customer may operate emergency standby generation equipment during outages of District electric service, during a District requested Interruptible Demand period as specified in Special Provision 10, and as reasonably necessary to test and maintain the emergency standby generation equipment. C) Prior to the provision of service hereunder, the customer shall be required to apply for IC Power Electric Service (hereinafter, Application for Service ) on the form prescribed in the General Terms and Conditions and Special Provisions which may be modified by the District from time to time. Character of Service Alternating current at a frequency of approximately 60 Hertz: 480Y/277 volts, 480 volts, 4,160 volts, 12,000 volts, 17,200 volts, 20,780 volts, 69,000 volts, or 115,000 volts three phase, where and to the extent available, at the option of the District. Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Annual & Monthly Rates The sum of the following customer, demand, and energy charges including applicable adjustments for power factor and Primary or Transmission Voltages which are effective on the date of meter reading for each account. (Such charges may be modified pursuant to Special Provisions 1, 12, and 13, see also Special Provisions 2 and 3.) Jan 1, 2012 Customer Charge per month $ Base Demand Charge per month: (for first 25,000 kw of Firm Contract Demand) $409,849 Firm Contract Demand Charge per kw per month: (Firm Contract Demand in excess of 25,000 kw and not more than 40,000 kw) $15.94 Excess Demand Charge per kw per month: (Demand in excess of Base and Firm Contract Demand) $16.70 Energy Charge Winter Billing Months October through April On Peak kwh, per kwh $ Off Peak kwh, per kwh $ Summer Billing Months May through September On Peak kwh, per kwh $ Partial Peak kwh, per kwh $ Off Peak kwh, per kwh $ Minimum Charge The minimum charge for each month or portion thereof shall be the sum of the Customer Charge, Base Demand Charge, Firm Contract Demand Charge, Excess Demand Charge, and Energy Charge. Determination of Demand Customer s Demand shall be the maximum 15-minute rate of taking in kilowatts measured by meter during the month or customer s Firm Contract Demand (including base demand) specified in the customer s Application for Service with the District, whichever is greater. Should the customer s equipment be such as may impose intermittent or violently fluctuating loads on the District s system, customer s demand for billing purposes may, at the sole option of the District, be based on a 5-minute interval. (See Special Provision 9.) Effective January 1, Cancels Schedule IC , dated January 1,

27 Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 2 of 7 A) Firm Contract Demand 1) Except as otherwise provided herein, the Firm Contract Demand applicable during each billing month shall be the maximum amount of Firm power in kilowatts (including base demand), that the customer shall have requested and the District shall have agreed to supply during such billing month; provided however, that if customer is currently receiving service under another District Industrial Contract Schedule, customer s Firm Contract Demand shall not be less than the Firm Contract Demand pursuant to such other District Industrial Contract Schedule. A customer may request a new Firm Contract Demand to be effective upon the completion of the original term of District Industrial Rate Schedule. 2) The customer may reduce its Firm Contract Demand by providing a written request for such reduction to the District at least one (1) year prior to the beginning of the first period to which the request applies; provided however, that (i) no such reduction shall become effective until customer has received service under another District Industrial Contract Schedule for at least 24 consecutive months and provided further that (ii) the maximum amount of reduction shall be as follows: a) For the first twelve (12) month period to which such notice applies, the maximum reduction shall be 25% of the Firm Contract Demand established pursuant to customer s Application. b) For the second twelve (12) month period to which such notice applies, the maximum reduction shall be 50% of the Firm Contract Demand established pursuant to customer s Application. Notwithstanding the foregoing, a customer s Firm Contract Demand under this IC Rate Schedule shall not be reduced to less than 25,000 kw. Notices of such reductions in the customer s Firm Contract Demand shall be irrevocable once given. 3) The customer s Firm Contract Demand, once established or reduced, may be increased only (i) pursuant to the terms of this Rate Schedule or (ii) by mutual agreement between the District and the customer evidenced by the execution by customer of a new, revised Application for Service and acceptance thereof by the District. B) Excess Demand The customer s Excess Demand for each billing month shall be the portion of the customer s measured Demand for such billing month, if any, that exceeds customer s Firm Contract Demand listed in the Application for Service between the customer and the District. Special Provisions 1. Provision Adjustments The District reserves the right, at any time, to adjust, either upward or downward, or eliminate rates, time periods, and discounts contained in Special Provisions 2, 3, 8, 10 and 11. Any adjustments to charges under this Special Provision shall be made only after a publicly noticed hearing before the District s Board of Directors. Any adjustments to charges made under this Special Provision shall not result in charges that exceed the District-allocated cost of providing service to customers in the IC Rate Schedule. 2. Adjustment for Power Factor For customers on this Rate Schedule, the maximum 15-minute reactive kilovolt-ampere demand requirements will be measured by means of installed instruments, or by periodic tests. The ratio of such reactive kilovolt-ampere demand requirements to the customer s kilowatt demand requirements at the time of the tests shall be used for computing the Power Factor Adjustment until a new test is made. In any month during which such customer s maximum 15-minute reactive kilovolt-ampere demand requirement is in excess of onehalf of the customer s maximum kilowatt demand requirement, an additional monthly charge of $1.43 will be made for each reactive kilovolt-ampere of such excess. 3. Delivery at Primary or Transmission Voltage When delivery is made at 4,160 volts, 12,000 volts, 17,200 volts or 20,700 volts a discount of 10% will be applied to the sum of the demand charges computed as described under Annual & Monthly Rates above including any adjustments to the demand charges pursuant to Special Provision 10. When delivery is made at 69,000 volts or above, a discount of 15% will be applied to the sum of the demand charge computed as described under Annual & Monthly Rates above including any adjustments to the demand charges pursuant to Special Provision 10. For totalized accounts the voltage discount is only applicable to meters being served at transmission or primary voltage. 4. Availability 5. Term Service under this Rate Schedule is available the first day of the first month following District s approval of customer s application but not prior to January 1, This contract between customer and District shall not terminate prior to December 31, Effective January 1, Cancels Schedule IC , dated January 1,

28 Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 3 of 7 6. Change in Rate Schedule This Industrial Contract Rate Schedule shall be effective upon its approval by the Board of Directors. Any customer whose application for this Rate Schedule is approved by the District shall begin receiving service under this Rate Schedule on the first day of the first full month after such approval but not prior to January 1, Application The customer shall complete an Application for Service, which shall identify the customer s Firm Contract Demand in accordance with conditions contained in this Schedule. The customer s application shall also specify the Interruptible Demand, if any, as referenced in Special Provision 10. The customer s application may also specify metering and communications equipment the customer will be required to install and/or maintain to implement the Interruptible Demand Provision. This Rate Schedule is available only upon execution of the customer s application, District verification of customer qualification, and acceptance by the District. Applications for service from customers receiving service under the IC Electric Rate Schedule must be submitted by the customer no later than 30 days after the effective date of this Rate Schedule. 8. Time Periods Time periods are defined as follows Winter: (Service from October 1 through April 30) On Peak: 8:00 a.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Summer: (Service from May 1 through September 30) On Peak: 1:00 p.m. to 9:00 p.m. Monday through Friday, excluding holidays. Partial Peak: 8:00 a.m. to 1:00 p.m. and 9:00 p.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Holidays are: New Year s Day, President s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. 9. Large Demands of Short Duration Where a customer requires new service or modification to existing services to supply x-ray equipment, welding equipment or other equipment, which presents large demands of short duration to the District s system, at the sole discretion of the District, such loads, may be served through a separate meter and transformer. It is the customer s responsibility to pay for, in advance, such equipment to supply modified service. Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 10. Interruptible Demand The potential interruption period is limited to Monday through Friday, 3:00 p.m. to 6:00 p.m. during the District s Summer Billing Months (May through September). By April 1 of each year, the District will determine how much interruptible load is required. Application for participation in the interruptible demand program will be taken up to the last working day in April of that calendar year. Applications will be accepted according to the following criteria: a) Priority will be given to loads that best fit District needs. b) Equivalent loads will be taken on a first-come, first-served basis until the target interruptible load is met. c) Past non-compliance in previous District interruptible programs may impact eligibility. After May 1 of that calendar year, if the interruptible target has not been met, the District will accept applications for participation in the interruptible program, up to the target, according to the criteria listed above. The Demand Reduction Credit (Special Provision 10.5 below) will be prorated Customer Eligibility To be eligible for the Interruptible Demand discount in any calendar year, a customer must sign up for the Interruptible Demand discount by the last working day in April of that calendar year Customer Interruptible Customer must reduce demand by the customer s designated kilowatt amount, Interruptible Demand, upon telephone notification by the District. A minimum of 2 hours notice will be provided to the customer prior to implementation of customer s required load reduction. Customer may, but is not required to, verify receipt of District s notice within 30 minutes of receiving such notice. District will provide, if possible, a non-binding notice to the customer by 12:00 noon the workday prior to any planned interruptions. District will have the right to a maximum of three (3) interruptions per month per account. Effective January 1, Cancels Schedule IC , dated January 1,

29 Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 4 of Interruptible Demand The customer shall state in its application the amount of Interruptible Demand, in kilowatts, subject to interruption pursuant to this Rate, provided that: a) the Interruptible Demand for July and August shall be equal, and shall be at least 100 kilowatts for each month; b) the Interruptible Demand for May, June and September shall be at least fifty percent (50%) of the Interruptible Demand for July and August, but not greater than the Interruptible Demand for July and August; c) The maximum Interruptible Demand in any month shall be no greater than 90% of the customer s total demand for that same month of the previous year. To allow new customers to be eligible for this Provision, the District will estimate the monthly demands for customers without prior billing history with the District until actual billing demand data become available Demand Reduction In the event the District, in its sole judgment, determines that it must reduce load, and the District notifies a customer of the requirement to reduce its demand, the customer must reduce its demand by the amount of customer designated Interruptible Demand calculated as follows: The Demand Reduction for any particular day shall be deemed the difference from customer s greatest recorded 15-minute peak demand during the 2-hour period immediately preceding the commencement of the interruption period to the greatest 15-minute demand recorded within the Interruptible Demand period Demand Reduction Credit In a month in which no request for Interruptible Demand Reduction has been made, customer shall receive a credit to their monthly demand charges of $3.62 per kilowatt per month of customer designated Interruptible Demand. In a month in which the District has requested Demand Reduction, customer shall receive a credit of $3.62 per kilowatt per month of actual Demand Reduction achieved as described in Section 10.4, not to exceed the customer designated Interruptible Demand amount. In months in which multiple requests for Demand Reduction are made, customer credit shall be based on the occurrence in which the least amount of actual Demand Reduction was achieved. For billing purposes, the Interruptible Demand shall be the same as the customer s demand, if customer s demand is less than the Interruptible Demand Non-Compliance Demand Charge A Non-Compliance Demand Charge will be imposed in the event that the customer fails to reduce its demand by the designated kilowatt amount during any 15-minute interval during an interruption period as required by the District pursuant to this Provision. The Non-Compliance Demand Charge will be based on the highest single Non-Compliance Demand incurred by the customer in the billing month for which the Non-Compliance Demand Charge is imposed. The Non-Compliance Demand Charge will be $3.62 per kilowatt multiplied by the number of kilowatts by which the customer failed to reduce its demand as described in Section 10.4, provided that the Non-Compliance Demand Charge shall not exceed $3.62 multiplied by the Interruptible Demand. Any customer failing to reduce its demand by the designated kilowatt amount on two or more occasions during any 12-month period will, at the District s option, become ineligible for this Provision and will not become eligible for the Provision for a period of 12 months Maintenance Outage Notice The customer shall have the right to waive all or part of its Interruptible Demand obligation for a maximum of one month per year. For the customer to waive all or part of its Interruptible Demand obligation in a month, written notice must be received by the District s Dispatching Supervisor at least five (5) working days prior to the month the customer wishes to waive all or part of its Interruptible obligation. This notice must specify the month a change is requested and the revised kilowatt amount of Interruptible Demand. Upon acceptance of the Maintenance Outage Notice, the customer will be obligated to reduce load, if called upon, by the revised amount specified in the notice. Customer Interruptible Demand Credit in that month will be based upon the revised Interruptible Demand as specified in the Maintenance Outage Notice. 11. Air Conditioning Controlled Load Service (S.T.E.P.) Service under this Schedule is provided to customers who have District-controlled electric central refrigerative air conditioning, which, in the opinion of the District, is suitable for controlled service Written Consent Service under this Schedule shall be provided only upon the written consent of the customer. If the customer is other than the landowner and the owner of the air conditioning equipment, the customer shall obtain the permission and authorization of the landowner and owner of the equipment to apply for and take service under this Rate Schedule, and to make the grants required hereunder to the District. Written consent to retain service under this Schedule shall be obtained from new customers and owners within thirty (30) days after such service is established at locations where control equipment is in place. Effective January 1, Cancels Schedule IC , dated January 1,

30 Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 5 of Control Period Air conditioning cycling control will be accomplished between the hours of 8:30 a.m. and 10:30 p.m. by interruption of controlled air conditioners for a period not to average more than 10 minutes nor exceed 12 minutes each half-hour. Air conditioners will not be interrupted on Sundays except as noted in Special Provision Rate Discount The following discount will commence with the first billing period (June through September, inclusive) after the District control equipment is installed on the customer s air conditioning equipment. The discount is per ton of controlled air conditioner capacity, as determined by the District. Under no circumstance shall the monthly commercial S.T.E.P. credit exceed the monthly energy charge. June 1 to September 30: Discount per Account per Month Central Air Conditioning Cycling... $ 2.00 per ton of controlled A/C capacity 11.4 Discount Billing Period The control discount for central air conditioning is in effect for four (4) consecutive summer billing periods beginning with the June billing period Suitable Equipment Controlled loads will be limited to permanently installed electric central refrigerative air conditioning equipment served from a branch circuit(s) exclusively devoted to such loads. Air conditioning equipment must have a compatible low voltage control circuit, control energy source, and accessible control equipment mounting location as determined by the District Multiple Central Air Conditioning Units Electric central refrigerative air conditioning systems equipped with more than two compressor units require the installation of District control equipment on two-thirds of total air conditioning capacity. If there are two compressor units, both must be under load control Emergency Control All controllable loads shall be subject to curtailment when, in the District s sole judgment, its generation and purchase capacity or energy resources, transmission capacity, or any combination of these is needed to meet the demands of its other customers and to prevent an otherwise avoidable outage. Emergency control under these circumstances may exceed the restrictions of Special Provision Installation, Maintenance and Removal Control mechanisms and associated equipment will be installed, tested, and maintained at the direction of the District at locations selected by the District and at no expense to the customer. Upon termination of this Schedule with respect to any customer, all wiring will be returned to normal operating conditions at the District s expense. 12. Power Supply Adjustment Notwithstanding anything to the contrary, the District reserves the right, at any time, to increase the energy and demand charges as stated in the annual monthly rates above as necessary to reflect increases in fuel or power supply costs. Any adjustments to charges made under this Special Provision shall not result in charges that exceed the District-allocated cost of providing service to customers in the IC Rate Schedule. 13. Environmental Adjustment Notwithstanding anything to the contrary, the District reserves the right, at any time, to increase the charges as stated in the annual monthly rates above as necessary to reflect new or increased costs resulting from legislative or regulatory mandates. Any adjustments to charges made under this Special Provision shall not result in charges that exceed the District-allocated cost of providing service to customers in the IC Rate Schedule. 14. Electric Service Rules Service under this Schedule is subject to the District s current Electric Service Rules. Effective January 1, Cancels Schedule IC , dated January 1,

31 Application for Service Electric Rate Schedule IC Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 6 of 7 1. (hereinafter Customer ), hereby requests the District to provide electric service to Customer, located at, For Account Number, under and in accordance with District s Electric Service Rules and Electric Rate Schedule IC , as such rules and schedule now exist or may hereafter be amended or superseded. A copy of IC is attached hereto and by this reference incorporated herein. 2. Customer s Firm Contract Demand shall be kilowatts (kw). 3. Optional: Customer may elect to utilize the Interruptible Demand Provision 10 as set forth in IC A separate Application for Interruptible Service shall be submitted for each year in which the Customer desires to participate in the District s Interruptible Demand discount program. 3.1 Customer shall comply with all terms and conditions set forth in IC , including the Special Provisions; and shall, upon notice, reduce its demand by the Interruptible Demand as required in IC Customer s Interruptible Demand shall be as follows: May (at least 50% of July, August) kw June (at least 50% of July, August) kw July (at least 100 kw and equal to August) kw August (at least 100 kw and equal to July) kw September (at least 50% of July, August) kw 3.3 Customer s contact for notice of interruptions under IC shall be the individual listed below. Such individual shall be available to receive notice at all times and any attempt to contact such individual at the telephone number listed shall be deemed actual notice to Customer: Name Telephone Alternate Telephone 4. Electric service under Rate Schedule IC shall be effective commencing on the first day of the first month following the District s verification and acceptance of Customer s compliance with Sections 3.3, 5.1, and 6 of this Application but not prior to January 1, District shall, at Customer s sole cost and expense, install and maintain automatic monitoring and metering equipment ( the equipment ) at Customer s location. Customer understands and acknowledges that the equipment shall be the property solely of the District, and that Customer shall have no right, title or interest therein. 5.1 At the time of submittal of this Application, Customer shall pay to the District Dollars ($ ) as an estimated, non-refundable charge for the equipment and installation of the equipment, including all costs of labor at the District s weighted labor rate. Upon completion of the installation, the actual costs will be determined by the District and Customer will receive a credit or additional billing for said costs. 5.2 Prior to the installation of the equipment, Customer shall take all necessary actions and precautions to ensure that the equipment is compatible with Customer s facilities. 5.3 Customer represents that it has the authority to, and hereby does, grant the District the right to install the equipment and to enter upon Customer s location at any reasonable time to install, inspect, operate, maintain, repair, replace, relocate or remove the equipment while IC is in effect. 5.4 Customer shall not at any time interfere or tamper with the equipment. Effective January 1, Cancels Schedule IC , dated January 1,

32 Application for Service (continued) Electric Rate Schedule IC Electric Rate Schedule IC Industrial Contract: MW Minimum Demand Page 7 of 7 6. Customer shall, at its sole cost and expense, provide, and at all times while IC is in effect maintain, a dedicated, unlisted telephone line, as specified by the District ( the communication service ), for the automatic monitoring and metering of Customer s electric usage. 6.1 District shall have the right to use the communication service as it, in its sole discretion, deems necessary to accomplish such purpose. 6.2 Customer shall pay any telephone company or other charges associated with or arising out of the District s use of the communication service. 7. Each party shall defend, indemnify and hold harmless, the other party (the Indemnified Party ), and its directors, officers, employees, representatives and agents, and each of them, from and against any and all liabilities, losses, damages, costs (including attorney fees and expenses) and/or claims resulting from the death or injury to any person, including employees of either party hereto, or damage to any property, including the property of either party hereto, resulting from the negligence of or breach of the obligations of the Indemnifying Party under IC or this Application. In no event, however, shall the Indemnifying Party be obligated to indemnify the Indemnified Party for any liabilities, losses, damages, costs and/or claims to the proportionate extent arising out of the negligence or act of the Indemnified Party. In each case above, the Indemnified Party will promptly notify the Indemnifying Party in writing of the claim, will not settle the claim on its own, and will reasonably cooperate (at the Indemnifying Party s expense) with the Indemnifying Party in the defense and any related settlement negotiations. 8. District is not a guarantor of power and, notwithstanding any Provision of IC , the District does not guarantee that interruptions may not occur during any period as a result of situations or circumstances beyond the control of the District. 9. Any assignment by Customer, voluntary or involuntary, of its rights under IC , or any rights or duties accrued hereunder, shall be void without the District s prior written consent. 10. This Application, together with applicable Electric Rate Schedule IC , constitutes the sole, only and entire agreement and understanding between the parties hereto as to the subject matter hereof, and no changes, alterations or modifications hereof or to any Provisions in Schedule IC or otherwise shall be effective unless in writing and signed by both parties. Date Approved by the District: Customer Modesto Irrigation District By By Name Name Title lastpage Title Effective January 1, Cancels Schedule IC , dated January 1,

33 Electric Rate Schedule SL Section 1 Public Street, Highway, & Park Lighting Service Page 1 of 4 Applicability This section of this Schedule is applicable to all night lighting on the public streets, alleys, highways and parks for cities, lighting districts or other public bodies. Public outdoor area lighting for other than all night lighting is supplied under Rate Schedule GS. Character of Service Alternating current at a frequency of approximately 60 Hertz, single phase, at voltages specified by the District, all night service approximately 4,150 hours per year, supplied from multiple or series circuits at the option of the District. Lamps will be supplied from an overhead source except as otherwise specified herein. Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Rates A) Metered Installation Fixed Monthly... $7.09 Per kilowatt-hour... $ B) District-Owned and Maintained Equipment (subject to Special Provisions 1 and 4) kwh Per Lamp Sodium Vapor Per Day Per Day 100 Watt $ Watt $ Watt $ Watt $ Watt $1.23 High Intensity Discharge Lamp 100 Watt $ Watt $0.89 C) Customer-Owned and Maintained Equipment served from either an underground or overhead source Effective January 1, 2015, this option C) will be closed to new or expanding lighting services. Unmetered street lighting will only be applicable to customers with a specified and verified number of street lights billed under this option C) prior to January 1, All customer-owned and maintained street lighting installed or upgraded after January 1, 2015, will be billed under option A) and will require the installation of a metered service. Unmetered multiple installation (subject to Special Provision 6) kwh Per Lamp Incandescent Per Day Per Day 300 Watt $ Watt $0.73 Mercury Vapor (subject to Special Provision 4) 175 Watt $ Watt $ Watt $0.66 1,000 Watt $1.57 Sodium Vapor (subject to Special Provision 4) 100 Watt $ Watt $ Watt $ Watt $ Watt $0.68 Minimum Charge The minimum charge for each billing period or portion thereof shall be the daily charge computed in accordance with the provisions given under Rates above. Effective January 1, 2019September 1, 2017, with specific periods to be determined by proration. Cancels Schedule SL, dated September 1, 2017January 1, 2016.

34 Electric Rate Schedule SL Section 1 Public Street, Highway, & Park Lighting Service Page 2 of 4 Term One year, and from year to year thereafter, until cancelled at the end of any one year term by either party upon ninety (90) days prior written notice to the other. Special Provisions 1. Standard Facilities Charges in Paragraph (B) under Rates are based upon the installation of street lighting fixtures of design specified by the District and mounted by means of brackets or mast arms up to eight (8) feet in length. 2. Service from Underground Facilities When fixtures are served from the District s underground distribution facilities, the customer shall install, own, and maintain its equipment to the District s nearest distribution terminal. 3. Lamp Ratings Ratings for various sizes of lamps in Paragraphs (B) and (C) under Rates are nominal ratings, approximate only, and do not necessarily indicate the lamp s power requirements. 4. Lamp Power Factor High intensity discharge lamp energy charges in Paragraph (B) under Rates shall apply only to luminaries with ballasts of 90% or above power factor. Energy charges shall be increased accordingly for lower factor luminaries. 5. Lamp Servicing: District-Owned and Maintained Equipment Upon failure of a lamp to operate as scheduled, the District will, within a reasonable period of time after notification or discovery, make the necessary repairs during normal working hours; however, no credit will be given for non-burning lamp time. 6. Metered Installations All series systems shall be metered. Metering shall be made ahead of customer s control and transformer equipment. The District reserves the right to require any lighting installation hereunder to be metered. 7. Charge for Lamp Sizes and Types not Listed If lamps are of sizes and types not listed in Paragraph (C) under Rates, the charge shall be based on the table below (wattage to include ballasts). Rate Tier Minimum Wattage Maximum Wattage kwh Per Day Per Lamp Per Day Rate Tier Minimum Wattage Maximum Wattage kwh Per Day Per Lamp Per Day SL1 Tier $0.04 SL1 Tier $0.40 SL1 Tier $0.07 SL1 Tier $0.44 SL1 Tier $0.11 SL1 Tier $0.47 SL1 Tier $0.15 SL1 Tier $0.51 SL1 Tier $0.18 SL1 Tier $0.55 SL1 Tier $0.22 SL1 Tier $0.58 SL1 Tier $0.26 SL1 Tier $0.62 SL1 Tier $0.29 SL1 Tier $0.66 SL1 Tier $0.33 SL1 Tier $0.69 SL1 Tier $0.36 SL1 Tier $ Relocation and Changes: District-Owned and Maintained Equipment The District will, at a customer s request, relocate District s existing equipment, provided the customer reimburses the District for the cost of necessary labor and materials, including engineering, supervision and general expenses. 9. Termination of Service Upon termination of service, the District shall have the right to remove all of its facilities placed, installed, erected or used in supplying service hereunder. 10. Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, 2019September 1, 2017, with specific periods to be determined by proration. Cancels Schedule SL, dated September 1, 2017January 1, 2016.

35 Electric Rate Schedule SL Section 2 Private Outdoor Area Lighting Service (Dusk to Dawn Lighting) Page 3 of 4 Applicability This section of this Schedule is applicable to all night outdoor area lighting service supplied from an existing, overhead, 120 volt source, where the lighting facilities are installed, owned, and maintained by the District. Character of Service Alternating current at a frequency of approximately 60 Hertz, 120 volts, single phase, with luminaire and bracket as specified by District and supported on District-owned wood poles. Lamps will be controlled to operate from dusk to dawn giving approximately 4,150 hours of lighting service annually. Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and Modesto Irrigation District Resolution Rates A) Lamp and Fixture on Existing Pole kwh Per Lamp Sodium Vapor Per Day Per Day 100 Watt $ Watt $0.73 Mercury Vapor Watt $ Watt $1.05 B) Lamp and Fixture With Pole kwh Per Lamp Sodium Vapor Per Day Per Day 100 Watt $ Watt $0.93 Mercury Vapor Watt $ Watt $1.25 C) Pole Rental Charge Per Pole Per Month 30 or 35 pole and secondary extension for lighting service... $6.16 Term A) Lamp and Fixture on Existing Pole Twelve (12) continuous months and thereafter until cancelled on 30 days prior written notice to the District. B) Lamp and Fixture with Pole Thirty-six (36) continuous months and thereafter until cancelled on 30 days prior written notice to the District. Service to lamps hereunder shall be continuous and temporary disconnection shall not be made. Special Provisions 1. Poles When suitable District-owned wood poles are available on an existing distribution circuit or on the customer s service lateral, lighting service will be supplied in accordance with rate (A), Lamp and Fixture on Existing PoleLamp and Fixture on Existing Pole. Where the District does not have an available and suitable existing pole; subject to voltage drop, span, and equipment access limitations; a pole may be installed, owned, and maintained by the District and lighting service will be supplied in accordance with rate (B), Lamp and Fixture With PoleLamp and Fixture With Pole. Where an additional pole(s) is required to provide a secondary extension for lighting service; subject to voltage drop, span and equipment access limitations; such pole(s) may be installed, owned, and 1 Mercury Vapor installations are no longer an available option and available only for existing service. Effective January 1, 2019September 1, 2017, with specific periods to be determined by proration. Cancels Schedule SL, dated September 1, 2017January 1, 2016.

36 Electric Rate Schedule SL Section 2 Private Outdoor Area Lighting Service (Dusk to Dawn Lighting) Page 4 of 4 maintained by the District in accordance with rate (C), Pole Rental ChargePole Rental Charge. Should the District utilize a lighting service pole for a purpose in addition to supporting the lamp unit and supplying electrical energy thereto, the pole rental charge shall terminate and lighting service will be supplied in accordance with rate (A), Lamp and Fixture on Existing PoleLamp and Fixture on Existing Pole. 2. Tenant Requesting Service When requested by a tenant to provide service under this section, District may require that the property owner(s) enter into agreement with the District concerning placement of lighting facilities before service is established. 3. Lamp Servicing 4. Billing Upon receipt of notice from a customer of the failure of a lamp to operate as scheduled, the District will within a reasonable period of time, make the necessary repairs during normal working hours. It shall be the customer s responsibility to make such notification. Billing shall coincide with that of the customer s primary premise account, where such account exists at the same location. No credit will be given for non-burning lamp time resulting from the failure of a fixture when repaired by the District in a reasonable period of time after notification. No billing shall be apportioned among two or more customers. At the customer s option, charges may be paid in advance. 5. Relocation The District will, at a customer s request, relocate its lighting facilities, provided that the customer reimburses the District for the cost of necessary labor and material including engineering, supervision and general expense required to complete such relocation. 6. Termination of Service Upon termination of service, the District shall have the right to remove all of its facilities placed, installed, erected or used in supplying service hereunder. If service is cancelled prior to the expiration of the initial 12- or 36-month period, the customer shall pay the District the calculated charges for the remaining portion of the period. 7. Mercury Vapor Lighting Mercury Vapor lighting service is not available for new installations. 8. Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, 2019September 1, 2017, with specific periods to be determined by proration. Cancels Schedule SL, dated September 1, 2017January 1, 2016.

37 Electric Rate Schedule P-3 Water Well Pumping and Agricultural Power Service Page 1 of 2 Applicability This Schedule is applicable to separately metered water well pumping, reclamation service, and farm use. Lighting and farm use will be provided to the extent permitted in Special Provision 2. This Schedule shall not apply to commercial food or agricultural processing operations, machine shops, or any other service not connected with the individual farm operation. Character of Service Alternating current at a frequency of approximately 60 Hertz: 120 volts, 120/208 volts or 120/240 volts, single phase or 240 volts, 240/120 volts, 208Y/120 volts, 480Y/277 volts, 480 volts, 4,160 volts, 12,000 volts, 17,200 volts three phase, where and to the extent available, at the option of the District. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the date of meter reading for each account. Summer (May September) Winter (October April) Fixed Monthly... $8.00 Fixed Monthly... $8.00 Fixed Horsepower (per HP): Fixed Horsepower (per HP): Less than 10 HP... $0.40 Less than 10 HP... $ HP & Over... $ HP & Over... $0.80 Electric Usage (per kwh): Electric Usage (per kwh): First 5,000 kwh... $ First 5,000 kwh... $ Over 5,000 kwh... $ Over 5,000 kwh... $ Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Connected Load The connected load used to determine the horsepower-based fixed charges shown under Monthly Charges shall be the total actual horsepower rating of all motors or other devices which are capable of being connected simultaneously to the District s system. In lieu of the connected load, the District may, at its option, measure by meter the maximum 15-minute demand in kilowatts. Such maximum demand divided by.746 shall then be used as the connected load in horsepower. Term (Three-Phase Service) Thirty-six (36) continuous months and thereafter until canceled on 30 days prior written notice to the District. Service to such facilities hereunder shall be continuous and temporary disconnection shall not be made. Upon termination of service, the District shall have the right to remove all of its facilities placed, installed, erected or used in supplying service hereunder. If service is canceled prior to the expiration of the initial 36-month period, the customer shall pay the District the monthly fixed charges for the remaining portion of the period. Special Provisions 1. Separate Metering Service under this Schedule will be supplied through a single meter and readings thereof will not be combined for billing purposes with those of any other meter through which other service may be taken by the customer. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule P-3, dated January 1,

38 Electric Rate Schedule P-3 Water Well Pumping and Agricultural Power Service Page 2 of 2 2. Incidental Loads Incidental lighting not to exceed 10% of the connected load will be permitted under this Schedule for water well pumping provided that the total connected load is 50 horsepower or more. Incidental lighting and power for general farm use is permitted under this Schedule for poultry house lighting and other agricultural uses. Residential uses such as cooking, water heating, lighting, heating, cooling or other uses are not allowed. All energy taken for such lighting or agricultural uses shall be taken through the power meter at the same voltage and shall be satisfactorily balanced between the phases. 3. Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule P-3, dated January 1,

39 Electric Rate Schedule P-4 Interruptible Water Pumping Power Service Page 1 of 2 Applicability This Schedule is applicable to electric service provided to governmental end-use customers that preschedule electricity deliveries with the District and have an average monthly water pumping demand of more than 1,000 kilowatts. Each eligible customer who chooses to take service under this Schedule is required to enter into a contract with the Modesto Irrigation District ( District ) prior to being served under this Schedule. The customer shall not sell, exchange or otherwise provide to any other person or entity electric energy obtained under this Rate. Character of Service Alternating current at a frequency of 60 Hertz, 230,000 volts, delivered at a point on the power grid owned or controlled by the District or to which the District has receipt or delivery capability. If necessary, power shall be scheduled for delivery by the District to another electric utility. Such utility shall maintain a 24-hour per day power dispatch center. No ancillary services are provided to the customer receiving service under this Rate Schedule. Territory Served The entire area within the Modesto Irrigation District electric service boundary or any other area within the zone known as NP15 and served by Modesto Irrigation District pursuant to the laws of the State of California and the District s Electric Service Rules. Monthly Charges The total amount of a customer s bill, excluding applicable local and state taxes and surcharges, will be the sum of the charges listed below and any adjustments for Special Provisions, effective on the billing date for each account (the Monthly Charges ). Summer (May September) Winter (October April) Fixed Monthly... $ Fixed Monthly... $ Demand (per kw)... $14.85 Demand (per kw)... $14.85 Electric Usage (per kwh): Electric Usage (per kwh): On Peak... $ On Peak... $ Partial Peak...$ Off Peak... $ Off Peak... $ Determination of Demand Customer s Demand shall be the maximum hourly rate of taking in kilowatts measured by actual deliveries during the month. Special Provisions 1. Electric Service Rules Service under this Schedule is subject to the District s Electric Service Rules as they may be amended from time to time. 2. Interruption a) Conditions for Interruption On a day when the District anticipates that interruption may be desirable, the District will contact the customer by telephone. If the customer agrees to the possibility of being interrupted on that day, then that day shall be an Interruptible Day. The District shall have the right, but not the obligation, to require the customer to interrupt load for the duration of an Interruption Period for any reason on an Interruptible Day. b) Notice of Interruption The District shall give the customer not less than 10 minutes notice before interruption is required. The District shall also notify the customer at the end of the Interruption Period. This condition does not limit service curtailments pursuant to statewide emergency plans. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule P-4, dated January 1,

40 Electric Rate Schedule P-4 Interruptible Water Pumping Power Service Page 2 of 2 c) Interruption Period An Interruption Period is the number of hours during which load is interrupted. The District shall notify the customer when the Interruption Period is complete. An Interruption Period shall be not less than four (4) hours. d) Statewide Emergency Curtailments 3. Delivery Limit Curtailments pursuant to statewide emergency plans are not Interruption Periods under this Rate Schedule. No Interruption Credit shall apply to statewide emergency curtailments. Power deliveries under this Rate Schedule shall not exceed eight (8) MW. 4. Scheduling Charge Late and/or revised schedules will be subject to a charge that is 50% of the Fixed Monthly Charge for each late and/or revised schedule submitted. 5. Time Periods Time periods are defined as follows Winter: (Service from October 1 through April 30) On Peak: 8:00 a.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Summer: (Service from May 1 through September 30) On Peak: 1:00 p.m. to 9:00 p.m. Monday through Friday, excluding holidays. Partial Peak: 8:00 a.m. to 1:00 p.m. and 9:00 p.m. to 11:00 p.m. Monday through Friday, excluding holidays. Off Peak: All other hours. Holidays are: New Year s Day, President s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. Effective January 1, , with specific periods to be determined by proration. Cancels Schedule P-4, dated January 1,

41 T AF R D Cost of Service Study Report November 19, 2018

42 TABLE OF CONTENTS EXECUTIVE SUMMARY... 1 A. Background... 1 B. Cost of Service and Rate Design Process Overview... 2 C. Revenue Requirements... 4 D. Cost of Service Results Compared to Current Revenue by Customer Class... 4 I. INTRODUCTION... 1 A. Background Generation and Power Supply Transmission and Distribution... 4 B. Cost of Service and Rate Design Process Overview... 4 II. REVENUE REQUIREMENTS... 6 A. Projected Energy Requirements... 7 B. Operations and Maintenance Expenses Power Production Transmission Distribution Customer Accounts Administrative & General C. Debt Service D. Non-Rate Revenue E. Total Revenue Requirements III. RATE REVENUE IV. COST OF SERVICE RESULTS A. Functionalization of Revenue Requirement Production Function Transmission Function Distribution Function Customer Service Function B. Classification of Revenue Requirement V. ALLOCATION OF REVENUE REQUIREMENT A. Class Allocation Factors Demand Allocations Energy Allocations... 19

43 3. Customer Allocations Direct Assignment Allocations B. Cost of Service Results C. Cost of Service Results Compared to Current Revenue D. Grandfathering Under Proposition VI. CONCLUSIONS LIST OF TABLES Table 1: MID Revenue Requirements for Electric Compared to Rate Revenues ($)... 4 Table 2: Cost of Service Compared to Rate Revenue by Customer Class ($)... 5 Table 3: Comparison of Under- or Over-Collection of Costs Under Current Rates Compared to Rates and Costs in 2010 (%)... 6 Table 4: MID's Power Supply Resources as of December 31, Table 5: Electric's Transmission and Distribution Facilities... 4 Table 6: Estimated Energy Requirements for MID... 7 Table 7: Total O&M for Electric Department for Test Year ($)... 8 Table 8: O&M Expenses for Power Production ($)... 9 Table 9: MID's Purchased Power Costs Table 10: Transmission O&M Expenditures ($) Table 11: Distribution O&M Expenses ($) Table 12: Customer Accounts O&M Expenditures ($) Table 13: Administrative & General Expenditures ($) Table 14: MID's Non-Rate Revenue for Electric ($) Table 15: MID s Revenue Requirements for Electric Table 16: Rate Revenue by Customer Class ($) Table 17: Functionalized Test Year Revenue Requirements ($) Table 18: Classification of MID's Electric Costs Table 19: Demand Allocation Factors Table 20: Energy Allocation Factors Table 21: Number of Customers by Schedule Table 22: Unbundled Revenue Requirements by Class ($) Table 23: Cost of Service Compared to Rates ($) Table 24: Comparison of Under- or Over-Collection of Costs Under Current Rates Compared to Rates and Costs in 2010 (%) LIST OF FIGURES Figure 1: Typical Cost of Service Process... 3 Figure 2: Typical Cost of Service Process... 6 November 19, 2018 ii MRW & Associates, LLC

44 EXECUTIVE SUMMARY In December 2017, Bartle Wells Associates (Bartle Wells) was retained by the Modesto Irrigation District (MID) to perform an Electric Cost of Service (COS) and Revenue Allocation Study (Study) as part of a broader study of the cost of service for all of MID s lines of business. Bartle Wells retained MRW & Associates, LLC (MRW) to assist with the Study. This report describes the analysis performed for the Electric line of service (Electric) and makes projections of the cost of service relative to the rate revenue recovered under current rates from the customers of Electric. 1 The report consists of six sections. Following this Executive Summary, Section 1 provides the introduction for the Study. Section 2 discusses the development of the revenue requirement for the Test Year. 2 Section 3 presents the rate revenue by customer class under present rates. Sections 4 and 5 discuss the estimated revenue requirement at various levels of aggregation (e.g., Electric, function, customer class). Section 6 presents conclusions. A. Background MID is a California irrigation district organized in 1887 under the provisions of the Irrigation District Law. MID has the powers under the Irrigation District Law to, among other things, provide irrigation and electric service. Under Irrigation District Law, MID has the powers of eminent domain, to contract, to construct works, to fix rates and charges for commodities or services furnished, to lease its properties and to incur indebtedness. MID is governed by a Board of Directors, the five members of which are elected from separate electoral divisions within its irrigation district boundaries for staggered four year terms. MID s operations are carried out under the direction of the General Manager who is in charge of MID s operations in accordance with the Board of Director s directives and policies. MID is located in the San Joaquin Valley in Central California, approximately 90 miles east of San Francisco, California. MID began providing electric service in 1923, and since 1940 has provided all electric service within its original 160 square mile service area, which includes the major portion of Stanislaus County. Beginning in 1996, MID has also provided electric service on a competitive basis in portions of the service area of Pacific Gas & Electric Company (PG&E). California Assembly Bill 2638 (AB 2638), effective on January 1, 2001, added the 7.5 square mile Mountain House Community Services District in western San Joaquin County to MID s exclusive electric service area and also designated a 400 square mile area in Southern San Joaquin County, Northern Stanislaus County and western Tuolumne County as MID s nonexclusive electric service area. Pursuant to AB 2638, other than as set forth therein, MID is further prohibited from providing electric transmission or distribution service to retail customers in the service territory of PG&E. For the year ended December 31, 2017, MID served over 1 MID s Fiscal Year (FY) runs from January 1 through December 31. All data contained in this report represents the MID FY unless otherwise stated. 2 The Test Year for the Study is November 19, 2018 ES-1 MRW & Associates, LLC

45 122,734 customers, had total retail sales of approximately billion kwh and a peak demand of 697 MW. To provide electric service within its service area, MID owns and operates an electric system that includes generation, transmission and distribution facilities. MID also purchases and sells power and transmission service and participates in pooling and other utility arrangements. MID also supplies water for irrigation use in a portion of Stanislaus County and owns and operates a water treatment plant which supplies treated domestic water on a wholesale basis to the City of Modesto. MID s irrigation system, as well as revenues from the sale of treated water, is operated and accounted for separately from Electric. Electric has no claim on the revenues of the irrigation or treated water systems. MID s last Electric Utility Rate Study was prepared in The MID Board approved a restructuring of electric rates in 2016 based in part on that study. B. Cost of Service and Rate Design Process Overview The COS and rate design process includes five steps as follows: 1. Determination of the Revenue Requirement This first step examines the utility s financial needs and determines the amount of revenue that must be generated from rates or non-rate revenue sources. The revenue requirement is determined on a cash basis. A cash basis analysis examines the cash obligations of the utility such as operations and maintenance (O&M) expenses, the Electric Utility s allocated portion of MID s administrative and general (A&G) expenses, debt service, and cash funded capital projects, and transfers to or from MID s reserves. 3 Discretionary Revenue is assigned at the discretion of the MID Board. Any Discretionary Revenue assigned to a customer class would have the effect of reducing that class s revenue requirement and, as a result, that class s Cost of Service. In preparing our analysis of the electric revenues from present rates and the development of the revenue requirement, the Project Team relied upon MID s historical audited data, the 2018 Budget, records of operation, customer billing data, and other detailed information and data compiled and provided by the MID s management and staff. 2. Functionalization and Sub-functionalization of Costs The revenue requirement is then assigned to the particular function or sub-function of the utility. Electric utilities like Electric typically have power supply, transmission, distribution, and customer services functions. Power Supply sub-functions may include utility-owned generation or shortand long-term purchased power from contracts or the wholesale power market. In MID s case, Electric incurs costs related to hydroelectric generation that is controlled by Irrigation, resulting in an inter-departmental transfer from Electric to Irrigation. Transmission and Distribution sub-functions may include distribution infrastructure by voltage, metering, billing, collection, etc. In MID s case, Electric uses right-of-way 3 At the present time, MID has a single set of reserves that are used for both Electric and Irrigation. November 19, 2018 ES-2 MRW & Associates, LLC

46 associated with Irrigation s canals for siting some of its transmission and distribution facilities, resulting in an inter-departmental transfer from Electric to Irrigation. Customer sub-functions include billing and collections, customer service, meter reading, etc. 3. Classification of Costs Once costs are functionalized, costs are then classified based on the underlying nature of the costs. Of particular importance is the determination of fixed versus variable costs. Fixed costs remain a financial obligation of the utility regardless of the amount of energy produced whereas variable costs fluctuate based on system energy requirements. Also, fixed and variable costs are associated with utility requirements to meet customer demand, energy, and customer service needs. 4. Allocation of Costs Once costs are classified, costs are then allocated to the various customer classes. Allocation factors align with cost classification. So, demand-related costs are allocated on measures of class demand such as class contribution to the system coincident peak (CP). Energy allocation factors are based on energy consumed by customers. Customer allocation factors are based on various allocators, such as the number of customers. These first four steps in the COS process are depicted in the figure below. Figure 1: Typical Cost of Service Process 5. Rate Design The fifth, and final, step is rate design, which translates COS results into rates for each customer class. The rate design establishes tariffs for each group of customers in order to fully recover all revenue requirements allocated to each customer group. Tariffs may include per-customer charges, demand charges, energy charges, or other charges. For this report, the Project Team did not propose revisions to MID s rate design. November 19, 2018 ES-3 MRW & Associates, LLC

47 C. Revenue Requirements The Project Team developed the Test Year Revenue Requirement for Electric based on the 2018 Budget with adjustments for unusual or one-time expenses or revenues. For this analysis, the Project Team used MID s COSA model after carefully reviewing the structure and assumptions in the model. The Project Team discussed any adjustments to expenses, revenues, model structure or assumptions with MID staff. After developing the costs of service for MID, the Project Team compared the expected rate revenue at present rates and non-rate revenues for the Test Year against the cost of service in the Test Year. MID staff provided rate revenue for the Test Year. Based on the costs and revenues for the Test Year, the Project Team compared costs and revenues to determine any under- or over-recovery of costs based on present rates. Table 1: MID Revenue Requirements for Electric Compared to Rate Revenues ($) Line Category Amount 1 O&M 290,106,182 2 Capital Expenses (1) 6,465,234 3 Debt Service & Debt Service Coverage (2) 94,613,189 4 Subtotal 391,184,604 5 Less Non-Rate Revenue -11,743,023 7 Less Discretionary Revenue -9,030,000 8 Revenue Requirement 370,411,582 9 Test Year Projected Rate Revenues 356,802, Over (Under) Recovery of Costs (13,609,202) 11 Over (Under) Recovery of Costs (3.8%) Please note the total amounts shown in the table may not sum due to rounding. Also note that this table does not include any transfers either to or from MID reserves. Notes: (1) Capital Expenses represent certain capital expenditures that are assumed to be paid out of current revenues. Other capital expenditures are assumed to be financed and are reflected in the Debt Service and Debt Service Coverage line item. (2) Debt Service & Debt Service Coverage reflect the annual total principal and interest paid on existing and new debt as well as an allowance for debt service coverage. As is seen from this table, MID s current rates under-recover MID s costs for Electric by $13,609,202 or 3.8%. Note that this table does not include any transfers either to or from MID reserves. D. Cost of Service Results Compared to Current Revenue by Customer Class The Project Team developed customer class-specific estimates of cost of service for the Test Year. To do this, the Project Team functionalized the revenue requirement into four functions (i.e., Production, Transmission, Distribution, and Customer Service), classified costs into three categories (i.e., Energy, Demand, and Customer), and then allocated those costs to each of November 19, 2018 ES-4 MRW & Associates, LLC

48 MID s customer classes. 4 These customer class-specific costs were then compared to rate revenue for each class. The following table presents these results. Table 2: Cost of Service Compared to Rate Revenue by Customer Class ($) Line Customer Class Schedule Cost of Service [a] Test Year Rate Revenues [b] Difference ($) [c] = [a]-[b] Difference (%) [d]=[c]/[b] 1 Residential Residential 164,434, ,733,609 8,701, % 2 Small GS-1 22,164,937 22,958,570 (793,634) -3.5% Commercial 3 M/L GS-2 73,878,168 76,301,128 (2,422,960) -3.2% Commercial 4 GS-TOU 4,501,940 4,867,789 (365,850) -7.5% 5 Industrial GS-3 60,917,991 56,993,098 3,924, % 6 IC-25 27,875,594 23,387,304 4,488, % 7 Agricultural P-3 12,448,157 12,445,627 2, % 8 P-4 2,194,078 2,131,909 62, % 9 Street Lights SL-1 1,292,278 1,281,709 10, % 10 SL-2 703, ,636 1, % 11 Total 370,411, ,802,380 13,609, % Table 2 shows that all customer classes except for tariffs serving Small and Medium/Large Commercial customers are paying less than their costs of service (i.e., Test Year rate revenues are less than Cost of Service). The levels of under- or over-collection for each customer class on a percentage basis are, on an absolute value basis, less than was found in late 2010, meaning that the current MID rates are closer to cost of service than what was found in The following table presents the level of under- or over-collection in late 2010 and under MID s current rates. As shown in Table 3 below, MID historically has over-recovered costs from rates paid by commercial customers taking service under Schedules GS-1, GS-2, and GS-TOU, and its policy to do so is pre-proposition 26 legislation that is grandfathered by the measure. Commercial customers will continue to pay above their cost of service, as permitted by pre-proposition 26 legislative choices which survive it. Moreover, because the proposed percentage of revenue allocation for those customers will decrease the extent to which commercial customers pay more than the cost of service (i.e., bringing them closer to service cost), they do not violate Proposition 26. Based on this, the Project Team believes that the rates currently in effect at MID are reasonable. 4 For this study, customer class is the same as rate schedule. November 19, 2018 ES-5 MRW & Associates, LLC

49 Table 3: Comparison of Under- or Over-Collection of Costs Under Current Rates Compared to Rates and Costs in 2010 (%) Line Customer Class Schedule Under/(Over) Collection of Costs in 2010 (%) Under/(Over) Collection of Costs Under Current Rates (%) 1 Residential Residential 5.6% 5.6% 2 Small Commercial GS-1-3.9% -3.5% 3 M/L Commercial GS-2-9.7% -3.2% 4 GS-TOU -8.4% -7.5% 5 Industrial GS-3 6.9% 6.9% 6 IC % 19.2% 7 Agricultural P-3 3.0% 0.02% 8 P-4 4.8% 2.9% 9 Street Lights SL-1 3.5% 0.8% 10 SL % 0.3% November 19, 2018 ES-6 MRW & Associates, LLC

50 I. INTRODUCTION In December 2017, Bartle Wells Associates (Bartle Wells) was retained by the Modesto Irrigation District (MID) to perform an Electric Cost of Service (COS) and Revenue Allocation Study (Study) as part of a broader study of the cost of service for all of MID s lines of business. Bartle Wells retained MRW & Associates, LLC (MRW) to assist with the Study. This report describes the analysis performed for the Electric line of service (Electric) and makes projections of the cost of service relative to the rate revenue recovered under current rates from the customers of Electric. 5 The report consists of six sections and an Executive Summary. Following the Executive Summary, this section provides the introduction for the Study. Section 2 discusses the development of the revenue requirement for the Test Year. 6 Section 3 presents the rate revenue by customer class under present rates. Sections 4 and 5 discuss the estimated revenue requirement at various levels of aggregation (e.g., Electric, function, customer class). Section 6 presents conclusions. Appendices are attached containing schedules and other information supporting the information contained in this report. Regular reviews of the performance of a utility s rates are an integral part of the management of any utility and failure to monitor the rates can result in the need for significant rate actions. The Project Team recommends that, going forward, MID continue to regularly monitor and review the performance of its adopted rates and perform rate adjustments in a timely manner to preserve the financial integrity of the Electric Utility. The analysis performed by the Project Team was designed to consider the foreseeable, known, and measurable adjustments during the Study Period. The goal was to provide MID management with information related to the degree to which costs at different levels of aggregation are being fully recovered by current rates. As with any forecast, assumptions were made and MID should note that the actual expenses and revenues may differ from the projected expenses and revenues outlined in this report due to unforeseen changes such as system growth, inflation, etc. A. Background MID is a California irrigation district organized in 1887 under the provisions of the Irrigation District Law. MID has the powers under the Irrigation District Law to, among other things, provide irrigation and electric service. Under Irrigation District Law, MID has the powers of eminent domain, to contract, to construct works, to fix rates and charges for commodities or services furnished, to lease its properties and to incur indebtedness. MID is governed by a Board of Directors, the five members of which are elected from separate electoral divisions within its irrigation district boundaries for staggered four year terms. MID s operations are carried out under the direction of the General Manager who is in charge of MID s operations in accordance with the Board of Director s directives and policies. 5 MID s Fiscal Year (FY) runs from January 1 through December 31. All data contained in this report represents the MID FY unless otherwise stated. 6 The Test Year for the Study is November 19, MRW & Associates, LLC

51 MID is located in the San Joaquin Valley in Central California, approximately 90 miles east of San Francisco, California. MID began providing electric service in 1923, and since 1940 has provided all electric service within its original 160 square mile service area, which includes the major portion of Stanislaus County. Beginning in 1996, MID has also provided electric service on a competitive basis in portions of the service area of Pacific Gas & Electric Company (PG&E). California Assembly Bill 2638 (AB 2638), effective on January 1, 2001, added the 7.5 square mile Mountain House Community Services District in western San Joaquin County to MID s exclusive electric service area and also designated a 400 square mile area in Southern San Joaquin County, Northern Stanislaus County and western Tuolumne County as MID s nonexclusive electric service area. Pursuant to AB 2638, other than as set forth therein, MID is further prohibited from providing electric transmission or distribution service to retail customers in the service territory of PG&E. For the year ended December 31, 2017, MID served over 122,734 customers, had total retail sales of approximately billion kwh and a peak demand of 697 MW. To provide electric service within its service area, MID owns and operates an electric system that includes generation, transmission and distribution facilities. MID also purchases and sells power and transmission service and participates in pooling and other utility arrangements. MID also supplies water for irrigation use in a portion of Stanislaus County and owns and operates a water treatment plant which supplies treated domestic water on a wholesale basis to the City of Modesto. MID s irrigation system, as well as revenues from the sale of treated water, is operated and accounted for separately from Electric. Electric has no claim on the revenues of the irrigation or treated water systems. MID s last Electric Utility Rate Study was prepared in The MID Board approved a restructuring of electric rates in 2016 based in part on that study. 1. Generation and Power Supply Electric provides power to its customers through a combination of MID-owned generation, purchase power contracts, and market purchases. The following table summarizes all of MID s power supply resources as of the end of November 19, MRW & Associates, LLC

52 Table 4: MID's Power Supply Resources as of December 31, 2017 Capacity Available (MW) Historical - Year Ending December 31, 2017 Actual Energy (GWh) Percent of Total Energy Source Generating Facilities: Don Pedro/Stone Drop (Hydro) % Woodland 1 (Combustion Turbine) Woodland 2 (Combustion and Steam Turbines) Woodland 3 (Reciprocating Engine) Ripon Generation Station McClure (Combustion Turbine, 2 units) Total (1) % Purchased Power: M-S-R PPA San Juan (2) % Lodi Energy Center (3) Renewables... Wind (4) New Hogan (5) Methane Digester McHenry Solar Project City and County of San Francisco (Hetch Hetchy) (6) Western Area Power Administration (WAPA) (6) Other Purchases (7) Total (1) , % Total Energy Resources (Generation + Load Reduction + Purchases) (9)... 1, , % Load: District System Requirement for Retail , % Wholesale Power Sales: (8) Other Sales % Total Capacity and Energy Sold at Wholesale % Total (Retail + Wholesale) (1)(9)... 1, , % (1) Totals may not add due to rounding. (2) M-S-R PPA ceased to have an ownership interest in the San Juan Unit No. 4 effective December 31, (3) MID s share of the output of the Lodi Energy Center is sold into the CAISO energy markets. Replacement energy is purchased for delivery to MID as needed. (4) Capacity shown is total contract capacity. Represents energy sold to MID at the project bus from the High Winds Project (50 MW), located in Solano County, California, and the Big Horn Project (25 MW) located in Klickitat County, Washington and also includes delivery of the output of the 98.7 MW from the Star Point Wind Project, located in Sherman County, Oregon and 32.5 MW of the Big Horn II Project. Actual capacity delivery at the project will be less than the total contract capacity. (5) Delivery of output for MID s benefit from the New Hogan Project commenced on June 1, 2010 and is scheduled similarly to the wind projects that are located within the CAISO. Although the plant has two generators with 3.0 MW of capacity, only 2.1 MW is shown because both units cannot operate at the same time (2.1 MW is the capacity of the larger unit). (6) WAPA and Hetch Hetchy Class 1 capacity are daily firm only. (7) Other Purchases include firm and non-firm short-term resources from various sources such as SMUD, BPA, PowerEx, and CAISO, among others. Also include reserves consistent with prudent utility practices. Direct load control (10 MW) and interruptible retail contracts (16.4 MW) count towards planning reserves. (8) Wholesale sales from the MID system are made on a short-term basis. This does not include sales made from Lodi Energy Center, San Juan, High Winds, Shiloh or New Hogan as output from those resources is sold directly to the CAISO energy markets. (9) Total capacity available includes planning reserves to meet MID load. It is important to note that not all contracts are available year-round. Source: MID November 19, MRW & Associates, LLC

53 MID must comply with California s Renewable Portfolio Standard (RPS) for load-serving entities. As of the beginning of September 2018, MID is required to serve 50% of its load using qualifying renewable resources by Transmission and Distribution The following table summarizes the extent of Electric s transmission and distribution facilities. Table 5: Electric's Transmission and Distribution Facilities Distribution Voltage (kv) Underground Overhead Total 4 kv kv kv , kv kv Total Distribution , , Transmission Voltage (kv) Underground Overhead Total 69 kv kv kv Total Transmission Source: MID Electric s transmission system consists of approximately 384 miles of facilities that are 69 kilovolts (kvs) or above. Electric s distribution system has both overhead and underground facilities totaling 1, miles. At the present time, MID s electric operations are a part of the overall operations of MID (i.e., the operations are not a separate business unit). 7 B. Cost of Service and Rate Design Process Overview The COS and rate design process includes five steps as follows: 1. Determination of the Revenue Requirement This first step examines the utility s financial needs and determines the amount of revenue that must be generated from rates or non-rate revenue sources. The revenue requirement is determined on a cash basis. A cash basis analysis examines the cash obligations of the utility such as operations and maintenance (O&M) expenses, the Electric Utility s allocated portion of MID s administrative and general (A&G) expenses, debt service, and cash funded capital projects, and transfers to or from MID s reserves. 8 7 For simplicity, this report will refer to MID s electric operations as Electric even though it is not a separate business unit. 8 At the present time, MID has a single set of reserves that are used for both Electric and Irrigation. November 19, MRW & Associates, LLC

54 Discretionary Revenue is assigned at the discretion of the MID Board. Any Discretionary Revenue assigned to a customer class would have the effect of reducing that class s revenue requirement and, as a result, that class s Cost of Service. 9 In preparing our analysis of the electric revenues from present rates and the development of the revenue requirement, the Project Team relied upon MID s historical audited data, the 2018 Budget, records of operation, customer billing data, and other detailed information and data compiled and provided by the MID s management and staff. 2. Functionalization and Sub-functionalization of Costs The revenue requirement is then assigned to the particular function or sub-function of the utility. Electric utilities like Electric typically have power supply, transmission, distribution, and customer services functions. Power Supply sub-functions may include utility-owned generation or shortand long-term purchased power from contracts or the wholesale power market. In MID s case, Electric incurs costs related to hydroelectric generation that is controlled by Irrigation, resulting in an inter-departmental transfer from Electric to Irrigation. Transmission and Distribution sub-functions may include distribution infrastructure by voltage, metering, billing, collection, etc. In MID s case, Electric uses right-of-way associated with Irrigation s canals for siting some of its transmission and distribution facilities, resulting in an inter-departmental transfer from Electric to Irrigation. Customer sub-functions include billing and collections, customer service, meter reading, etc. 3. Classification of Costs Once costs are functionalized, costs are then classified based on the underlying nature of the costs. Of particular importance is the determination of fixed versus variable costs. Fixed costs remain a financial obligation of the utility regardless of the amount of energy produced whereas variable costs fluctuate based on system energy requirements. Also, fixed and variable costs are associated with utility requirements to meet customer demand, energy, and customer service needs. 4. Allocation of Costs Once costs are classified, costs are then allocated to the various customer classes. Allocation factors align with cost classification. So, demand-related costs are allocated on measures of class demand such as class contribution to the system coincident peak (CP). Energy allocation factors are based on energy consumed by customers. Customer allocation factors are based on various allocators, such as the number of customers. These first four steps in the COS process are depicted in the figure below. 9 See Appendix 2 for more details about Discretionary Revenues. November 19, MRW & Associates, LLC

55 Figure 2: Typical Cost of Service Process II. 5. Rate Design The fifth, and final, step is rate design, which translates COS results into rates for each customer class. The rate design establishes tariffs for each group of customers in order to fully recover all revenue requirement allocated to each customer group. Tariffs may include per-customer charges, demand charges, energy charges, or other charges. For this report, the Project Team did not propose revisions to MID s rate design. REVENUE REQUIREMENTS Developing the Test Year Revenue Requirement is the first step in the COS and rate design process, as shown in Figure 2. The Test Year Revenue Requirement for Electric was based on the 2018 Budget with adjustments for unusual or one-time expenses or revenues. There are two primary revenue requirement methodologies employed in the utility industry; the cash basis and the utility basis. The primary differences between the cash basis and the utility basis involve the treatment of depreciation, return on invested capital, and debt service. The cash basis, which is the most common method used by municipalities and irrigation districts, includes debt service, but excludes depreciation and return on invested capital in the revenue requirement determination. The cash basis focuses on meeting the cash demands of the utility. The utility basis, which is most commonly used by private or for-profit utilities, includes depreciation and return on invested capital, but excludes debt service from the revenue requirement determination. In this COS analysis, the Project Team utilized the cash basis, as it follows the traditional cashoriented budgeting practices frequently used by government entities. In addition, the cash basis generally is easier to explain to customers since the cash basis attempts to match revenue and expenditures. November 19, MRW & Associates, LLC

56 A. Projected Energy Requirements The electric consumption by Electric s customers is a key driver in projections of expenses and revenues. The forecast of sales and electric load associated with customer demands was developed by MID. The following table presents assumed electric sales for the Test Year by customer class. 10 Table 6: Estimated Energy Requirements for MID Res. GS-1 GS-2 GS- TOU GS-3 IC-25 P-3 P-4 SL-1 SL-2 Total (MWh) Sales 868, ,003 5,501 31, , ,442 85,619 20,805 9,548 2,419 2,514,597 Losses 34,636 5, ,215 5,128 3, , ,199 Total 902, ,526 5,599 32, , ,570 89,227 20,898 10,698 2,513 2,601,796 (MW) Peak Losses Total Source: MID. Note: Totals may not add due to rounding. Total sales for the Test Year are 2,514,597 MWh. Energy supplied (which includes losses) is 2,601,796 MWh in the Test Year. Peak demand at the customer level is 664 MW in the Test Year. B. Operations and Maintenance Expenses The first step in developing the revenue requirement forecast for the Test Year was the development of Test Year O&M expenses. O&M expenses for the Test Year are based on MID s 2018 budget with adjustments as necessary. O&M expenses consist of costs from five broad categories: Power Production Transmission Distribution Customer Accounts Administrative and General (A&G) The following table summarizes the O&M costs for the Test Year. 10 Details regarding sales by customer class and rate schedule are found in Appendix 1. November 19, MRW & Associates, LLC

57 Table 7: Total O&M for Electric Department for Test Year ($) Power Transmission Distribution Customer A & G Total Production Accounts 205,892,704 8,781,221 15,829,819 13,702,338 45,900, ,106,182 Source: Appendix 1, Schedule 3 The following sections provide details for each of these five categories of costs. 1. Power Production MID s power production O&M expenses reflect the costs to operate and maintain MID s generating fleet, purchase fuel for its gas-fired generation, purchase power pursuant to short- and long-term power purchase agreements (PPAs), operate and dispatch MID s portfolio of power supply assets to meet MID s customer loads, and to compensate Irrigation for the net value of the energy and capacity that Electric receives from MID s hydroelectric generating facilities. Table 8 below presents the Power Production O&M expenses for the Test Year. MID s largest O&M expenses for Power Production are purchased power and fuel. Each of these categories are discussed in more detail below. Most of the O&M expenses in Table 8 are self-explanatory. However, the category Hydro Water Charge deserves additional discussion. The Don Pedro dam has a hydroelectric generating facility. Don Pedro generates electricity that is used by Electric to serve its customers. As a result, Electric is able to avoid either purchasing or generating the quantity of electricity and capacity provided by Don Pedro. Thus, Electric avoids the costs of purchasing both energy and capacity that it receives from Irrigation. At the same time, the responsibility for building, operating, and maintaining Don Pedro has historically been split between the Electric and Irrigation business lines. Electric is responsible for the relicensing of the hydroelectric facility at Don Pedro with the Federal Energy Regulatory Commission (FERC). The net cost that Electric avoids associated with Don Pedro is the difference between (1) the value of energy and capacity related to the hydroelectric generation provided to Electric from Don Pedro and (2) the costs that Electric bears related to the ownership of the hydroelectric generation at Don Pedro For additional details regarding the development of Electric s net cost associated with Don Pedro, see Appendix 2. November 19, MRW & Associates, LLC

58 Hydraulic Power Generation Other Power Generation FERC Account Table 8: O&M Expenses for Power Production ($) Description O&M Costs ($) 535 Oper. Supervision and Engineering 69, Hydraulic Expenses 11, Electric Expenses 69, Misc. Hydro Power Generation Exp. 253,971 Subtotal Operations 403, Maint. Supervision and Engineering 23, Maint. Of Res., Dams, and Waterways 368, Maintenance of Electric Plant 441, Maint. Of Misc. Hydro Power Plant 34,993 Subtotal Maintenance 868,508 Total Hydro Power Expense 1,271, Oper. Supervision and Engineering 8,629, Fuel 22,827, Generation Expenses 4,073,574 Subtotal Operations 35,530, Maint. Supervision and Engineering 180, Maintenance of Generating Units 2,376, Maint. Of Misc. Other Power Gener. P.t 2,107,671 Subtotal Maintenance 4,665,052 Total Other Power Production Expenses 40,195, Purchased Power 150,436, System Control and Load Dispatching 7,657, Hydro Water Charge 6,331,565 Total Other Power Supply Expense 164,425,121 Total Production Expense 205,892,704 Source: Appendix 1, Schedule 3 a) Purchased Power Expenses Purchased Power expenses are the largest portion of the Power Production O&M expenses, which are the largest of MID s O&M expenses for Electric. These costs are associated with take or pay contracts, purchased power agreements, and spot market purchases to balance MID s needs to meet load. Overall, MID s purchased power expenses for the Test Year are about $150.4 million. Table 9 below summarizes forecast expenses for Electric s purchased power for the Test Year. November 19, MRW & Associates, LLC

59 Table 9: MID's Purchased Power Costs Counterparty/Type Cost (MM$) Renewables Wind 55.2 Solar 10.3 Biomass 1.4 Small Hydro 0.2 Subtotal Renewables 67.1 Purchased Power Long Term 5.9 Short Term 43.3 Subtotal Purchased Power 49.2 Lodi Energy Center (Fuel + O&M) 2.9 M-S-R 17.9 TANC 11.6 Misc. Regulatory and Grid Charges 1.9 Total Source: MID Note: Components may not sum to total due to rounding b) Fuel Expenses Fuel expenses are the second-largest portion of MID s Power Production O&M expenses, which are the largest of MID s O&M expenses for Electric. These costs are associated with fuel acquired by MID to operate its own power plants and fuel that is delivered to power plants with which MID has tolling agreements. All of MID s fuel expenses for power production are related to purchases of natural gas. MID s fuel expenses for the Test Year are $22.8 million. 2. Transmission MID s transmission O&M expenses reflect the costs to operate and maintain MID s high voltage transmission system (i.e., 69 kv to 230 kv) in order to ensure safe and reliable service to MID s retail customers. The following table presents the Transmission O&M expenses for the Test Year. November 19, MRW & Associates, LLC

60 Operation Maintenance FERC Account Table 10: Transmission O&M Expenditures ($) Description O&M Costs ($) 560 Operation Supervision and Engineering 3,319, Station Expenses 2,556, Rents 414,699 Subtotal - Operations 6,290, Maintenance of Overhead Lines 2,490,374 Subtotal Maintenance 2,490,374 Total Transmission Expense 8,781,221 Source: Appendix 1, Schedule 3 MID s operations expenses are somewhat larger than its maintenance expenses for its transmission facilities. Most of the O&M expenses in Table 10 are self-explanatory. However, the category Rents deserves additional discussion. Irrigation has many miles of canals. These canals have land adjacent to them. In the past, MID has constructed transmission and distribution facilities on the rights-of-way of some of MID s canals. As a result, MID was able to avoid having to lease land to site some of its transmission and distribution facilities. Thus, Electric incurs a cost that is equal to the costs Electric avoids by using Irrigation s rights-of-way; this compensation is found in the Rents line item Distribution MID s distribution O&M expenses reflect the costs to operate and maintain MID s lower voltage distribution system (i.e., below 69 kv) in order to ensure safe and reliable service to MID s retail customers. The following table presents the Distribution O&M expenses for the Test Year. 12 For additional discussion of the derivation of this line item, please see Appendix 2. November 19, MRW & Associates, LLC

61 Operation Maintenance FERC Account Table 11: Distribution O&M Expenses ($) Description O&M Costs ($) 582 Station Expenses 3,411, Miscellaneous Distribution Expenses 26,500 Subtotal Operations 3,438, Maint. Supervision and Engineering 1,263, Maintenance of Overhead Lines 5,722, Maintenance of Underground Lines 1,748, Maintenance of Line Transformers 327, Maint. Of Street Lighting Equipment 93, Maintenance of Meters 3,236,735 Subtotal Maintenance 12,391,431 Total Distribution Expense 15,829,819 Source: Appendix 1, Schedule 3 MID s maintenance expenses are larger than its operations expenses for its distribution facilities 4. Customer Accounts MID s Customer Accounts O&M expenses reflect the costs to provide retail services to MID s customers. These include revenue-cycle services (e.g., meter reading, billing) as well as customer assistance. The following table presents the Customer Accounts O&M expenses for the Test Year. Table 12: Customer Accounts O&M Expenditures ($) FERC Account Description O&M Costs ($) Operation 901 Supervision 719, Customer Records and Collection 6,424, Uncollectable Accounts 2,300, Customer Assistance 4,258,182 Total Customer Accts. Expense 13,702,338 Source: Appendix 1, Schedule 3 MID s Customer Records and Collections are nearly half of MID s total Customer Accounts O&M expenses. 5. Administrative & General MID s A&G expenses reflect the costs to operate the MID enterprise in its entirety. These consist of two sets of costs: (1) certain costs that are directly assigned to Electric and (2) an November 19, MRW & Associates, LLC

62 allocated portion of the A&G costs that are not directly assigned to either Electric or Irrigation. 13 The following table presents the O&M expenses related to A&G for the Test Year. Table 13: Administrative & General Expenditures ($) FERC Description O&M Costs ($) Account 920 Administrative and General 41,001, Public Benefits 4,298, Franchise Requirements 600,000 Total A&G Expense 45,900,100 Source: Appendix 1, Schedule 3 Note: In Appendix 2, A&G Expenses in Table 5 only include FERC Account 920. FERC Account 921 and 927 are included in the O&M line item in Table 5 in Appendix 2. In addition to A&G expenses, Electric receives revenue that reimburses A&G expenses that MID bills to others (i.e., the City of Modesto). This revenue is included as a part of the non-rate revenue received by the Electric Department. This is discussed further below. C. Debt Service Debt service represents existing and projected debt service for Electric. The existing debt service within the Test Year Revenue Requirement includes the amortization schedules for MID debt as provided by MID. MID s debt service costs include a 10% adder to ensure debt service coverage is consistent with bond covenants. Finally, MID plans to accelerate payment of outstanding debt. MID has taken this step for the past several years. The accelerated repayment costs included in the COSA are $24.5 million for D. Non-Rate Revenue Electric receives non-rate revenue from various sources. The sources of non-rate revenue include customer service fees and certain interest income. 14 In addition, as previously discussed, Electric receives revenue that reimburses A&G expenses that MID bills to others. The following table summarizes the major categories of non-rate revenue. The revenue reimbursing the A&G expenses that MID bills to others is included under the category Other Operating Income. 13 For additional information regarding the allocation of A&G expenses that are not directly assigned to the Electric Department, see Appendix See Appendix 2 for further discussion of allocation of interest income to Electric. November 19, MRW & Associates, LLC

63 Other Operating Revenues Other Income Table 14: MID's Non-Rate Revenue for Electric ($) Category Amount Customer Service Fee Revenue 1,400,000 Total Other Operating Revenues 1,400,000 Other Operating Income 7,920,489 Interest Income 2,422,534 Total Other Income 10,343,023 Total Non-Rate Revenue 11,743,023 Source: Appendix 1, Schedule 2 E. Total Revenue Requirements Based on the various categories of expenses and non-rate revenue discussed above, the following summarizes the revenue requirements for MID s Electric Department for the Test Year. Table 15: MID s Revenue Requirements for Electric Line Category Amount 1 O&M 290,106,182 2 Capital Expenses 15 6,465,234 3 Debt Service & Debt Service Coverage 16 94,613,189 4 Subtotal 391,184,604 5 Less Non-Rate Revenue -11,743,023 7 Less Discretionary Revenue 17-9,030,000 8 Revenue Requirement 370,411,582 Source: Appendix 1, Schedule 1 Note that this table does not include any transfers either to or from MID reserves. III. RATE REVENUE MID last established its retail electric rates in Based on those rates and MID s billing determinants, estimates of total rate revenue as well as rate revenue by customer class were developed. The following table summarizes the forecasted rate revenue for the Test Year. 15 This line item is the capital expenditures that MID expenses and pays out of current revenues. Source: MID. 16 This line item equals the sum of Debt Service (principal plus interest), an allocation for defeasance of debt ($24.5 million), plus an allocation for meeting debt service coverage requirements. See Appendix 1 for more details about this line item. 17 Discretionary Revenues is derived from wholesale revenues and certain interest on reserves. The MID Board has discretion to allocate these revenues on the basis of Board policy. 18 The rate adjustment in 2016 only changed rates for residential customers and the rate change was revenue neutral to that class. November 19, MRW & Associates, LLC

64 Table 16: Rate Revenue by Customer Class ($) Line Customer Class Schedule Rate Revenue ($) 1 Residential Residential 155,733,609 2 Small Commercial GS-1 22,958,570 3 Medium/Large Commercial GS-2 76,301,128 4 GS-TOU 4,867,789 5 Industrial GS-3 56,993,098 6 IC-25 23,387,304 7 Agricultural P-3 12,445,627 8 P-4 2,131,909 9 Street Lighting SL-1 1,281, SL-2 701, Total 356,802,380 Source: Appendix 1, Schedule 1 Residential is MID s single largest customer class, with revenues of almost $156 million. GS-2 is MID s largest commercial customer class, with revenues of about $76.3 million. IV. COST OF SERVICE RESULTS Developing the Test Year Revenue Requirement is the first step in the Cost of Service Study, as shown in Figure 2. After determining the system revenue requirement, a COS for each customer class is developed to determine the specific costs to serve each class. Rate revenues for each Customer class revenues are compared to class revenue requirements to evaluate the current rate s abilities to fully recover costs. MRW reviewed MID s approach for determination of the cost to serve each customer class based on the revenue requirement developed in Section 3. Once completed, the COS results indicate the degree to which existing rates recover the costs to serve customers. A. Functionalization of Revenue Requirement The second step in the COS and rate design process, as shown in Figure 2, is to functionalize the revenue requirement. Electric s costs were unbundled into four functions: production, transmission, distribution, and customer service. The assignment of costs by function falls into two general categories: 1) direct assignments and 2) derived allocations. Direct assignments are costs that are readily associated with a specific utility function and are directly assigned to that function. For example, the purchase power contracts are an expense solely related to power supply, so it is directly assigned to that function. Derived allocators are allocation factors that are based on the sum, average, or weighted effect of different underlying factors. Derived allocators can be complex and should reflect the logical answer to the following question what underlying activities drive the cost of this item? Each of the four utility functions is described below. November 19, MRW & Associates, LLC

65 1. Production Function The power supply function consists of costs associated with power generation, the cost of purchased power, and procuring and administering power supply contracts. 2. Transmission Function The transmission function consists of costs associated with operating and maintaining the transmission portion of the high-voltage electric grid and making capital investments, as necessary. The transmission facilities transmit electricity from the generation stations to the distribution system. 3. Distribution Function The distribution function consists of costs associated with operating and maintaining the distribution portion of the electric grid and making capital investments, as necessary. The distribution facilities deliver power to the retail customers after it has been transmitted from the generation stations via the transmission grid. This includes low voltage distribution lines, distribution poles, underground lines, customer service connections, meters, and lighting-related assets. 4. Customer Service Function The customer service function consists of costs associated with operating and maintaining the customer related facilities to meet customer support needs. This includes, but is not limited to, customer service, billing and collection, and meter reading. The revenue requirement determined for the Test Year was unbundled into the four functional areas of the system: production, transmission, distribution, and customer. The results of the functional unbundling are summarized in the following table. These are also illustrated further in Appendix 2. Table 17: Functionalized Test Year Revenue Requirements ($) Line Function Amount ($) 1 Production 288,735,307 2 Transmission 15,266,846 3 Distribution 51,599,002 4 Customer Service 14,810,426 5 Total 370,411,582 Source: Appendix 1, Schedule COSA Model Functional and Classification The production function represents approximately 78% of the Test Year Revenue Requirement. The distribution function is the second largest cost center representing approximately 14% of the November 19, MRW & Associates, LLC

66 Test Year Revenue Requirement. The transmission function and the customer service function each represent 4% of the Test Year Revenue Requirement. 19 B. Classification of Revenue Requirement The third step in the COS and rate design process, as shown in Figure 2, is to classify the functionalized revenue requirement. System costs can be classified into four generally-accepted rate-making cost classifications: (1) demand or fixed costs; (2) energy or variable costs; (3) customer-related costs; and (4) directly assignable costs. In order to provide a reasonable basis for the assignment of total revenue requirements (costs) to each customer class, costs for each function have been analyzed and classified into four categories as described below. 1. Demand Costs Capacity (fixed- or demand-related) costs are those costs incurred to maintain a utility system to allow it to meet the total combined demands of its customers. Capacity costs include demand-related purchased power costs, the fixed portion of O&M expenses, debt service, capital expenditures, and other costs that are generally fixed and do not vary materially with the quantity of energy used or that cannot be designated specifically as a customer or variable cost. 2. Energy Costs Energy, or variable costs, are costs that vary directly with energy usage, including such items as fuel, energy-related purchased power, and a portion of O&M expenses. 3. Customer Costs Customer costs are those costs directly related to the number and type of customers, such as customer accounting, customer service, billing, and meter related expenses. 4. Direct Assignment Costs Direct assignment costs are those costs that are readily identifiable and applicable to a particular customer or customer class (e.g., Lighting). 20 The Project Team included Discretionary Revenues in the Direct Assignment category. Once the costs within each function are assigned to each service category, the demand, energy, customer, and direct assignment component of each service is calculated. 19 For this study, the Project Team assigned Discretionary Revenue to the Customer Service function. 20 MID s direct assignment costs are included in Customer Costs for the purposes of classification under service category. November 19, MRW & Associates, LLC

67 Table 18: Classification of MID's Electric Costs Line Function Demand Energy Customer Total 1 Production 104,282, ,452, ,735,307 2 Transmission 15,266,846 15,266,846 3 Distribution 51,599,002 51,599,002 4 Customer Service 14,810,426 14,810,426 5 Total 119,549, ,452,992 66,409, ,411,582 Source: Appendix 1, Schedule COSA Model Functional and Classification In total, 50% of the Electric Utility s total revenue requirement is energy-related or variable costs. The remaining 50% of the revenue requirement is fixed in nature and classified as demand and customer service. V. ALLOCATION OF REVENUE REQUIREMENT The fourth step in the COS and rate design process, as shown in Figure 2, is to allocate the functionalized, classified revenue requirement to the various customer classes. Customer classes represent aggregations of customers that have similar customer usage characteristics and use the system in a similar manner. These groups of customers have similar COS results, which justify similar rates. A. Class Allocation Factors Based upon actual and assumed customer service and consumption characteristics, the Project Team reviewed the various factors used by MID in its allocation of revenue requirement to individual customer classes. The Project Team examined those allocation factors to ensure that they were reasonable. Based on our review of MID s allocation factors, the Project Team has adopted demand related, energy-related, customer-related, and direct assignment allocation factors as described below. 1. Demand Allocations Demand allocators are derived based on the demand requirements of individual customers and classes of customers. Costs are allocated to classes based on the class contribution to various peak allocators. This is a measure of each class s cost responsibility associated with the infrastructure required to meet the system peak demand. As you move from the generator to the meter, the measure of peak demand responsibility changes from a system perspective (coincident peak), to a class perspective (non-coincident peak), to a customer perspective (demand at meter). Demand contributions at these various points in the system are determined based on information provided by MID. For customer class allocation purposes, the Peak Hours allocator (average capacity need during top 90% hours of system demand), 12-month coincident peak (12CP), and annual non-coincident peak (NCP) were used to allocate demand-related power supply and transmission related costs. November 19, MRW & Associates, LLC

68 The 12CP allocator was used to allocate winter and year-round baseload-related power supply costs. The Peak Hours allocator was used to allocate the peaking related power supply costs during summer months. Transmission costs for Electric were also allocated using the Peak Hours method for summer, which recognizes that the transmission system is constructed to deliver power at the times of the maximum system peak. Similarly, distribution infrastructure is designed to meet the maximum demands of the localized system or customers, so the NCP allocation factor was used for distribution costs at different voltage levels. An NCP allocator is typically used to allocate distribution costs, as these facilities are sized to meet localized peak demands rather than the system peak demand. The NCP method was used to allocate the distribution system demand-related costs associated with substations, poles, conductors, and distribution transformers. To account for variability in demands and loads between years, the load data for the last 5 years was used to determine the demand allocators. The following table presents the various demand allocators utilized in the Study. These represent the percentage of demand costs that are allocated to each rate schedule based on their load characteristics. The data behind these factors are illustrated further in Appendix 1. Table 19: Demand Allocation Factors Customer Class Schedule Peak Hours 12CP NCP Subtransmission NCP Primary NCP Secondary Residential Residential 51.9% 45.4% 49.4% 49.4% 59.3% Small GS-1 5.6% 5.5% 5.7% 5.7% 6.8% Commercial Med/Large GS % 19.9% 18.0% 18.0% 21.3% Commercial GS-TOU 1.0% 1.2% 0.9% 0.9% 0.2% Industrial GS % 16.4% 14.2% 14.2% 7.8% IC % 8.0% 8.0% 8.0% 0.0% Agricultural P-3 3.2% 2.7% 3.3% 3.3% 4.0% P-4 0.5% 0.6% 0.0% 0.0% 0.0% Street Lights SL-1 0.1% 0.2% 0.4% 0.4% 0.5% SL-2 0.0% 0.1% 0.1% 0.1% 0.1% Source: Derived from Appendix 1, Schedule COSA Model Allocation Factors 2. Energy Allocations Energy allocation factors are the basis for allocating costs or expenses classified as variable or energy related and are assumed to vary directly with kwh sales. Energy-related costs classified as variable were energy costs from fuel, purchased power, and costs related to system control and load dispatching. The energy necessary to supply each customer class 21 is used to allocate these types of costs to individual customer classes. The following table lists the energy allocation 21 This accounts for energy losses that occur on the transmission and distribution system when delivering energy to customers. November 19, MRW & Associates, LLC

69 factor utilized in the Study. The energy at input is the actual energy that has to be generated to account for the losses that will result over the transmission and distribution system. The load data behind these factors are illustrated further in Appendix 1. Customer Class Schedule Table 20: Energy Allocation Factors Summer Energy at Input Winter Energy at Input Annual Energy at Input Residential Residential 34.5% 34.9% 34.7% Small GS-1 5.3% 5.8% 5.6% Commercial Med/Large Commercial GS % 23.3% 22% GS-TOU 1.4% 1.6% 1.5% Industrial GS % 18.6% 20.3% IC % 11.8% 11.2% Agricultural P-3 4.1% 2.8% 3.4% P-4 0.9% 0.7% 0.8% Street Lights SL-1 0.4% 0.5% 0.4% SL-2 0.1% 0.1% 0.1% Source: Derived from Appendix 1, Schedule COSA Model Allocation Factors 3. Customer Allocations Customer costs are defined as those costs related to the number of customers and the type of service required. Included in the customer-related costs are the costs associated with meter reading, customer service, sales, billing, collection, and other customer-related activities. The customer allocation factors were largely based on the number of customers in each class. In allocating certain customer-related costs to the various customer classifications, weighted customer allocation factors were utilized. Weighting reflects that servicing certain types of customers requires more effort and expenses than other types of customers. Weighting factors were adopted from information provided by MID staff. Weighting factors reflect the relationships between the customer classes and the types of equipment or services needed to serve the class and the relative costs of those items. For example, large customers may have more than one meter per customer while residential customers usually have one meter per customer. Thus, the weighting factor for meters is 1 for residential customers, while it is a higher number for commercial customers. The number of customer accounts in each class are shown in the table below. Further details can be found in Appendix 1. November 19, MRW & Associates, LLC

70 Functionalized by Class Table 21: Number of Customers by Schedule Customer Class Schedule Customers Residential Residential 95,835 Small Commercial GS-1 10,388 Med/Large Commercial GS-2 2,251 GS-TOU 19 Industrial GS-3 43 IC-25 1 Agricultural P-3 1,725 P-4 1 Street Lights SL SL-2 3,746 Source: Appendix 1, Schedule COSA Model Allocation Factors 4. Direct Assignment Allocations Certain costs are not allocated to customer classes using the revenue allocators. Instead, those costs are directly assigned to the customer class that is responsible for them. An example of a directly-assigned cost would be O&M costs related to maintenance of streetlight equipment. MID s direct assignment allocations are included in the Customer Cost classification. As discussed elsewhere, the Project Team assigned Discretionary Revenues (e.g., wholesale revenues, certain interest income) to specific customer classes. B. Cost of Service Results The unbundled COS results by customer class is shown in the following table. Res GS-1 GS-2 GS- TOU Table 22: Unbundled Revenue Requirements by Class ($) GS-3 IC-25 P-3 P-4 SL-1 SL-2 Total Production 114,666,239 16,214,469 60,758,333 3,908,541 52,625,628 27,859,168 9,440,513 2,103, , , ,735,307 Transmission 7,412, ,284 2,973, ,527 2,223,746 1,048, ,005 90,064 26,339 6,823 15,266,846 Distribution 26,206,599 3,021,295 9,513, ,331 6,855,472 3,550,086 1,766, ,823 48,670 51,599,002 Customer 16,150,043 2,063, ,722 8,541 (786,854) (4,582,638) 791, , ,917 14,810,426 Total COS 164,434,962 22,164,937 73,878,168 4,501,940 60,917,991 27,875,594 12,069,345 2,411,569 1,185, , ,411,582 Classified by Class Energy 63,998,526 10,302,344 40,448,819 2,751,314 37,458,545 20,707,922 6,363,502 1,489, , , ,452,992 Demand 58,079,794 6,777,409 23,283,512 1,326,754 17,390,829 8,200,223 3,527, , ,520 53, ,549,161 Customer 42,356,642 5,085,184 10,145, ,871 6,068,618 (1,032,552) 2,557, , ,587 66,409,428 Total COS 164,434,962 22,164,937 73,878,168 4,501,940 60,917,991 27,875,594 12,448,157 2,194,078 1,292, , ,411,582 Source: Appendix 1, Schedule COSA Model Functional and Classification As can be seen from the above table, the residential rate class is MID s biggest rate class, followed by GS-2, which is a medium/large commercial class, and GS-3 which is an industrial class. MID s production function is by far the costliest function, while costs are slightly more evenly distributed when classified between demand, energy and customer costs, as the distribution costs are included in the Customer costs classification. November 19, MRW & Associates, LLC

71 C. Cost of Service Results Compared to Current Revenue Estimated operating costs were developed by the Project Team to compare the revenue generated under current rates to the current operating costs of Electric. The following table summarizes the variance between the Test Year Revenue Requirement and the annual revenue generated from current rates, by customer class. The result of comparing the projected revenues to the customer class revenue requirements indicate the degree to which existing rates recover revenues from each customer class on a COS basis. Table 23: Cost of Service Compared to Rates ($) Line Customer Class Schedule Cost of Service [a] Test Year Rate Revenues [b] Difference ($) [c] = [a]-[b] Difference (%) [d]=[c]/[b] 1 Residential Residential 164,434, ,733,609 8,701, % 2 Small GS-1 22,164,937 22,958,570 (793,634) -3.5% Commercial 3 M/L GS-2 73,878,168 76,301,128 (2,422,960) -3.2% Commercial 4 GS-TOU 4,501,940 4,867,789 (365,850) -7.5% 5 Industrial GS-3 60,917,991 56,993,098 3,924, % 6 IC-25 27,875,594 23,387,304 4,488, % 7 Agricultural P-3 12,448,157 12,445,627 2, % 8 P-4 2,194,078 2,131,909 62, % 9 Street Lights SL-1 1,292,278 1,281,709 10, % 10 SL-2 703, ,636 1, % 11 Total 370,411, ,802,380 13,609, % Source: Appendix 1, Schedule 1 As shown in Table 23, overall COS analysis forecasts that current costs are $370,411,582 and the current rate revenue is $356,802,380. Table 23 shows that all customer classes except for tariffs serving Small and Medium/Large Commercial customers are paying less than their costs of service (i.e., Test Year rate revenues are less than Cost of Service). For example, Residential s Cost of Service is $164,434,962 but its Rate Revenues under current rates are only $155,733,609, meaning that Residential s Cost of Service is 5.6% greater than its rate revenue. The levels of under- or over-collection for each customer class on a percentage basis are, on an absolute value basis, less than was found in late 2010, meaning that the current MID rates are closer to cost of service than what was found in The following table presents the level of under- or over-collection in late 2010 and under MID s current rates. November 19, MRW & Associates, LLC

72 Table 24: Comparison of Under- or Over-Collection of Costs Under Current Rates Compared to Rates and Costs in 2010 (%) Line Customer Class Schedule Under/(Over) Collection of Costs in 2010 (%) Under/(Over) Collection of Costs Under Current Rates (%) 1 Residential Residential 5.6% 5.6% 2 Small Commercial GS-1-3.9% -3.5% 3 M/L Commercial GS-2-9.7% -3.2% 4 GS-TOU -8.4% -7.5% 5 Industrial GS-3 6.9% 6.9% 6 IC % 19.2% 7 Agricultural P-3 3.0% 0.02% 8 P-4 4.8% 2.9% 9 Street Lights SL-1 3.5% 0.8% 10 SL % 0.3% Source: MID and Appendix 1, Schedule 1 D. Grandfathering Under Proposition 26 As shown in Table 24 above, MID historically has over-recovered costs from rates paid by commercial customers taking service under Schedules GS-1, GS-2, and GS-TOU, and its policy to do so is pre-proposition 26 legislation that is grandfathered by the measure. Commercial customers will continue to pay above their cost of service, as permitted by pre-proposition 26 legislative choices which survive it. Moreover, because the proposed percentage of revenue allocation for those customers will decrease the extent to which commercial customers pay more than the cost of service (i.e., bringing them closer to service cost), they do not violate Proposition 26. Based on this, the Project Team believes that the rates currently in effect at MID are reasonable. VI. CONCLUSIONS The Project Team concludes: The rates currently in force at MID are reasonable given the cost of service for MID. The rate revenue collected by Electric is less than MID s cost of service for Electric. Any under- or over-collection of cost of service by Electric pursuant to the rates currently in effect are similar or less than the level of under- or over-collection of cost of service by Electric as was found in early 2011 (based on a Cost of Service Analysis prior to the enactment of Proposition 26), meaning that the MID rates that are currently in force are reasonable based on the grandfathering of the levels of under- or over-collection found in early November 19, MRW & Associates, LLC

73 APPENDIX 1 SUPPORTING TABLES November 19, 2018 MRW & Associates, LLC

74 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P-4 Schedule 1: Summary of Results A. REVENUE REQUIREMENT CALCULATION (CASH BASIS) Operating Expenses: 1 Operation & Maintenance Expenses 91 Schedule 3 290,106, ,597,891 16,709,984 57,911,467 3,709,300 50,237,912 26,869,993 1,018, ,431 9,487,562 1,937,342 2 Public Purpose/DSM Programs 3 Annual Energy Sale Total Operating Expenses - 290,106, ,597,891 16,709,984 57,911,467 3,709,300 50,237,912 26,869,993 1,018, ,431 9,487,562 1,937, Operating Margin: 7 Capital Improvements 52 Rate Base 6,465,234 3,405, ,673 1,138,010 56, , ,420 19,522 5, ,953 18,293 8 Principal Portion of Debt Service 52 Rate Base 57,895,000 30,493,472 3,507,357 10,190, ,755 7,344,168 3,576, ,815 49,161 1,889, ,814 9 Debt Service 52 Rate Base 29,480,626 15,527,535 1,785,976 5,189, ,535 3,739,713 1,821,303 89,017 25, ,920 83, Debt Service Coverage 52 Rate Base 7,237,563 3,812, ,461 1,273,956 63, , ,134 21,854 6, ,154 20, Total Operating Margin - 101,078,422 53,238,312 6,123,466 17,791, ,993 12,822,125 6,244, ,208 85,829 3,298, , Total Required Revenues - 391,184, ,836,203 22,833,450 75,703,288 4,592,293 63,060,037 33,114,582 1,323, ,261 12,785,638 2,223, Less: Other Operating Revenues 90 Schedule 2 (1,400,000) (1,353,539) (41,919) (4,542) Less: Other Income 90 Schedule 2 (19,373,023) (9,047,701) (626,594) (1,820,579) (90,354) (2,142,046) (5,238,988) (31,231) (8,783) (337,481) (29,266) Required Revenues From Sales - 370,411, ,434,962 22,164,937 73,878,168 4,501,940 60,917,991 27,875,594 1,292, ,478 12,448,157 2,194, Revenues at Existing Rates 90 Schedule 2 356,802, ,733,609 22,958,570 76,301,128 4,867,789 56,993,098 23,387,304 1,281, ,636 12,445,627 2,131, Increase (Decrease) Required - $ - 13,609,202 8,701,353 (793,634) (2,422,960) (365,850) 3,924,893 4,488,289 10,569 1,842 2,530 62, % 3.8% 5.6% -3.5% -3.2% -7.5% 6.9% 19.2% 0.8% 0.3% 0.0% 2.9% B. BILLING UNITS Energy (MWh): energy sales 30 Annual 2,590, , , ,212 38, , ,344 10,655 2,503 88,828 20, Demand (kw): billing demands 35 Annual - - 1,100, Summer , Winter , Customers (#) average # customers 114,210 95,835 10,388 2, ,746 1, C. UNIT COSTS Customer Cost: Customer Cost ($) $ 66,409,428 $ 42,356,642 $ 5,085,184 $ 10,145,837 $ 423,871 $ 6,068,618 $ (1,032,552) $ 331,407 $ 472,587 $ 2,557,639 $ Unit Cost $/customer/month $48.46 $36.83 $40.79 $ $1, $11, ($86,046.01) $ $10.51 $ $ Energy Cost: Energy Cost ($) $ 184,452,992 $ 63,998,526 $ 10,302,344 $ 40,448,819 $ 2,751,314 $ 37,458,545 $ 20,707,922 $ 755,351 $ 177,653 $ 6,363,502 $ 1,489, Unit Cost cents/kwh Demand Cost: Demand Cost ($) $ 119,549,161 $ 58,079,794 $ 6,777,409 $ 23,283,512 $ 1,326,754 $ 17,390,829 $ 8,200,223 $ 205,520 $ 53,238 $ 3,527,016 $ 704, Unit Cost $/kw/month $ Unit Cost cents/kwh Total (Customer/Energy/Demand): Total Cost ($) $ 370,411,582 $ 164,434,962 $ 22,164,937 $ 73,878,168 $ 4,501,940 $ 60,917,991 $ 27,875,594 $ 1,292,278 $ 703,478 $ 12,448,157 $ 2,194, Unit Cost cents/kwh COSA clean.xlsx 11/6/18 5:14 PM Page 1 of 1

75 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P-4 68 Schedule 2: Operating Revenues Residential Sales 155,733, ,733, Commercial and Industrial Sales: 75 GS-1 22,958,570 22,958, GS-2 < 500 kw 76,301,128 76,301, GS-2 > 500 kw - 79 GS-TOU 4,867,789 4,867, GS-3 56,993,098 56,993, IC-10 23,387,304 23,387, Street Lighting Sales: 88 SL-1 1,281,709 1,281, SL-2 701, , Municipal and Pumping (P-3) Sales 12,445,627 12,445, P-4 Sales 2,131,909 2,131, Total Electric Sales Revenues 356,802, ,733,609 22,958,570 76,301,128 4,867,789 56,993,098 23,387,304 1,281, ,636 12,445,627 2,131, Customer Service Fee Revenue 37 Uncollectible Accou 1,400,000 1,353,539 41,919 4, Miscellaneous Service Revenues - 98 Sales of Water and Water Power - 99 Rent from Electric Property Other Electric Revenues Total Other Operating Revenues - 1,400,000 1,353,539 41,919 4, Other Operating Income 52 Rate Base 7,920,489 4,171, ,834 1,394,164 69,191 1,004, ,325 23,916 6, ,437 22, Revenues from Nonutility Operations Expenses of Nonutility Operations Interest Income 52 Rate Base 2,422,534 1,275, , ,414 21, , ,663 7,315 2,057 79,045 6, Sales of Economy Energy 44 Discretionary Revs 9,030,000 3,600, ,000 4,600, Total Other Income - 19,373,023 9,047, ,594 1,820,579 90,354 2,142,046 5,238,988 31,231 8, ,481 29, TOTAL REVENUES AND INCOME - 377,575, ,134,850 23,627,084 78,126,248 4,958,143 59,135,144 28,626,292 1,312, ,419 12,783,108 2,161, COSA clean.xlsx 11/6/18 5:16 PM Page 1 of 1

76 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Schedule 3: O&M Expenses POWER PRODUCTION EXPENSES: Hydraulic Power Generation: Oper. Supervision and Engineering 120 Summer 11 Peak Hours - Peak P 27,600 14,695 1,621 5, ,262 1, Winter CP - Baseload P 41,400 18,805 2,290 8, ,789 3, , Hydraulic Expenses 123 Summer 11 Peak Hours - Peak P 4,600 2, Winter CP - Baseload P 6,900 3, , , Electric Expenses 126 Summer 11 Peak Hours - Peak P 27,600 14,695 1,621 5, ,262 1, Winter CP - Baseload P 41,400 18,805 2,290 8, ,789 3, , Misc. Hydro Power Generation Exp. 129 Summer 11 Peak Hours - Peak P 101,588 54,088 5,966 19,196 1,035 12,006 5, , Winter CP - Baseload P 152,382 69,215 8,428 30,278 1,786 24,987 12, , Subtotal - Operation - 403, ,886 22,868 78,597 4,480 58,769 27, ,893 2, Maint. Supervision and Engineering 135 Summer 11 Peak Hours - Peak P 9,554 5, , , Winter CP - Baseload P 14,330 6, , ,350 1, Maint. Of Res., Dams, and Waterways 138 Summer 11 Peak Hours - Peak P 147,200 78,373 8,645 27,814 1,499 17,396 7, , Winter CP - Baseload P 220, ,291 12,213 43,873 2,587 36,206 17, ,936 1, Maintenance of Electric Plant 141 Summer 11 Peak Hours - Peak P 176,652 94,055 10,374 33,379 1,799 20,877 9, , Winter CP - Baseload P 264, ,358 14,656 52,651 3,105 43,450 21, ,124 1, Maint. of Misc. Hydro Power Plant 144 Summer 11 Peak Hours - Peak P 13,997 7, , , Winter CP - Baseload P 20,996 9,537 1,161 4, ,443 1, Subtotal - Maintenance - 868, ,662 49, ,186 9, ,505 59,675 1, ,600 5, Total Hydro Power Expense - 1,271, ,548 72, ,783 14, ,274 87,397 2, ,493 7, Other Power Generation: Oper. Supervision and Engineering 60 Other Power Operati 8,629,732 3,184, ,525 1,859, ,568 1,671, ,616 32,073 7, ,826 66, Fuel 155 Summer 5 Summer Energy at I 11,217,366 3,865, ,219 2,305, ,107 2,480,827 1,189,589 39,490 9, , , Winter 6 Winter Energy at In 11,609,881 4,054, ,887 2,701, ,419 2,154,078 1,373,435 54,016 12, ,917 78, Generation Expenses 158 Summer 11 Peak Hours - Peak P 2,001,764 1,065, , ,244 20, , ,485 1, ,786 10, Winter CP - Baseload Prod 2,071, , , ,665 24, , ,851 4,808 1,245 55,699 12, Subtotal - Operation - 35,530,553 13,111,808 1,990,782 7,655, ,758 6,882,950 3,740, ,053 31,259 1,201, , Maint. Supervision and Engineering 61 Other Power Maint. 180,646 87,704 10,239 35,190 2,006 26,313 12, ,325 1, Maintenance of Generating Units 170 Summer 11 Peak Hours - Peak Prod 950, ,176 55, ,639 9, ,355 49, ,718 5, Winter CP - Baseload Prod 1,426, ,733 78, ,352 16, , ,157 3, ,338 8, Maint. of Misc. Other Power Gener. Plt 173 Summer 11 Peak Hours - Peak Prod 843, ,873 49, ,302 8,586 99,636 43, ,128 4, Winter CP - Baseload Prod 1,264, ,405 69, ,274 14, , ,233 2, ,998 7, Subtotal - Maintenance - 4,665,052 2,264, , ,757 51, , ,534 8,048 2, ,507 27, COSA clean.xlsx 11/6/18 5:17 PM Page 1 of 4

77 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Total Other Power Production Expense - 40,195,604 15,376,699 2,255,184 8,564, ,560 7,562,455 4,061, ,101 33,344 1,339, , Other Power Supply Expenses: Purchased Power: 183 Demand 184 Summer 11 Peak Hours - Peak P 21,952,316 11,688,022 1,289,182 4,148, ,576 2,594,379 1,134,865 18,273 4, , , Winter CP - Baseload P 32,928,474 14,956,701 1,821,316 6,542, ,836 5,399,474 2,635,969 76,410 19, , , Energy 187 Summer 5 Summer Energy at I 47,891,203 16,504,261 2,545,484 9,842, ,289 10,591,596 5,078, ,598 41,580 1,986, , Winter 6 Winter Energy at In 47,664,199 16,646,145 2,787,161 11,089, ,814 8,843,537 5,638, ,762 50,297 1,321, , Total - 150,436,193 59,795,128 8,443,143 31,622,516 2,033,515 27,428,985 14,488, , ,403 4,925,777 1,097, System Control and Load Dispatching 192 Summer 5 Summer Energy at I 3,611,801 1,244, , ,279 51, , ,028 12,715 3, ,814 34, Winter 6 Winter Energy at In 4,045,562 1,412, , ,221 63, , ,585 18,822 4, ,175 27, Hydro Water Charge: 196 Capacity - Summer 11 Peak Hours - Peak P 509, ,339 29,929 96,297 5,190 60,229 26, ,003 2, Capacity - Winter CP - Baseload P 764, ,222 42, ,893 8, ,350 61,194 1, ,552 4, Energy - Summer 5 Summer Energy at I 2,485, , , ,759 35, , ,560 8,749 2, ,087 23, Energy - Winter 6 Winter Energy at In 2,572, , , ,443 40, , ,292 11,968 2,714 71,322 17, Total Other Power Supply Expense - 164,425,121 64,826,045 9,226,396 34,663,408 2,237,555 30,190,843 16,005, , ,249 5,399,730 1,207, TOTAL PRODUCTION EXPENSE - 205,892,704 80,820,291 11,553,673 43,475,748 2,812,240 37,938,572 20,154, , ,162 6,776,245 1,516, TRANSMISSION EXPENSES: Operation: Operation Supervision and Engineering 46 Transmission Plant 3,319,470 1,611, , ,636 36, , ,079 5,727 1,484 97,845 19, Load Dispatching Station Expenses 46 Transmission Plant 2,556,679 1,241, , ,044 28, , ,668 4,411 1,143 75,361 15, Overhead Line Expenses 46 Transmission Plant Underground Line Expenses Transmission of Electricity by Others Miscellaneous Transmission Expenses 46 Transmission Plant Rents 46 Transmission Plant 414, ,337 23,504 80,784 4,605 60,404 28, ,224 2, Subtotal - 6,290,847 3,054, ,549 1,225,464 69, , ,241 10,853 2, ,429 37, Maintenance: Maint. Supervision and Engineering Maintenance of Structures 46 Transmission Plant Maintenance of Station Equipment 46 Transmission Plant Maintenance of Overhead Lines 46 Transmission Plant 2,490,374 1,209, , ,127 27, , ,112 4,297 1,113 73,406 14, Maintenance of Underground Lines Maint. of Misc. Transmission Plant Subtotal - 2,490,374 1,209, , ,127 27, , ,112 4,297 1,113 73,406 14, TOTAL TRANSMISSION EXPENSE - 8,781,221 4,263, ,696 1,710,591 97,509 1,279, ,354 15,150 3, ,835 51, DISTRIBUTION EXPENSES: Operation: Operation Supervision and Engineering 64 Distribution Operation COSA clean.xlsx 11/6/18 5:17 PM Page 2 of 4

78 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Load Dispatching Station Expenses 82 Account 362 (Sta E 3,411,888 1,685, , ,755 30, , ,444 14,217 3, , Overhead Line Expenses: 241 Primary 69 Account 364 (Dist P Secondary 69 Account 364 (Dist P Underground Line Expenses: 244 Primary 80 Account 366 (UG) Secondary Street Lighting Expenses 36 Street Lighting Meter Expenses 27 Meters Customer Installation Expenses 28 Services Miscellaneous Distribution Expenses 64 Distribution Operati 26,500 13,090 1,509 4, ,761 2, Line Construction 46 Transmission Plant Subtotal - 3,438,388 1,698, , ,515 31, , ,568 14,327 3, , Maintenance: Maint. Supervision and Engineering 65 Distribution Mainte 1,263, ,356 83, ,812 7, ,838 68,809 10,081 5,057 50, Maintenance of Structures 81 Account 361 (Struct Maintenance of Station Equipment 82 Account 362 (Sta E Maintenance of Overhead Lines 260 Primary 69 Account 364 (Dist P 5,607,871 2,770, ,372 1,007,215 50, , ,097 23,339 5, , Secondary 69 Account 364 (Dist P 114,446 56,535 6,518 20,555 1,039 16,242 9, , Maintenance of Underground Lines 263 Primary 80 Account 366 (UG) 1,748, ,578 99, ,986 15, , ,000 7,276 1,596 58, Secondary Maintenance of Line Transformers 35 NCP - Secondary 327, ,201 22,389 69, ,483-1, , Maint. of Street Lighting Equipment 36 Street Lighting 93, ,047 37, Maintenance of Meters 27 Meters 3,236,735 2,647, ,945 93,268 1,243 14,212 7, , Maint. of Misc. Distribution Plant Subtotal - 12,391,431 7,273, ,181 1,675,758 77,558 1,224, ,054 98,897 49, , TOTAL DISTRIBUTION EXPENSE - 15,829,819 8,971,504 1,013,985 2,293, ,772 1,712, , ,224 52, , CUSTOMER ACCOUNTS EXPENSES: Supervision 66 Customer Accounts 719, ,773 56,556 18, ,017 19,020 13, Meter Reading 29 Meter Reading Customer Records and Collection 30 Accounting and Billing 6,424,729 5,207, , ,515 4,130 9, , , , Uncollectible Accounts 37 Uncollectible Accounts 2,300,000 2,223,672 68,867 7, Customer Assistance 26 Average Customers 4,258,182 3,573, ,306 83, , , ,674 64, Informational & Instructional Advertising 26 Average Customers Misc. Customer Accounts Expenses 26 Average Customers TOTAL CUSTOMER ACCTS EXP. - 13,702,338 11,613,842 1,077, ,128 5,106 11, , , , ADMINISTRATIVE & GENERAL EXPENSE: Administrative and General 3 Annual Energy Sales 41,001,233 14,228,875 2,293,437 9,008, ,492 8,303,908 4,610, ,621 39,608 1,405, , Public Benefits 3 Annual Energy Sales 4,298,867 1,491, , ,506 64, , ,434 17,679 4, ,394 34, Outside Services 3 Annual Energy Sales Property Insurance 50 Total Plant Other Expense 50 Total Plant Employee Pensions and Benefits 57 Salaries and Wages Franchise Requirements 3 Annual Energy Sales 600, ,221 33, ,826 8, ,517 67,474 2, ,572 4, General Advertising 26 Average Customers Miscellaneous General Expenses 67 A&G Operation Rents 67 A&G Operation COSA clean.xlsx 11/6/18 5:17 PM Page 3 of 4

79 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Maintenance of General Plant 49 General Plant TOTAL A&G EXPENSE - 45,900,100 15,928,955 2,567,459 10,084, ,673 9,296,067 5,161, ,768 44,341 1,573, , TOTAL O&M EXPENSES - 290,106, ,597,891 16,709,984 57,911,467 3,709,300 50,237,912 26,869,993 1,018, ,431 9,487,562 1,937, COSA clean.xlsx 11/6/18 5:17 PM Page 4 of 4

80 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Schedule 4: Electric Plant in Service INTANGIBLE PLANT: Organization Franchises and Consents 79 PTD Plant 17,253 8,953 1,032 3, ,230 1, Miscellaneous Intangible Plant 79 PTD Plant 50,598,090 26,257,592 3,025,712 9,047, ,061 6,540,534 3,175, ,426 90,926 1,626, , TOTAL INTANGIBLE PLANT - 50,615,343 26,266,545 3,026,744 9,050, ,216 6,542,764 3,177, ,503 90,957 1,627, , PRODUCTION PLANT: Hydraulic Production Plant Land and Land Rights 329 Summer 11 Peak Hours - Peak P 2,598,043 1,383, , ,914 26, , ,311 2, ,679 14, Winter CP - Baseload P 3,897,065 1,770, , ,340 45, , ,965 9,043 2, ,770 24, Structures and Improvements 332 Summer 11 Peak Hours - Peak P 3,173,586 1,689, , ,665 32, , ,064 2, ,881 17, Winter CP - Baseload P 4,760,379 2,162, , ,879 55, , ,075 11,046 2, ,980 29, Reservoirs, Dams, and Waterways 335 Summer 11 Peak Hours - Peak P 9,001,823 4,792, ,645 1,700,941 91,680 1,063, ,365 7,493 1, ,331 48, Winter CP - Baseload P 13,502,735 6,133, ,854 2,682, ,217 2,214,122 1,080,912 31,333 8, ,013 84, Wtr Wheels, Turbines, & Generators 338 Summer 11 Peak Hours - Peak P 3,977,067 2,117, , ,487 40, , ,602 3, ,688 21, Winter CP - Baseload P 5,965,600 2,709, ,965 1,185,355 69, , ,554 13,843 3, ,382 37, Misc. Power Plant Equipment 341 Summer 11 Peak Hours - Peak P 407, ,220 23,959 77,090 4,155 48,216 21, ,612 2, Winter CP - Baseload P 611, ,967 33, ,597 7, ,348 48,989 1, ,452 3, Roads, Railroads, and Bridges 344 Summer 11 Peak Hours - Peak P 352, ,535 20,685 66,555 3,587 41,627 18, ,751 1, Winter CP - Baseload P 528, ,981 29, ,980 6,191 86,635 42,294 1, ,204 3, Total Hydraulic Plant - 48,776,812 23,681,230 2,764,541 9,501, ,632 7,104,756 3,351,432 84,152 21,799 1,437, , Other Production Plant Land and Land Rights Structures and Improvements 353 Summer 11 Peak Hours - Peak P 13,724,125 7,307, ,969 2,593, ,775 1,621, ,493 11,424 2, ,882 74, Winter CP - Baseload P 20,586,187 9,350,614 1,138,648 4,090, ,217 3,375,637 1,647,952 47,770 12, , , Fuel Holders, Prod., and Accessories 356 Summer 11 Peak Hours - Peak P 2,394,326 1,274, , ,420 24, , ,779 1, ,883 12, Winter CP - Baseload P 3,591,490 1,631, , ,623 42, , ,504 8,334 2,159 96,555 22, Prime Movers 359 Summer 11 Peak Hours - Peak P 39,432,884 20,995,160 2,315,754 7,451, ,608 4,660,275 2,038,554 32,824 8,503 1,315, , Winter CP - Baseload Prod 59,149,326 26,866,679 3,271,625 11,752, ,077 9,699,060 4,734, ,254 35,555 1,590, , Generators 362 Summer 11 Peak Hours - Peak Prod 39,748,995 21,163,466 2,334,318 7,510, ,828 4,697,634 2,054,896 33,087 8,571 1,326, , Winter CP - Baseload Prod 59,623,492 27,082,054 3,297,851 11,847, ,633 9,776,812 4,772, ,355 35,840 1,602, , Accessory Electric Equipment 365 Summer 11 Peak Hours - Peak Prod 11,402,781 6,071, ,645 2,154, ,133 1,347, ,487 9,492 2, ,435 61, Winter CP - Baseload Prod 17,104,172 7,769, ,054 3,398, ,416 2,804,671 1,369,212 39,690 10, , , Misc. Power Plant Equipment 368 Summer 11 Peak Hours - Peak Prod 16,580,953 8,828, ,741 3,133, ,871 1,959, ,182 13,802 3, ,196 89, Winter CP - Baseload Prod 24,871,430 11,297,047 1,375,671 4,941, ,429 4,078,313 1,990,992 57,713 14, , , Total Other Production Plant - 308,210, ,636,586 17,468,536 60,039,666 3,422,454 44,893,424 21,176, , ,742 9,084,799 1,818, TOTAL PRODUCTION PLANT - 356,986, ,317,816 20,233,076 69,541,441 3,964,085 51,998,180 24,528, , ,541 10,522,543 2,105, COSA clean.xlsx 11/6/18 5:17 PM Page 1 of 2

81 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P TRANSMISSION PLANT: MID Transmission 378 Summer 17 Pk Needs - Trans C 40,059,146 21,328,599 2,352,532 7,569, ,987 4,734,288 2,070,930 33,346 8,638 1,336, , Winter 18 Trans Capacity for Y 60,088,719 27,293,368 3,323,584 11,939, ,084 9,853,098 4,810, ,434 36,119 1,615, , TOTAL TRANSMISSION PLANT - 100,147,864 48,621,968 5,676,116 19,508,910 1,112,071 14,587,386 6,881, ,780 44,757 2,951, , DISTRIBUTION PLANT: Land and Land Rights 81 Account 361 (Struct 21,785,444 10,760,936 1,240,602 3,912, ,776 3,091,506 1,745,985 90,777 19, , Structures and Improvements 387 Subtransmission 33 NCP - Subtransmiss 3,736,947 1,846, , ,299 33, , ,733 15,509 3, , Primary 34 NCP - Primary 3,057,502 1,509, , ,945 27, , ,805 12,802 2, , Station Equipment 390 Subtransmission 33 NCP - Subtransmiss 44,477,035 21,974,853 2,533,428 7,989, ,877 6,313,149 3,555, ,589 40,500 1,481, Primary 34 NCP - Primary 36,390,301 17,969,629 2,071,675 6,533, ,265 5,162,489 2,925, ,374 33,432 1,211, Poles, Towers, and Fixtures 393 Subtransmission 39 NCP - Subtransmiss 35,428,756 17,504,353 2,018,034 6,364, ,713 5,028,820 2,832, ,037 32,261 1,179, Primary 40 NCP - Primary 16,292,056 8,045, ,496 2,925, ,860 2,311,263 1,309,783 68,218 14, , Overhead Conductors and Devices 396 Subtransmission 39 NCP - Subtransmiss 14,595,059 7,211, ,340 2,621, ,531 2,071,648 1,166,736 60,573 13, , Primary 40 NCP - Primary 6,711,596 3,314, ,087 1,205,002 60, , ,572 28,103 6, , Underground Conduit 399 Subtransmission 41 NCP - Subtransmiss 36,282,432 17,926,130 2,066,660 6,517, ,465 5,149,992 2,900, ,580 33,038 1,208, Primary 42 NCP - Primary 16,684,622 8,238, ,844 2,995, ,423 2,366,954 1,341,343 69,862 15, , Underground Conductors and Devices 402 Subtransmission 41 NCP - Subtransmiss 42,569,533 21,032,410 2,424,776 7,647, ,556 6,042,395 3,403, ,673 38,763 1,417, Primary 42 NCP - Primary 19,575,771 9,666,568 1,114,435 3,514, ,662 2,777,105 1,573,774 81,968 17, , Line Transformers 35 NCP - Secondary 63,901,476 37,867,137 4,365,611 13,633, ,928 4,968, ,331 71,819 2,552, Services 28 Services 31,211,508 26,785,122 2,903, ,137 5,310 6, , Meters 27 Meters 24,066,773 19,683,462 2,133, ,496 9, ,673 59, ,381, Installations on Customer Premises 28 Services 4,639,662 3,981, ,592 93, , Leased Property on Customer Premises 36 Street Lighting 2,588, ,553,155 1,035, Street Lighting Equipment 36 Street Lighting TOTAL DISTRIBUTION PLANT - 423,995, ,317,578 26,781,443 68,497,547 2,830,993 47,313,206 23,897,824 3,119,551 1,379,117 14,857, GENERAL PLANT: Land and Land Rights 79 PTD Plant Structures and Improvements 79 PTD Plant 827, ,175 49, ,872 7, ,904 51,911 3,668 1,486 26,592 2, Office Furniture and Equipment 57 Salaries and Wages 296, ,774 18,600 48,477 2,453 34,773 16,809 1,135 1,471 8, Transportation Equipment 58 PTD Salaries & Wages Stores Equipment 59 Materials & Supplies Tools, Shop, and Garage Equipment 58 PTD Salaries & Wages 789, ,589 46, ,934 7, ,912 50,586 3,020 1,179 24,899 2, Laboratory Equipment 79 PTD Plant 744, ,102 44, ,031 6,677 96,175 46,701 3,300 1,337 23,923 2, Power Operated Equipment 58 PTD Salaries & Wages Communication Equipment 58 PTD Salaries & Wages 2,774,597 1,419, , ,073 26, , ,860 10,618 4,145 87,545 10, Miscellaneous Equipment 70 Accounts ,564,592 22,439,628 2,589,820 7,868, ,130 5,722,137 2,762, ,004 76,945 1,374, , TOTAL GENERAL PLANT - 48,995,643 25,240,290 2,912,975 8,847, ,367 6,433,774 3,106, ,744 86,562 1,546, , TOTAL PLANT IN SERVICE - 980,740, ,764,197 58,630, ,445,433 8,816, ,875,311 61,590,830 4,325,469 1,760,935 31,505,589 3,026, COSA clean.xlsx 11/6/18 5:17 PM Page 2 of 2

82 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Schedule 5: Accumulated Depreciation INTANGIBLE PLANT: Organization Franchises and Consents 79 PTD Plant 8,103 4, , , Miscellaneous Intangible Plant 79 PTD Plant 9,804,880 5,088, ,321 1,753,133 87,988 1,267, ,439 43,489 17, ,265 30, TOTAL INTANGIBLE PLANT - 9,812,983 5,092, ,806 1,754,582 88,060 1,268, ,948 43,525 17, ,526 30, PRODUCTION PLANT: Hydraulic Production Plant Structures and Improvements 446 Summer 11 Peak Hours - Peak P 1,634, ,381 96, ,893 16, ,198 84,511 1, ,540 8, Winter CP - Baseload P 2,452,110 1,113, , ,230 28, , ,295 5,690 1,474 65,924 15, Reservoirs, Dams, and Waterways 449 Summer 11 Peak Hours - Peak P 3,961,593 2,109, , ,563 40, , ,802 3, ,172 21, Winter CP - Baseload P 5,942,389 2,699, ,681 1,180,743 69, , ,696 13,789 3, ,758 36, Wtr Wheels, Turbines, & Generators 452 Summer 11 Peak Hours - Peak P 3,678,715 1,958, , ,112 37, , ,178 3, ,734 19, Winter CP - Baseload P 5,518,072 2,506, ,212 1,096,432 64, , ,729 12,805 3, ,350 34, Misc. Power Plant Equipment 455 Summer 11 Peak Hours - Peak P 221, ,029 13,019 41,888 2,258 26,199 11, ,396 1, Winter CP - Baseload P 332, ,037 18,392 66,071 3,896 54,525 26, ,940 2, Roads, Railroads, and Bridges 458 Summer 11 Peak Hours - Peak P 260, ,768 15,306 49,248 2,654 30,802 13, ,696 1, Winter CP - Baseload P 390, ,576 21,624 77,681 4,581 64,106 31, ,510 2, Total Hydraulic Plant - 24,393,404 11,843,042 1,382,554 4,751, ,871 3,553,106 1,676,059 42,085 10, , , Other Production Plant Structures and Improvements 466 Summer 11 Peak Hours - Peak P 2,196,220 1,169, , ,987 22, , ,538 1, ,273 11, Winter CP - Baseload P 3,294,330 1,496, , ,578 38, , ,716 7,644 1,980 88,566 20, Fuel Holders, Prod., and Accessories 469 Summer 11 Peak Hours - Peak P 1,251, ,146 73, ,411 12, ,864 64,680 1, ,742 6, Winter CP - Baseload P 1,876, , , ,902 21, , ,234 4,355 1,128 50,455 11, Prime Movers 472 Summer 11 Peak Hours - Peak P 18,106,834 9,640,580 1,063,350 3,421, ,411 2,139, ,065 15,072 3, ,104 98, Winter CP - Baseload P 27,160,251 12,336,671 1,502,268 5,396, ,248 4,453,625 2,174,215 63,025 16, , , Generators 475 Summer 11 Peak Hours - Peak P 33,810,005 18,001,384 1,985,542 6,388, ,342 3,995,749 1,747,869 28,144 7,290 1,128, , Winter CP - Baseload P 50,715,008 23,035,662 2,805,112 10,076, ,248 8,316,036 4,059, ,683 30,485 1,363, , Accessory Electric Equipment 478 Summer 11 Peak Hours - Peak Prod 6,013,181 3,201, ,133 1,136,222 61, , ,862 5,005 1, ,620 32, Winter CP - Baseload Prod 9,019,772 4,096, ,895 1,792, ,688 1,479, ,045 20,930 5, ,491 56, Misc. Power Plant Equipment 481 Summer 11 Peak Hours - Peak Prod 8,253,384 4,394, ,692 1,559,519 84, , ,674 6,870 1, ,360 44, Winter CP - Baseload Prod 12,380,076 5,623, ,758 2,459, ,062 2,030, ,042 28,728 7, ,831 77, Total Other Production Plant - 174,076,935 84,514,664 9,866,220 33,910,371 1,933,000 25,355,782 11,960, ,326 77,797 5,131,089 1,026, TOTAL PRODUCTION PLANT - 198,470,339 96,357,706 11,248,773 38,662,232 2,203,871 28,908,888 13,636, ,410 88,699 5,850,109 1,170, TRANSMISSION PLANT: MID Transmission 2018 COSA clean.xlsx 11/6/18 5:18 PM Page 1 of 2

83 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Summer 17 Pk Needs - Trans C 32,726,717 17,424,611 1,921,924 6,183, ,309 3,867,724 1,691,867 27,242 7,057 1,091, , Winter 18 Trans Capacity for Y 49,090,076 22,297,588 2,715,235 9,754, ,208 8,049,586 3,929, ,912 29,508 1,319, , TOTAL TRANSMISSION PLANT - 81,816,793 39,722,200 4,637,159 15,937, ,517 11,917,310 5,621, ,154 36,565 2,411, , DISTRIBUTION PLANT: Structures and Improvements 499 Subtransmission 33 NCP - Subtransmiss 2,359,351 1,165, , ,830 21, , ,608 9,792 2,148 78, Primary 34 NCP - Primary 1,930, , , ,581 17, , ,191 8,083 1,773 64, Station Equipment 502 Subtransmission 33 NCP - Subtransmiss 29,613,152 14,631,026 1,686,776 5,319, ,904 4,203,343 2,367, ,901 26, , Primary 34 NCP - Primary 24,228,942 11,964,317 1,379,337 4,350, ,893 3,437,225 1,947, ,452 22, , Poles, Towers, and Fixtures 505 Subtransmission 33 NCP - Subtransmiss 25,640,841 12,668,419 1,460,511 4,606, ,833 3,639,506 2,049, ,415 23, , Primary 34 NCP - Primary 11,791,044 5,822, ,256 2,116, ,011 1,672, ,929 49,372 10, , Overhead Conductors and Devices 508 Subtransmission 33 NCP - Subtransmiss 3,111,145 1,537, , ,881 28, , ,707 12,912 2, , Primary 34 NCP - Primary 1,430, ,470 81, ,864 12, , ,017 5,991 1,314 47, Underground Conduit 511 Subtransmission 33 NCP - Subtransmiss 16,095,645 7,952, ,814 2,891, ,158 2,284,644 1,286,694 66,800 14, , Primary 34 NCP - Primary 7,401,647 3,654, ,371 1,328,894 67,175 1,050, ,048 30,992 6, , Underground Conductors and Devices 514 Subtransmission 33 NCP - Subtransmiss 29,876,418 14,761,099 1,701,771 5,366, ,295 4,240,711 2,388, ,994 27, , Primary 34 NCP - Primary 13,738,791 6,784, ,140 2,466, ,688 1,949,046 1,104,516 57,527 12, , Line Transformers 35 NCP - Secondary 36,267,442 21,491,588 2,477,713 7,738,009 64,660 2,820, ,778 40,761 1,448, Services 28 Services 15,279,904 13,112,923 1,421, ,000 2,600 2, , Meters 27 Meters 9,873,980 8,075, , ,524 3,792 43,355 24, , Installations on Customer Premises 28 Services 2,870,923 2,463, ,060 57, , Leased Property on Customer Premises 36 Street Lighting 2,588, ,553,155 1,035, Street Lighting Equipment 36 Street Lighting TOTAL DISTRIBUTION PLANT - 234,098, ,745,337 14,564,417 38,421,232 1,589,675 26,597,554 13,419,290 2,435,162 1,228,957 8,096, GENERAL PLANT: Structures and Improvements 79 PTD Plant 348, ,091 20,868 62,395 3,132 45,108 21,904 1, ,220 1, Office Furniture and Equipment 57 Salaries and Wages 39,525 21,714 2,481 6, ,639 2, , Transportation Equipment 58 PTD Salaries & Wages Stores Equipment 59 Materials & Supplies Tools, Shop, and Garage Equipment 58 PTD Salaries & Wages 789, ,589 46, ,934 7, ,912 50,586 3,020 1,179 24,899 2, Laboratory Equipment 79 PTD Plant 469, ,497 28,059 83,897 4,211 60,653 29,452 2, ,087 1, Power Operated Equipment 58 PTD Salaries & Wages Communication Equipment 58 PTD Salaries & Wages 984, ,525 58, ,575 9, ,891 63,112 3,768 1,471 31,065 3, Miscellaneous Equipment 70 Accounts ,930,092 7,690, ,562 2,696, ,843 1,961, ,761 58,605 26, ,050 53, Other Tangible Property TOTAL GENERAL PLANT - 17,561,465 9,043,738 1,043,789 3,172, ,277 2,307,246 1,114,057 69,173 30, ,508 62, TOTAL ACCUM. DEPRECIATION - 541,760, ,961,373 32,080,944 97,948,773 4,953,402 70,999,468 34,407,694 3,031,425 1,402,540 17,228,769 1,746, COSA clean.xlsx 11/6/18 5:18 PM Page 2 of 2

84 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Schedule 6: Depreciation Expense INTANGIBLE PLANT: Organization Franchises and Consents 79 PTD Plant Miscellaneous Intangible Plant 79 PTD Plant 1,614, ,961 96, ,719 14, , ,355 7,162 2,902 51,920 4, TOTAL INTANGIBLE PLANT - 1,614, ,050 96, ,750 14, , ,366 7,163 2,902 51,926 4, PRODUCTION PLANT: Hydraulic Production Plant Structures and Improvements 556 Summer 11 Peak Hours - Peak P 52,999 28,218 3,112 10, ,264 2, , Winter CP - Baseload P 79,498 36,110 4,397 15, ,036 6, , Reservoirs, Dams, and Waterways 559 Summer 11 Peak Hours - Peak P 90,018 47,928 5,286 17, ,639 4, , Winter CP - Baseload P 135,027 61,332 7,469 26,830 1,582 22,141 10, , Wtr Wheels, Turbines, & Generators 562 Summer 11 Peak Hours - Peak P 111,150 59,179 6,527 21,002 1,132 13,136 5, , Winter CP - Baseload P 166,724 75,729 9,222 33,128 1,954 27,339 13, ,482 1, Misc. Power Plant Equipment 565 Summer 11 Peak Hours - Peak P 12,239 6, , , Winter CP - Baseload P 18,359 8,339 1,015 3, ,010 1, Roads, Railroads, and Bridges 568 Summer 11 Peak Hours - Peak P 5,882 3, , Winter CP - Baseload P 8,823 4, , , Total Hydraulic Plant - 680, ,491 38, ,605 7,559 99,153 46,772 1, ,065 4, Other Production Plant Structures and Improvements 576 Summer 11 Peak Hours - Peak P 229, ,029 13,460 43,307 2,334 27,087 11, ,647 1, Winter CP - Baseload P 343, ,155 19,015 68,310 4,028 56,373 27, ,243 2, Fuel Holders, Prod., and Accessories 579 Summer 11 Peak Hours - Peak P 71,830 38,244 4,218 13, ,489 3, , Winter CP - Baseload P 107,745 48,940 5,959 21,409 1,262 17,668 8, , Prime Movers 582 Summer 11 Peak Hours - Peak P 1,577, ,806 92, ,042 16, ,411 81,542 1, ,624 8, Winter CP - Baseload P 2,365,973 1,074, , ,115 27, , ,399 5,490 1,422 63,608 14, Generators 585 Summer 11 Peak Hours - Peak P 1,589, ,539 93, ,431 16, ,905 82,196 1, ,046 8, Winter CP - Baseload P 2,384,940 1,083, , ,884 27, , ,918 5,534 1,434 64,118 14, Accessory Electric Equipment 588 Summer 11 Peak Hours - Peak Prod 342, ,135 20,089 64,638 3,484 40,428 17, ,413 1, Winter CP - Baseload Prod 513, ,071 28, ,957 6,012 84,140 41,076 1, ,795 3, Misc. Power Plant Equipment 591 Summer 11 Peak Hours - Peak Prod 497, ,845 29,212 93,992 5,066 58,787 25, ,596 2, Winter CP - Baseload Prod 746, ,911 41, ,257 8, ,349 59,730 1, ,060 4, Total Other Production Plant - 10,769,525 5,228, ,388 2,097, ,588 1,568, ,969 18,580 4, ,442 63, TOTAL PRODUCTION PLANT - 11,450,245 5,559, ,970 2,230, ,147 1,667, ,741 19,755 5, ,507 67, TRANSMISSION PLANT: MID Transmission 2018 COSA clean.xlsx 11/6/18 5:18 PM Page 1 of 2

85 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Summer 17 Pk Needs - Trans C 737, ,415 43, ,266 7,506 87,104 38, ,590 3, Winter 18 Trans Capacity for Y 1,105, ,159 61, ,670 12, ,283 88,500 2, ,722 6, TOTAL TRANSMISSION PLANT - 1,842, , , ,936 20, , ,603 3, ,312 10, DISTRIBUTION PLANT: Structures and Improvements 609 Subtransmission 33 93,426 46,159 5,322 16, ,261 7, , Primary 34 76,439 37,746 4,352 13, ,844 6, , Station Equipment 612 Subtransmission 33 1,472, ,589 83, ,542 13, , ,723 6,112 1,341 49, Primary 34 1,204, ,976 68, ,326 10, ,930 96,866 5,045 1,107 40, Poles, Towers, and Fixtures 615 Subtransmission 33 NCP - Subtransmiss 1,062, ,131 60, ,931 9, ,865 84,966 4, , Primary 34 NCP - Primary 488, ,352 27,825 87,752 4,436 69,338 39,293 2, , Overhead Conductors and Devices 618 Subtransmission 33 NCP - Subtransmiss 437, ,330 24,940 78,655 3,976 62,149 35,002 1, , Primary 34 NCP - Primary 201,348 99,426 11,463 36,150 1,827 28,564 16, , Underground Conduit 621 Subtransmission 33 NCP - Subtransmiss 1,452, ,396 82, ,836 13, , ,074 6,026 1,322 48, Primary 34 NCP - Primary 667, ,717 38, ,881 6,060 94,724 53,680 2, , Underground Conductors and Devices 624 Subtransmission 33 NCP - Subtransmiss 1,564, ,178 89, ,118 14, , ,100 6,495 1,425 52, Primary 34 NCP - Primary 719, ,355 40, ,203 6, ,090 57,854 3, , Line Transformers 35 NCP - Secondary 1,917,044 1,136, , ,020 3, ,070-9,820 2,155 76, Services 28 Services 789, ,417 73,428 15, , Meters 27 Meters 1,180, , ,687 34, ,185 2, , Installations on Customer Premises 28 Services 139, ,450 12,948 2, , Leased Property on Customer Premises 36 Street Lighting 21, ,777 8, Street Lighting Equipment 36 Street Lighting TOTAL DISTRIBUTION PLANT - 13,490,236 7,563, ,774 2,157,664 89,756 1,494, ,271 61,910 19, , GENERAL PLANT: Structures and Improvements 79 PTD Plant 24,810 12,875 1,484 4, ,207 1, Office Furniture and Equipment 57 Salaries and Wages 19,763 10,857 1,241 3, ,319 1, Transportation Equipment 58 PTD Salaries & Wages Stores Equipment 59 Materials & Supplies Tools, Shop, and Garage Equipment 58 PTD Salaries & Wages 123,463 63,143 7,296 22,519 1,167 16,414 7, , Laboratory Equipment 79 PTD Plant 37,201 19,305 2,225 6, ,809 2, , Power Operated Equipment 58 PTD Salaries & Wages Communication Equipment 58 PTD Salaries & Wages 110,984 56,761 6,559 20,243 1,049 14,755 7, , Miscellaneous Equipment 70 Accounts ,861,037 1,473, , ,720 26, , ,427 11,230 5,053 90,267 10, Other Tangible Property TOTAL GENERAL PLANT - 3,177,258 1,636, , ,803 29, , ,469 12,478 5, ,251 11, TOTAL DEPRECIATION EXPENSE - 31,575,228 16,491,403 1,898,633 5,609, ,397 4,056,714 1,975, ,484 33,754 1,029,051 94, COSA clean.xlsx 11/6/18 5:18 PM Page 2 of 2

86 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Schedule 7: Rate Base NET PLANT IN SERVICE: Intangible Plant 92 Schedule 4 50,615,343 26,266,545 3,026,744 9,050, ,216 6,542,764 3,177, ,503 90,957 1,627, , Production Plant 92 Schedule 4 356,986, ,317,816 20,233,076 69,541,441 3,964,085 51,998,180 24,528, , ,541 10,522,543 2,105, Transmission Plant 92 Schedule 4 100,147,864 48,621,968 5,676,116 19,508,910 1,112,071 14,587,386 6,881, ,780 44,757 2,951, , Distribution Plant 92 Schedule 4 423,995, ,317,578 26,781,443 68,497,547 2,830,993 47,313,206 23,897,824 3,119,551 1,379,117 14,857, General Plant 92 Schedule 4 48,995,643 25,240,290 2,912,975 8,847, ,367 6,433,774 3,106, ,744 86,562 1,546, , Total Plant - 980,740, ,764,197 58,630, ,445,433 8,816, ,875,311 61,590,830 4,325,469 1,760,935 31,505,589 3,026, Accum. Provision for Depreciation 93 Schedule 5 (541,760,448) (277,961,373) (32,080,944) (97,948,773) (4,953,402) (70,999,468) (34,407,694) (3,031,425) (1,402,540) (17,228,769) (1,746,060) NET PLANT INVESTMENT - 438,980, ,802,824 26,549,410 77,496,660 3,863,329 55,875,842 27,183,136 1,294, ,395 14,276,821 1,279, ADD: 669 Materials and Supplies Inventories 95 Schedule 8 7,031,590 3,613, ,275 1,238,282 61, , ,455 36,691 15, ,013 19, Construction Work in Progress 95 Schedule 8 11,528,975 5,958, ,155 2,073, ,068 1,502, ,952 49,020 19, ,537 37, Working Capital Allowance (1/8) 56 O&M - Fuel&Purch Pwr 672 Purchased Power Allowance (1/12) DEDUCT: 675 Customer Advances 95 Schedule 8 23,425,601 11,725,080 1,360,549 4,394, ,707 3,239,626 1,547,048 68,934 24, , , RATE BASE - 434,115, ,649,902 26,299,292 76,412,982 3,792,311 55,068,945 26,819,496 1,310, ,623 14,164,699 1,228, COSA clean.xlsx 11/6/18 5:19 PM Page 1 of 1

87 MID COST OF SERVICE STUDY 2018 TEST YEAR FER Alloc Allocation System Acco Cost Element Factor Basis Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Schedule 8: Miscellaneous Customer Advances - Production 77 Total Production Pl 18,362,086 8,914,826 1,040,714 3,576, ,898 2,674,594 1,261,650 31,679 8, , , Customer Advances - Distribution 47 Distribution Plant 5,063,515 2,810, , ,025 33, , ,397 37,255 16, , Construction Work in Progress: 690 Production 77 Total Production Pl 5,648,250 2,742, ,128 1,100,285 62, , ,089 9,745 2, ,488 33, Transmission 46 Transmission Plant 256, ,704 14,558 50,036 2,852 37,413 17, ,571 1, Distribution 47 Distribution Plant 4,880,254 2,708, , ,418 32, , ,068 35,907 15, , General 49 General Plant 743, ,076 44, ,279 6,911 97,646 47,147 2,925 1,314 23,469 2, Total - 11,528,975 5,958, ,155 2,073, ,068 1,502, ,952 49,020 19, ,537 37, Materials and Supplies Inventories: 698 Fuel 5 Summer Energy at I 633, ,375 33, ,228 8, ,142 67,200 2, ,284 5, Other Production 77 Total Production Pl 1,279, ,241 72, ,265 14, ,382 87,920 2, ,717 7, Transmission 46 Transmission Plant 959, ,931 54, ,949 10, ,787 65,940 1, ,288 5, Distribution 47 Distribution Plant 4,158,646 2,308, , ,840 27, , ,396 30,597 13, , General Total - 7,031,590 3,613, ,275 1,238,282 61, , ,455 36,691 15, ,013 19, Salaries and Wages: 707 Production 77 Total Production Pl 11,569,653 5,617, ,737 2,253, ,473 1,685, ,945 19,961 5, ,027 68, Transmission 46 Transmission Plant 5,051,298 2,452, , ,998 56, , ,072 8,715 2, ,892 29, Transmission -- Maintenance 46 Transmission Plant 2,076,524 1,008, , ,509 23, , ,677 3, ,208 12, Distribution 47 Distribution Plant 2,597,793 1,441, , ,680 17, , ,421 19,113 8,450 91, Distribution -- Maintenance 47 Distribution Plant 8,531,187 4,734, ,868 1,378,236 56, , ,847 62,768 27, , Customer Accounting 26 Average Customers 6,114,670 5,130, , ,516 1,017 2, , ,570 92, Administrative and General 79 PTD Plant 21,041,341 10,919,284 1,258,250 3,762, ,822 2,719,897 1,320,737 93,328 37, ,562 64, Total - 56,982,467 31,304,450 3,577,094 9,322, ,769 6,687,518 3,232, , ,937 1,710, , COSA clean.xlsx 11/6/18 5:19 PM Page 1 of 1

88 11/6/ COSA clean.xlsx Page 1 COST ALLOCATION FACTORS System No. Factor Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P-4 ENERGY (MWh): 1 Summer Energy Sales S P S 1,235, ,840 65, ,950 17, , ,042 4,350 1,073 51,255 11,682 2 Winter Energy Sales S P W 1,355, ,237 79, ,261 21, , ,302 6,305 1,430 37,573 9,123 3 Annual Energy Sales S P A 2,590, , , ,212 38, , ,344 10,655 2,503 88,828 20, Summer Energy at Input I P S 1,242, ,152 66, ,329 17, , ,754 4,374 1,079 51,533 11,745 6 Winter Energy at Input I P W 1,359, ,757 79, ,273 21, , ,816 6,325 1,434 37,693 9,153 7 Annual Energy at Input I P A 2,601, , , ,602 38, , ,570 10,698 2,513 89,227 20, DEMAND (MW): 11 Peak Hours - Peak Prod P P CP - Baseload Prod P A NCP - Subtransmission T D A NCP - Primary P D A NCP - Secondary S D A Pk Needs - Trans Capacity T P Trans Capacity for Year Around Needs T A DA- NCP - NO IC-25 P D A DA- NCP - ALL IC-25 P D A CUSTOMER: Voltage Function Season 26 Average Customers 114,210 95,835 10,388 2, ,746 1, Meters 117,177 95,835 10,388 3, , Services 111,672 95,835 10,388 2, , Meter Reading 114,713 95,835 10,388 4, , Accounting and Billing 118,241 95,835 10,388 4, ,746 3, Average No. of Meters 110,394 95,835 10,388 2, , NCP - Subtransmission T D A NCP - Primary P D A NCP - Secondary S D A

89 11/6/ COSA clean.xlsx Page 2 COST ALLOCATION FACTORS Voltage Function Season System No. Factor Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P-4 DIRECT ASSIGNMENTS: 36 Street Lighting Uncollectible Accounts 69,387 67,085 2, NCP - Subtransmission OH NCP - Primary OH NCP - Subtransmission UG NCP - Primary UG Discretionary Revs 9,030,000 3,600, ,000 4,600, Sales Revenues 356,802, ,733,609 22,958,570 76,301,128 4,867,789 56,993,098 23,387,304 1,281, ,636 12,445,627 2,131,909 COMPOSITE FACTORS: 46 Transmission Plant 100,147,864 48,621,968 5,676,116 19,508,910 1,112,071 14,587,386 6,881, ,780 44,757 2,951, , Distribution Plant 423,995, ,317,578 26,781,443 68,497,547 2,830,993 47,313,206 23,897,824 3,119,551 1,379,117 14,857, T&D Plant 524,142, ,939,546 32,457,559 88,006,457 3,943,063 61,900,592 30,778,937 3,292,331 1,423,874 17,809, , General Plant 48,995,643 25,240,290 2,912,975 8,847, ,367 6,433,774 3,106, ,744 86,562 1,546, , Total Plant 980,740, ,764,197 58,630, ,445,433 8,816, ,875,311 61,590,830 4,325,469 1,760,935 31,505,589 3,026, Net Plant 438,980, ,802,824 26,549,410 77,496,660 3,863,329 55,875,842 27,183,136 1,294, ,395 14,276,821 1,279, Rate Base 434,115, ,649,902 26,299,292 76,412,982 3,792,311 55,068,945 26,819,496 1,310, ,623 14,164,699 1,228, Power Production Exp 205,892,704 80,820,291 11,553,673 43,475,748 2,812,240 37,938,572 20,154, , ,162 6,776,245 1,516, Purchased Power 150,436,193 59,795,128 8,443,143 31,622,516 2,033,515 27,428,985 14,488, , ,403 4,925,777 1,097, O&M - Fuel&Purch Pwr 116,842,742 53,882,424 6,991,736 21,282,516 1,335,258 18,174,021 9,818, , ,038 3,774, , Salaries and Wages 56,982,467 31,304,450 3,577,094 9,322, ,769 6,687,518 3,232, , ,937 1,710, , PTD Salaries & Wages 29,826,455 15,254,250 1,762,680 5,440, ,930 3,965,318 1,911, ,139 44, , , Materials & Supplies 7,031,590 3,613, ,275 1,238,282 61, , ,455 36,691 15, ,013 19, Other Power Operation 26,900,821 9,927,186 1,507,257 5,796, ,190 5,211,206 2,832,361 99,980 23, , , Other Power Maint. 4,484,405 2,177, , ,567 49, , ,121 7,737 2, ,182 26, Transmission Expense 8,781,221 4,263, ,696 1,710,591 97,509 1,279, ,354 15,150 3, ,835 51, Distribution Expense 15,829,819 8,971,504 1,013,985 2,293, ,772 1,712, , ,224 52, , Distribution Operation 3,411,888 1,685, , ,755 30, , ,444 14,217 3, , Distribution Maintenance 11,128,359 6,531, ,783 1,504,946 69,652 1,099, ,245 88,816 44, , Customer Accounts 12,982,911 11,004,070 1,020, ,903 4,838 10, , , , A&G Operation 45,900,100 15,928,955 2,567,459 10,084, ,673 9,296,067 5,161, ,768 44,341 1,573, , Admin & General Exp 45,900,100 15,928,955 2,567,459 10,084, ,673 9,296,067 5,161, ,768 44,341 1,573, , Account 364 (Dist Poles) 51,720,812 25,549,414 2,945,530 9,289, ,574 7,340,083 4,141, ,255 47,229 1,722, Accounts ,604,036 2,371, , ,516 42, , ,956 18,072 8, ,259 16, Revenue Requirements 389,784, ,482,664 22,791,531 75,698,746 4,592,293 63,060,037 33,114,582 1,323, ,261 12,785,638 2,223, Total Revenue 377,575, ,134,850 23,627,084 78,126,248 4,958,143 59,135,144 28,626,292 1,312, ,419 12,783,108 2,161,175 74

90 11/6/ COSA clean.xlsx Page 3 COST ALLOCATION FACTORS Voltage Function Season System No. Factor Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P Total Production Plant 356,986, ,317,816 20,233,076 69,541,441 3,964,085 51,998,180 24,528, , ,541 10,522,543 2,105, Hydro Production Plant 48,776,812 23,681,230 2,764,541 9,501, ,632 7,104,756 3,351,432 84,152 21,799 1,437, , PTD Plant 881,129, ,257,362 52,690, ,547,898 7,907, ,898,773 55,307,347 3,908,222 1,583,416 28,331,778 2,697, Account 366 (UG) 52,967,054 26,165,041 3,016,504 9,513, ,888 7,516,947 4,241, ,442 48,367 1,763, Account 361 (Structures) 6,794,448 3,356, ,919 1,220,244 61, , ,538 28,312 6, , Account 362 (Sta Equip) 80,867,337 39,944,482 4,605,103 14,523, ,141 11,475,638 6,481, ,963 73,932 2,692, Schedule 2 91 Schedule 3 92 Schedule 4 93 Schedule 5 94 Schedule 6 95 Schedule

91 MID FUNCTIONAL COST ANALYSIS Factor Voltage Function Season Code System Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P-4 Production: Demand Summer P P DPP 42,204,705 22,470,955 2,478,533 7,974, ,838 4,987,856 2,181,848 35,132 9,101 1,408, ,558 Winter P A DAP 62,077,610 28,196,758 3,433,592 12,334, ,388 10,179,228 4,969, ,049 37,315 1,668, ,243 Subtotal 104,282,315 50,667,713 5,912,125 20,309,514 1,157,227 15,167,083 7,151, ,181 46,415 3,077, ,801 Energy Summer P S ESP 90,829,130 31,301,524 4,827,695 18,666,733 1,288,321 20,087,727 9,632, ,758 78,859 3,767, ,670 Winter P W EWP 93,623,862 32,697,002 5,474,649 21,782,086 1,462,993 17,370,817 11,075, ,593 98,795 2,595, ,347 Subtotal 184,452,992 63,998,526 10,302,344 40,448,819 2,751,314 37,458,545 20,707, , ,653 6,363,502 1,489,017 Total 288,735, ,666,239 16,214,469 60,758,333 3,908,541 52,625,628 27,859, , ,069 9,440,513 2,103,818 Transmission (Demand) Summer T P DPT 6,106,738 3,251, ,627 1,153,900 62, , ,699 5,083 1, ,741 33,071 Winter T A DAT 9,160,108 4,160, ,657 1,820, ,333 1,502, ,279 21,256 5, ,264 56,994 Distribution: Subtotal 15,266,846 7,412, ,284 2,973, ,527 2,223,746 1,048,978 26,339 6, ,005 90,064 Customer Subtransmission T D A CADT 28,181,657 13,923,765 1,605,237 5,062, ,905 4,000,154 2,252, ,960 25, ,614 - Primary P D A CADP 16,135,912 7,967, ,606 2,897, ,443 2,289,112 1,297,230 67,564 14, ,128 - Secondary S D A CADS 7,281,434 4,314, ,452 1,553,564 12, ,206-37,299 8, ,870 - Subtotal 51,599,002 26,206,599 3,021,295 9,513, ,331 6,855,472 3,550, ,823 48,670 1,766,612 - Other Customer C 14,810,426 16,150,043 2,063, ,722 8,541 (786,854) (4,582,638) 109, , , SUMMARY: Total 66,409,428 42,356,642 5,085,184 10,145, ,871 6,068,618 (1,032,552) 331, ,587 2,557, TOTAL 370,411, ,434,962 22,164,937 73,878,168 4,501,940 60,917,991 27,875,594 1,292, ,478 12,448,157 2,194,078 Energy 184,452,992 63,998,526 10,302,344 40,448,819 2,751,314 37,458,545 20,707, , ,653 6,363,502 1,489,017 Demand 119,549,161 58,079,794 6,777,409 23,283,512 1,326,754 17,390,829 8,200, ,520 53,238 3,527, ,865 Customer 66,409,428 42,356,642 5,085,184 10,145, ,871 6,068,618 (1,032,552) 331, ,587 2,557, Total 370,411, ,434,962 22,164,937 73,878,168 4,501,940 60,917,991 27,875,594 1,292, ,478 12,448,157 2,194,078 FACTORS: Energy Factors Summer Energy Sales 1 S P S ESPS Winter Energy Sales 2 S P W EWPS Annual Energy Sales 3 S P A EAPS 45,900,100 15,928,955 2,567,459 10,084, ,673 9,296,067 5,161, ,768 44,341 1,573, ,602 4 Summer Energy at Input 5 I P S ESPI 68,936,592 23,756,920 3,664,076 14,167, ,797 15,245,984 7,310, ,687 59,851 2,859, ,705 Winter Energy at Input 6 I P W EWPI 69,616,301 24,312,651 4,070,808 16,196,600 1,087,844 12,916,494 8,235, ,896 73,461 1,930, ,710 Annual Energy at Input 7 I P A EAPI

92 MID FUNCTIONAL COST ANALYSIS Factor Voltage Function Season Code System Total Residential GS-1 GS-2 GS-TOU GS-3 IC-25 SL-1 SL-2 P-3 P-4 Demand Factors Peak Hours - Peak Prod 11 P P DPP 42,204,705 22,470,955 2,478,533 7,974, ,838 4,987,856 2,181,848 35,132 9,101 1,408, , CP - Baseload Prod 12 P A DAP 62,077,610 28,196,758 3,433,592 12,334, ,388 10,179,228 4,969, ,049 37,315 1,668, ,243 NCP - Subtransmission 13 T D A DADT NCP - Primary 14 P D A DADP NCP - Secondary 15 S D A DADS Pk Needs - Trans Capacity 17 T P DPT 6,106,738 3,251, ,627 1,153,900 62, , ,699 5,083 1, ,741 33,071 Trans Capacity for Year Around Need 18 T A DAT 9,160,108 4,160, ,657 1,820, ,333 1,502, ,279 21,256 5, ,264 56, DA- NCP - NO IC P D A DADP DA- NCP - ALL IC P D A DADP Customer Factors Average Customers 26 C 4,542,287 3,811, ,147 89, , , ,993 68, Meters 27 C 7,000,175 5,725, , ,714 2,688 30,736 17, , Services 28 C 4,339,547 3,724, ,674 87, , Meter Reading 29 C Accounting and Billing 30 C 6,780,745 5,495, , ,676 4,358 9, , , , Average No. of Meters 31 C NCP - Subtransmission 33 T D A CADT (6,753,546) (3,336,738) (384,684) (1,213,195) (61,326) (958,610) (539,882) (28,029) (6,150) (224,933) - NCP - Primary 34 P D A CADP 70,819 34,971 4,032 12, ,047 5, ,357 - NCP - Secondary 35 S D A CADS 7,281,434 4,314, ,452 1,553,564 12, ,206-37,299 8, ,870 - Direct Assignments Street Lighting 36 C 150, ,132 60, Uncollectible Accounts 37 C 1,027, ,354 30,764 3, NCP - Subtransmission OH 39 T D A CADT 15,713,219 7,763, ,031 2,822, ,685 2,230,362 1,256,123 65,213 14, ,342 - NCP - Primary OH 40 P D A CADP 7,225,787 3,568, ,359 1,297,320 65,578 1,025, ,910 30,256 6, ,530 - NCP - Subtransmission UG 41 T D A CADT 19,221,983 9,497,042 1,094,891 3,453, ,547 2,728,402 1,536,615 79,775 17, ,205 - NCP - Primary UG 42 P D A CADP 8,839,306 4,364, ,216 1,587,012 80,222 1,253, ,627 37,012 8, , Discretionary Revs 44 C (9,030,000) (3,600,000) (830,000) (4,600,000) Sales Revenues 45 C

93 APPENDIX 2 EXPENSE AND REVENUE ALLOCATION REPORT November 19, 2018 MRW & Associates, LLC

94 Draft Expense and Revenue Allocation Report October 10, 2018

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96 TABLE OF CONTENTS 1 Introduction MID Overview A&G Allocation Methodology A&G Allocation Methods Strengths and Weaknesses of Different Allocation Methods: A&G Allocation Approach Domestic Water Electric and Irrigation Recommended Allocation Factors Utility Factors Calculation Methodology Direct Expenses Factor Direct Revenues Factor Number of Employees Factor Gross Plant in Service Factor Calculation Methodology Applied Using the 2018 Budget Discretionary Revenue Other Revenues Wholesale Power Revenues Interfunctional Value Value of Electric Transmission Along Irrigation Canals Value of Hydroelectric Power from Don Pedro Hydropower Valuation Methodology Implementation Projected Value Applying Allocation Methodology Recommended Allocation of Expenses Recommendations Applied to the 2018 Budget Domestic Water Results Irrigation Results Electric Enterprise Reserve Policy Recommendation Conclusion... 13

97 LIST OF TABLES Table 1: 2016 Actuals Allocation Factors... 4 Table 2: 2016 Budget Allocation Factors... 5 Table 3: Utility Factor Calculation (2018 Budget)... 6 Table 4: Right of Way Width Calculation... 8 Table 5: 2018 Right of Way Value Calculation... 9 Table 6: Projected Value of Energy and Capacity from Don Pedro (2018) Table 7: Net Revenues by Service Line APPENDICES APPENDIX A: Tables

98 1 INTRODUCTION The Modesto Irrigation District (MID) has three distinct lines of service; providing electricity to retail customers (Electric), providing water to irrigation customers (Irrigation), and providing treated water to the City of Modesto (Domestic Water). MID hired consultants from Bartle Wells Associates and (MRW and Associates) MRW to (1) recommend a framework for allocating revenues and expenses between its lines of service, (2) apply this framework to MID s 2018 budget, and (3) identify whether current rates comply with Proposition 26 requirements. Proposition 26 requires that rates collected for one line of service not subsidize another line of service. The consulting team created an allocation framework for MID s lines of service with three primary objectives: 1. Ensure the revenues and expenses benefitting only one line of service are being directly allocated to that line of service. 2. Identify expense and revenue categories which benefit multiple lines of service and make sure they are being reasonably split between the lines. 3. Identify and quantify the value one line of service may be providing another line of service. The following report explains the consulting team s recommendations for a framework to use going forward and presents the results from applying the recommended framework to the 2018 budget. 1.1 MID Overview MID was established as the second irrigation district in California in 1887 to provide irrigation water to the Central Valley In 1923, after completion of the original Don Pedro Dam, MID began generating and selling electricity. In 1994 MID began providing potable water to the City of Modesto. Today MID provides irrigation water to about 3,100 accounts irrigating over 100,000 acres, electric service to about 123,000 accounts located over 560 square miles, and one third of the water supply serving the City of Modesto s 73,000 accounts. 2 A&G ALLOCATION METHODOLOGY MID incurs expenses and receives revenues for various activities that benefit multiple lines of service. These revenues and expenses are categorized as Administrative and General (A&G). Examples of A&G activities are: Legal Salaries for administrative staff Regulatory administration 1 P age

99 Human resources Information technology Billing Call center and other customer services Building services Because A&G cannot be directly assigned to Electric, Irrigation, and Domestic Water it is necessary to allocate A&G to each line of service. 2.1 A&G Allocation Methods There are a number of approaches that can be taken to allocate A&G to different lines of service. Generally accepted approaches include: Allocation based on input from functional area: Examples of functional areas are information technology and finance. Under this approach, employees in each functional area providing A&G services to the utility are surveyed and asked to allocate the benefit their area provides to each line of service. A typical approach would be to survey managers of each specific department and have the managers develop allocation factors for different A&G categories under their control. MID currently uses this approach to allocate A&G to Domestic Water. 1 Allocation based on factor(s): Under this approach, A&G costs that cannot be directly assigned to a function are allocated based on factors that are deemed representative of the appropriate split of costs between functions. Examples of such allocators are operating and maintenance (O&M) costs by function, revenue by function, and the size of each line of service (e.g., gross plant, number of employees). Both approaches have been used by other utilities with multiple lines of service to allocate A&G Strengths and Weaknesses of Different Allocation Methods: The following section discusses the strengths and weaknesses for each method for allocating A&G. Allocation based on input from functional area: This approach relies on the expertise of a utility s departmental managers to develop allocation factors by department. This is both a strength and a weakness to the approach. It is a strength because the utility s managers should have a good understanding of how much time and effort their individual departments spend supporting the work of the utility s different lines of business. This approach allows for greater detail because there can be specific allocations for each line item of A&G in the budget. However, this approach is based on an individual s judgement which can be subjective. This potential weakness is mitigated by having additional review of the final allocations. 1 Based on information provided by MID 2 P age

100 Allocation based on factor(s): This approach removes potential subjectivity from the allocation of A&G to function as it is completely transparent. A challenge presented by this approach is the factors are one size fits all for each A&G line item in the budget. This can make it difficult to determine the appropriate allocation factor(s). It is important to select one or more factor(s) that are indicative of the size of the utility and the degree to which each function within the utility relies on unassigned A&G. 2.2 A&G Allocation Approach Domestic Water The consulting team believes it is reasonable to continue to identify Domestic Water A&G expenses based on input from functional area (manager surveys) for the following reasons: Domestic Water operations are relatively new and distinct when compared to Irrigation and Electric operations which have been intertwined for almost a century. Domestic Water operations are geographically distinct because they occur at the Modesto Regional Water Treatment Plant. The water treatment plant s only purpose is to serve Domestic Water. Domestic Water A&G is transparent as it is reviewed by the City of Modesto. Domestic Water s portions of A&G expenses are shown in Table 4 of the Appendix in the column DW A&G %. The contractual arrangement with the City of Modesto is structured so that Domestic Water A&G expenses are paid based on the budget and are trued up annually based on actual costs. The consulting team recommends Domestic Water A&G expenses and the corresponding reimbursement from the City be treated as A&G by Electric and Irrigation Electric and Irrigation In order to ensure compliance with Proposition 26, the consulting team recommends MID use allocation factor(s) for the assignment of A&G to Electric and Irrigation. The reasons for this are: Transparency: The allocation of A&G can be a complex matter in utility ratemaking. In order to ensure that the assignment process is clear and unambiguous, it is necessary to exclude subjective decisions by utility managers from the process. The transparency ensures that the assignment is done based on publicly available data. Accepted Practice: Allocation of A&G using so called utility factors has been used by many utilities. It is the accepted approach used at the Federal Energy Regulatory Commission. 2 It is 2 Accounting for Public Utilities, Hahne and Aliff, Chapter P age

101 also been used in ratemaking by San Diego Gas & Electric at the California Public Utilities Commission Recommended Allocation Factors The consulting team tested various possible allocation factors using MID s 2016 budget and 2016 actuals. These factors included allocations based on revenue, O&M, gross plant in service, and number of employees. Based on this review, the consulting team recommends using a four factor allocation method based on revenue, O&M, gross plant in service, and number of employees. This allocation scheme has been used by many combination utilities including San Diego Gas & Electric. It allocates slightly more A&G to Electric than the approach based on input from managers. This is appropriate given the much larger gross plant, O&M expenses and rate revenues for Electric when compared to Irrigation. The following tables summarize the allocators based on different factors: Table 1: Test Allocation Factors (2016 Actual) Electric and Irrigation Only Electric Irrigation 2016 Revenue 99% 1% 2016 O&M 82% 18% Number of employees in % 19% 2016 Gross plant in service 95% 5% Average of O&M, employees, revenue, and gross plant in service 89% 11% 3 For example, see Direct Testimony of Mark A. Diancin: Shared Services and Shared Assets Billing Policies and Process, SDG&E s 2016 General Rate Case, Exhibit SDG&E 26, November Page

102 Table 2: Test Allocation Factors (2016 Budget) Electric and Irrigation Only Electric Irrigation 2016 Revenue 99% 1% 2016 O&M 84% 16% Number of employees in % 18% 2016 Gross plant in service 95% 5% Average of O&M, employees, revenue, and gross plant in service 90% 10% 2.3 Utility Factors Calculation Methodology The consulting team recommends using a three year average for each factor to make the results more predictable. The recommended methodology for each factor is as follows: Direct Expenses Factor Each expense line item in the MID financial system was reviewed and categorized as Irrigation, Electric, or A&G. The sum of direct expenses for Electric and Irrigation, less Domestic Water A&G expenses, in each year are included in the direct expenses factor calculation. The consulting team recommends using a three year average which includes the budget year for this factor because budgeted expenses are used to calculate user fees and reflect any operational changes planned for the next year. This calculation is shown in detail in Appendix A, Table Direct Revenues Factor Each revenue line item in the MID financial system was reviewed and categorized as Irrigation, Electric, or A&G. The sum of direct revenues for Electric and Irrigation in each year are included in the direct revenues factor calculation. The consulting team recommends using a three year average which includes the budget year for this factor because budgeted expenses are used to calculate user fees and reflect any operational changes planned for the next year. This calculation is shown in detail in Appendix A, Table Number of Employees Factor MID staff provided the count of employees by line of service in each year. The consulting team recommends using a three year average which excludes the budget year for this factor because the actual staffing levels have remained consistent over time. This calculation is shown in detail in Appendix A, Table Gross Plant in Service Factor MID staff provided the gross plant in service by line of service in each year. The consulting team recommends using a three year average which excludes the budget year for this factor because gross plant has remained consistent over time. This calculation is shown in detail in Appendix A, Table 3 5 P age

103 2.3.5 Calculation Methodology Applied Using the 2018 Budget The following table applies the factor calculation methodology discussed above to the 2018 budget year. The outcomes of the utility factors calculation are an A&G allocation factor of percent for Electric and percent for Irrigation. Table 3: Utility Factor Calculation (2018 Budget) Utility Factor Calculation 2018 Budget 3 Year Factor Category Average Factors Actual Actual Actual Budget Year Range % Direct Expenses Electric $57,842,788 $59,173,997 $61,319,652 $69,095,245 $63,196, % Irrigation $11,204,076 $10,746,963 $10,936,571 $12,926,059 $11,536, % $69,046,863 $69,920,960 $72,256,223 $82,021,304 $74,732,829 Direct Revenues Electric $373,318,406 $367,495,543 $375,096,457 $368,300,513 $370,297, % Irrigation $6,087,760 $5,602,645 $5,687,851 $7,486,306 $6,258, % $379,406,166 $373,098,188 $380,784,308 $375,786,819 $376,556,438 Number of Employees Electric % Irrigation % Plant in Service Electric $928,772,407 $946,144,508 $982,000,000 $952,305, % Irrigation $53,633,318 $54,508,543 $55,800,000 $54,647, % $982,405,725 $1,000,653,051 $1,037,800,000 $1,006,952,925 Line of Service Utility Factor Electric 89.73% Irrigation 10.27% 3 DISCRETIONARY REVENUE Some revenues MID receives may reasonably be considered discretionary. The consulting team worked with MID s attorney to identify these revenues. Total discretionary revenues are shown in Appendix A, Table 6. 6 P age

104 3.1 Other Revenues The consulting team concludes that some line items under the category Other Revenue in the MID budget may be considered discretionary by MID s Board of Directors. The noted line items are as follows: PRJ Fiber Optic Revenue o This revenue is rent paid to run fiber optic lines on MID property. The consulting team concludes that it is reasonable to treat income from rents as discretionary. PRJ Interest Income o The consulting team recommends Interest identified as direct should be allocated directly but all other interest should be treated as discretionary based on California Government Code section 53647, which allows interest revenue to be used for general fund purposes. PRJ Late Penalties o Late penalties are not fees for a service and may be considered discretionary. PRJ Rental of District Property o The consulting team concludes it is reasonable to treat income from rents as discretionary. PRJ Warehouse Sales o Warehouse sales are essentially windfall revenue, as the items sold are usually completely depreciated and would be disposed of if there was no buyer. It reasonable to consider windfall revenue as discretionary. The outcome of applying these recommendations to MID s 2018 budget is $6.5 million of discretionary revenue. 3.2 Wholesale Power Revenues Based on the recent California Supreme Court ruling in Citizens for Fair REU Rates v. City of Redding, 4 gross wholesale power revenues may be transferred to a utility s general fund, to be used for any lawful purpose, such as funding the cost of irrigation service. Thus, wholesale power revenues are also discretionary. The outcome of applying this recommendation to MID s 2018 budget is an additional $9.5 million of discretionary revenue. 4 INTERFUNCTIONAL VALUE When the assets of one line of service provide value to another line of service it is reasonable for the benefitting line of service to pay for that value. The consulting team reviewed MID s lines of service and identified two areas where interfunctional value is being provided and developed methodologies to quantify those values. 4 (2018) 6 Cal.5 th 1 7 P age

105 4.1 Value of Electric Transmission Along Irrigation Canals The value of the right of way along MID canals used by Electric is equal to the necessary land needed for transmission and distribution right of way multiplied by rental value of land from the Bureau of Land Management (BLM) for the MID service territory ($456.55/acre for BLM rental zone 9). 5 MID provided the number of poles on the MID canals (2,540) and the typical span between poles (300 feet). MID also provided the distribution of line miles by voltage as well as the width of right of way needed by voltage. The following table presents this information, which is used to estimate the average width of right of way on the MID system: Table 4: Right of Way Width Calculation T&D Line Voltage Level 1 T&D Distance (Miles) Percent of Total T&D Miles Right of Way Width (Feet) 12 kv % kv % kv % kv % kv % 140 1,257.8 Weighted Average Right of Way Width kv lines are not located on canals _linear_rent_schedule_0.pdf 8 P age

106 Using these inputs, we estimated the rental value of right of way used on MID s canals as $414,699. The following table summarizes the calculation: Table 5: 2018 Right of Way Value Calculation Right of Way Value Amount Poles on canals 2,580 Typical Span Between Poles (Linear Feet) 300 Right of Way (Linear Feet) 774,000 Right of Way (Miles) 147 Average Width of Right of Way (Feet) 51 Right of Way (Square Feet) 39,566,912 Square Feet per Acre 43,560 Right of Way (Acres) BLM Rental Zone 9 Rate per Acre $ Right of Way Value $414, Value of Hydroelectric Power from Don Pedro MID owns 31.54% (63 Megawatts) of the Don Pedro hydropower facility (Don Pedro) located on the Tuolumne River. Turlock Irrigation District owns the rest of the Don Pedro hydropower facility. MID uses the power from this facility to serve a portion of MID s electric load. MID s ownership of this hydropower facility is the result of Irrigation operations because the dam is historically an Irrigation asset, as is the water contained by the dam, which ultimately produces hydropower. Moreover, if MID had not developed retail electric operations it would have been able to sell its generation capacity and energy on the open market and use this revenue to fund irrigation service. The consulting team believes it is reasonable for Electric to compensate Irrigation for the value of Don Pedro hydroelectric generation capacity and generated power for the following reasons: MID s ownership of hydro generation capacity in Don Pedro only exists due to Irrigation. MID s original intent when it began generating hydropower from the Don Pedro Dam was to reduce the rates paid by Irrigation customers. MID could have opted to not make the hydro value available to retail electric customers and sold the capacity and energy on the open market. Electric benefits from the dedicated, close, green, reliable source of electricity Hydropower Valuation Methodology The consulting team recommends using the market value of energy and capacity provided by the Don Pedro hydropower facility to quantify the value of the services provided by the Don Pedro hydropower facility to MID s Electric rate payers. 9 P age

107 Using the value of energy and capacity is a bottom up approach. The unrecovered value of Don Pedro is assessed as the market value of the energy and capacity that Don Pedro provides, less the costs for relicensing of Don Pedro, A&G expenses, Don Pedro capital expenses, and other hydropower expenses that are already paid for by electric customers. The consulting team recommends using this method for the assessment of the value of services provided by Don Pedro, for the following reasons: Easy to Understand: This assessment uses simple inputs of Don Pedro s energy and capacity production and established market prices for energy and capacity. These inputs can be easily understood and changed. Transparency: As the inputs used are publicly available market prices for energy and capacity on the CAISO grid, there is little room for adjustments that could skew results one way or another. Clarity: This approach clearly demonstrates the costs of running Don Pedro and the value of services obtained from Don Pedro so there is no confusion or double counting of costs or the value of services Implementation In order to properly implement this valuation methodology, it is important to clearly define the sources for the market prices of energy and capacity and the costs related to Don Pedro that are already paid by Electric customers. Market prices of energy and capacity: MRW relied on publicly available sources for the prices of energy and capacity that would be used to value the services provided by Don Pedro. For the price of the energy, MRW used historical prices for the NP15 node from CAISO s OASIS database and Platt s Megawatt Daily. For future energy prices MRW used publicly available data from the Nodal Exchange futures reports from August For capacity, MRW relied on the resource adequacy (RA) reports from the California Public Utilities Commission for current and historic RA prices and assumed that new plants will likely not be needed to be built for capacity purposes and prices will remain relatively stable in coming years. Don Pedro costs paid by Electric customers: Any cost related to the Don Pedro Dam included in Electric s cost of service study will be netted out of the Value of Energy & Capacity. Projected flows: Several flow scenarios were reviewed, and the consulting team recommends basing the value on average flow projections for P age

108 4.2.3 Projected Value The following table shows the projected value of energy and capacity from Don Pedro in Table 6: Projected Value of Energy and Capacity from Don Pedro (2018) Don Pedro Generation Capacity Total Hydro Cost Paid by Incremental Hydro Flow Estimate Amount Energy Value Value Value Electric Value MWH $ $ $ $ $ Drought Year 64,000 $2,184,682 $1,882,508 $4,067,190 $3,023,693 $1,043,496 Dry Year 110,000 $3,754,922 $1,882,508 $5,637,430 $3,023,693 $2,613,737 Average Year 200,000 $7,472,750 $1,882,508 $9,355,258 $3,023,693 $6,331,565 Wet Year 300,000 $10,240,697 $1,882,508 $12,123,205 $3,023,693 $9,099,511 5 APPLYING ALLOCATION METHODOLOGY Recommended Allocation of Expenses The consulting team and MID staff went through each expense line of MID s 2018 budget to classify it as A&G, Electric, or Irrigation. The methodology to allocate the expenses is as follows: First, the Domestic Water A&G expense portion of each expense line item in the budget is identified and allocated to Electric and Irrigation as A&G based on the utility factors. Next, the remaining expense in each budget line item is allocated as it was reclassified; to either Electric, Irrigation, or A&G. The complete, reclassified 2018 budget is attached in Appendix A, Table Recommended Allocation of Other Revenues Actual revenues for each line item under the Other Revenue category in the MID budget are recorded to the line of service tied to the revenue. If the revenue is not related to a specific line of service it is recorded as A&G. The consulting team recommends projecting the split of budgeted revenue to each line of service for rate making purposes. The team recommends basing the projected split on the percentage of the last three years of recorded actual revenues to minimize anomalies. This process was performed for the 2018 budget and is found in Appendix A, Table P age

109 6 RECOMMENDATIONS APPLIED TO THE 2018 BUDGET The consulting team s recommended allocation framework was applied to MID s 2018 budget. The net revenues were calculated to test whether each line of service could operate without needing additional rate revenue. If the sum of negative net revenues for each line of service are less than MID s total available discretionary revenue, no line of service will need a rate increase in order to fund the cost of service. The following table exhibits the result of this exercise. Table 7: Net Revenues by Service Line Projected Net Revenue Electric Fund Domestic Water Results The net revenue of Domestic Water is zero. This is expected because the City of Modesto is contractually obligated to reimburse MID for all expenses Irrigation Results Irrigation Fund Domestic Water Discretionary Fund 2018 Budget $ Millions $ Millions $ Millions $ Millions Source of Funds Rate Revenue $356.8 $4.1 Other Revenue Direct 1 $7.1 $10.2 $19.3 A&G $4.6 $0.5 $3.3 Discretionary $9.0 $6.5 $16.0 Total Source of Funds $377.5 $21.3 $22.6 $16.0 Use of Funds O&M 1 $249.1 $12.9 $8.7 A&G $41.0 $4.7 $3.3 Capital $6.5 $3.7 $10.6 Debt Service $94.6 Discretionary Transfer $15.5 Total Use of Funds $391.2 $21.3 $22.6 $15.5 Net (Rev Exp) $13.7 $0.0 $0.0 $0.5 1 Includes Canal Right of Way and Don Pedro Hydro Electric Value After applying the allocation framework Irrigation requires $6.5 million of the identified $16.0 million of discretionary revenues to have zero net revenue. Irrigation could select to finance the 2018 capital projects. Assuming a thirty year term with a 4.5% interest rate, projected annual debt service payments for the budgeted capital in 2018 would be 12 P age

110 $0.2 million. This option would allow the MID Board to use $3.5 million of the discretionary revenues for other purposes while maintaining zero net revenue for Irrigation Electric Enterprise Electric is projected to have net revenues of $13.7 million. The negative net revenue is due to MID s planned defeasance of outstanding debt. 7 RESERVE POLICY RECOMMENDATION The consulting team recommends that MID begin to track a separate reserve balance for each line of service and a balance for discretionary funds. This will ensure that rate revenue from one line of service does not benefit another line of service. Based on the recent California Supreme Court ruling in the Citizens for Fair REU Rates v. City of Redding the consulting team recommends MID track surpluses from the sale of wholesale power in the discretionary reserve balance. 8 CONCLUSION The consulting team made recommendations which provide MID a reasonable framework to fairly apportion revenues and expenses to each line of service. The recommendations are as follows: Use the identified direct Electric and Irrigation revenue and expense categories Use a three year average of actual other revenue to allocate budgeted other revenue Continue allocating Domestic Water A&G using the manager survey method Use the Utility Factor method to allocate A&G between Electric and Irrigation Have Electric and Irrigation treat Domestic Water A&G expenses and revenues as A&G Electric should transfer an amount to Irrigation based on the recommended Don Pedro hydro value methodology Electric should transfer an amount to Irrigation for the value of transmission right of way on irrigation canals based on BLM rates. These recommendations allow each line of service to reasonably account for all revenues and expenses when setting rates for that service. The consulting team applied the recommended framework to MID s 2018 budget and found that there are sufficient discretionary revenues to allow each line of service to be in compliance with Proposition 26 without raising Electric or Irrigation rates. 13 P age

111 APPENDIX A 14 P age

112 MID Allocation Report Table 1 Expenses for Utility Factors Expenses Less A&G 1 MID Expenses for Utility Factors Actual Actual Actual Budget PRJ Board of Directors PRJ Board Secretary Office PRJ Legal Counsel PRJ Legal Claims PRJ MID Water Rights PRJ SED Litigation OM BOARD OF DIRECTORS DIVISION PRJ General Manager PRJ Regulatory Administration PRJ District Seminar & Meetings PRJ Public Affairs PRJ Project Management PRJ Public Inform Canal Safety PRJ Public Inform Elect Safety PRJ Community Service PRJ Safety/Environmental Compliance Admin PRJ Safety PRJ Environmental OM GENERAL MANAGER DIVISION PRJ Human Resources PRJ Training PRJ Recruitments PRJ Employee Programs PRJ Retirement Administration OM HUMAN RESOURCES DIVISION PRJ IT Administration Line of Service Allocation

113 MID Allocation Report Table 1 Expenses for Utility Factors Expenses Less A&G 1 MID Expenses for Utility Factors Actual Actual Actual Budget Line of Service Allocation PRJ IT Systems Support PRJ IT Applications Business Support PRJ IT Applications Operations Support PRJ Technical Operations PRJ Network/Desktop Support PRJ IT Security OM INFORMATION TECHNOLOGY DIVISION PRJ Finance Admin PRJ Employee Cost Savings Prog PRJ Treasurer PRJ Financing Related Expense PRJ Retirement Investment Expense PRJ Pricing/Risk Management PRJ Budget/Rates Administrator PRJ Controller PRJ Accounting PRJ Customer Services Admin $265,071 $282,212 $264,566 $719,427 Electric PRJ Billing 1,856,532 2,550,870 2,578,976 2,625,030 Electric PRJ Call Center 1,537,088 1,359,225 1,615,338 1,940,600 Electric PRJ Cash Accounting 1,717,015 1,717,291 1,546,855 1,838,038 Electric PRJ Risk & Property PRJ Building Services PRJ Purchasing PRJ Materials Handling PRJ Equipment Clearing PRJ Fleet Maintenance PRJ Vehicles & Equipment

114 MID Allocation Report Table 1 Expenses for Utility Factors Expenses Less A&G 1 MID Expenses for Utility Factors Actual Actual Actual Budget Line of Service Allocation PRJ Energy Services 237, , ,051 1,798,867 Electric PRJ Marketing 533, , ,310 Electric PRJ Public Benefits 457, , ,628 Electric PRJ Energy Management 2,610,609 1,883,723 1,825,899 4,258,182 Electric PRJ Solar Photovoltaic 544,897 Electric PRJ Solar Photovoltaic PBI 3,274,395 3,162,998 2,656,627 2,500,000 Electric OM FINANCE DIVISION PRJ Claims/Other Write Offs PRJ Don Pedro Rec Agency Expense 377, , , ,233 Irrigation PRJ Electric Retail Write Offs 751,278 1,370, ,476 2,300,000 Electric PRJ Insurance PRJ Permission and Municipal Fees 486, , , ,000 Electric PRJ Retiree Medical Expense PRJ Basic Unfunded Liability Amort. PRJ Warehouse Sales Cost PRJ WBO Costs OM OTHER E PENSES DIVISION PRJ Electric Resources Admin 868,638 1,046,195 1,263,657 1,123,913 Electric PRJ Electric Resources/Planning 2,677,024 2,371,782 2,180,100 3,599,960 Electric PRJ Operations Admin 743, , ,010 1,397,445 Electric PRJ Power Scheduling 2,719,891 2,754,313 2,819,378 2,939,494 Electric PRJ Control Center Dispatching 3,423,967 3,357,578 3,245,042 3,320,424 Electric OM ELECTRIC RESOURCES DIVISION PRJ Transmission & Dist Admin 549, , , ,777 Electric PRJ General Engineering 463, , , ,817 Electric PRJ Trans/Dist Planning 523, , , ,312 Electric PRJ Trans/Dist Engineering 557, , , ,557 Electric

115 MID Allocation Report Table 1 Expenses for Utility Factors Expenses Less A&G 1 MID Expenses for Utility Factors Actual Actual Actual Budget Line of Service Allocation PRJ Substation Engineering 430, , , ,013 Electric PRJ Mapping/Records 685, , , ,007 Electric PRJ Trouble General Maintenance 1,617,735 1,650,932 1,881,818 2,121,401 Electric PRJ Turn on/turn off 12,121 15,314 4,511 21,061 Electric PRJ Street Lighting 99,040 94,344 89,908 93,411 Electric PRJ Vegetation Management 1,731,542 1,800,491 1,943,198 1,978,416 Electric PRJ Trouble Administration 448, , , ,640 Electric PRJ Inspections 650, , , ,423 Electric PRJ Line Construction Admin 1,147,854 1,069,350 1,077,958 1,165,551 Electric PRJ LC Overhead Transmission 71, , , ,497 Electric PRJ LC Overhead Distrib Maint 819,372 1,078,794 1,067,188 1,622,501 Electric PRJ Line Construction General 674, , ,087 1,148,326 Electric PRJ LC Underground Distribution 880,174 1,075, ,421 1,184,756 Electric PRJ Insulating Equipment 15,886 8,873 19,452 26,500 Electric PRJ Substation 725, , , ,433 Electric PRJ Transmission Substation 884, ,680 1,356,286 1,958,666 Electric PRJ Distribution Substation 1,597,378 1,990,451 2,220,325 3,411,888 Electric PRJ Maintenance of Relays 1,082, , ,165 1,272,141 Electric PRJ Meter Transformer 425, , , ,796 Electric PRJ Meter Maintenance 1,406,758 1,552,749 1,466,600 1,602,797 Electric PRJ Transformer Maintenance 201, , , ,193 Electric PRJ LM Receiver Maintenance 14,816 20,557 22,238 80,524 Electric OM ELECTRIC TRANSMISSION AND DISTRIBUTION DIVISION PRJ Water Operations Admin 339, , , ,249 Irrigation PRJ Water Rights 363, , , ,026 Irrigation PRJ Irrigation System Improvements 296, , , ,000 Irrigation PRJ LaGrange Water System 261, , ,465 90,000 Irrigation

116 MID Allocation Report Table 1 Expenses for Utility Factors Expenses Less A&G 1 MID Expenses for Utility Factors Actual Actual Actual Budget Line of Service Allocation PRJ Civil Engineering 568, , , ,770 Irrigation PRJ Surveying 337, , , ,976 Irrigation PRJ Conservation Improvements 57, , , ,824 Irrigation PRJ Water Measurement 91,851 31,046 30, ,497 Irrigation PRJ Water Data & Analysis 115, , , ,225 Irrigation PRJ Ground Water Management 7,317 13,730 10,893 64,675 Irrigation PRJ Don Pedro Watershed 171, , , ,515 Irrigation PRJ Irrigation Admin 686, , , ,034 Irrigation PRJ Irrigation Services 1,740,077 1,663,100 1,844,024 1,885,639 Irrigation PRJ La Grange 53,417 9,282 23,983 40,216 Irrigation PRJ Upper Main Canal 113, , , ,955 Irrigation PRJ Modesto Reservoir 99, , , ,964 Irrigation PRJ Pumps 1,746, , , ,832 Irrigation PRJ Laterals and Ditches 1,723,004 2,127,523 2,606,855 2,542,798 Irrigation PRJ Gunite 897, , , ,531 Irrigation PRJ Irrigation Pipelines 116, , , ,095 Irrigation PRJ Structures 158, ,669 47, ,431 Irrigation PRJ Weed & Moss Control 739, ,876 1,057,717 1,121,285 Irrigation PRJ Landscaping 141, , , ,291 Irrigation OM WATER OPERATIONS DIVISION PRJ Domestic Water Admin PRJ Domestic Water A&G PRJ Domestic Water Operations PRJ Domestic Water Laboratory PRJ Domestic Water Maintenance OM DOMESTIC WATER DIVISION District OM

117 MID Allocation Report Table 1 Expenses for Utility Factors Expenses Less A&G 1 MID Expenses for Utility Factors Actual Actual Actual Budget Line of Service Allocation PS Purchase Power PRJ Generation Admin 591, , , ,898 Electric PRJ Don Pedro Generation O&M 905,337 1,021,590 1,246,412 1,150,000 Electric PRJ New Hogan O&M 60,684 74,080 96,118 88,393 Electric PRJ Stone Drop O&M 24,248 27,239 12,858 33,585 Electric PRJ McClure O&M 741, , ,126 1,120,818 Electric PRJ Woodland Operations 7,188,979 6,448,031 3,744,285 4,516,162 Electric PRJ Woodland Maintenance 4,346,406 4,987,257 10,196,166 4,484,405 Electric PRJ Ripon O&M $1,561,887 $1,972,243 $1,808,439 $1,959,200 Electric PS Generation O&M PS Generation Fuel District Power Supply 1 A&G includes Domestic Water A&G

118 MID Allocation Report Table 2 Revenues for Utility Factors MID Revenues for Utility Factors Line of Service Actual Actual Actual Budget PRJ Electric Wholesale Rev $16,018,000 $7,103,000 $8,254,015 $9,538,133 PRJ El Transmission Rev Retail 2,330,256 1,100,873 2,500,132 Electric PRJ Electric Operating Revenue 328,589, ,420, ,425, ,762,941 Electric PRJ Environmental Energy Adjustment 17,038,459 20,364,576 18,935,184 18,998,567 Electric PRJ Greenhouse Gases Adjustment PRJ Capital Infrastructure Adjustment 6,969,393 7,030,642 7,107,664 7,040,872 Electric Electric Revenue PRJ Raw Water Revenue 4,527,774 3,574,421 3,769,469 4,082,743 Irrigation PRJ FERC Instream Flow Revenue 1,334,891 1,477,205 1,532,879 1,620,812 Irrigation PRJ Domestic Water Revenue PRJ Storm Water Revenue 1,441,051 Irrigation Water Revenue PRJ Customer Services Fees Rev 1,853,645 1,916,462 1,239,042 1,400,000 Electric PRJ Don Pedro Rec Agency Revenue 225, , , ,700 Irrigation PRJ DW Admin Fees Revenue PRJ Facilities Charge 519, , , ,000 Electric PRJ Fiber Optic Revenue PRJ Gain or Loss on Sale of Assets PRJ Interest Income PRJ Late Penalties PRJ Misc. Cost Recovery PRJ Misc. Operating Income PRJ Other Entities Admin Fees Revenue PRJ Rental of District Property PRJ Retirement Fund Revenue PRJ Revenue Aid to Construction PRJ Warehouse Sales PRJ WBO Income Rev Other Revenues

119 MID Allocation Report Table 3 Utility Factors Calculation Utility Factor Calculation 2018 Budget 3 Year Factor Category Average Factors Actual Actual Actual Budget Year Range % Direct Expenses Electric $57,842,788 $59,173,997 $61,319,652 $69,095,245 $63,196, % Irrigation $11,204,076 $10,746,963 $10,936,571 $12,926,059 $11,536, % $69,046,863 $69,920,960 $72,256,223 $82,021,304 $74,732,829 Direct Revenues Electric $373,318,406 $367,495,543 $375,096,457 $368,300,513 $370,297, % Irrigation $6,087,760 $5,602,645 $5,687,851 $7,486,306 $6,258, % $379,406,166 $373,098,188 $380,784,308 $375,786,819 $376,556,438 Number of Employees Electric % Irrigation % Plant in Service Electric $928,772,407 $946,144,508 $982,000,000 $952,305, % Irrigation $53,633,318 $54,508,543 $55,800,000 $54,647, % $982,405,725 $1,000,653,051 $1,037,800,000 $1,006,952,925 Line of Service Utility Factor Electric 89.73% Irrigation 10.27%

120 MID Allocation Report Table Operating Expenses Allocation Category DW A&G % DW A&G Electric Expenses Irrigation Expenses 2018 Operating Expense Allocation Total Expenses PRJ Board of Directors $196,280 A&G 6.47% $12,700 $176,102 $20,178 PRJ Board Secretary Office 369,969 A&G 6.47% 23, ,936 38,033 PRJ Legal Counsel 1,699,682 A&G 30.77% 522,979 1,524, ,727 PRJ Legal Claims 1,050,000 A&G 28.57% 300, , ,940 PRJ MID Water Rights 250,000 A&G 33.33% 83, ,300 25,700 PRJ SED Litigation 0.00% OM BOARD OF DIRECTORS DIVISION 3,565,931 PRJ General Manager 684,982 A&G 20.00% 136, ,566 70,416 PRJ Regulatory Administration 951,779 A&G 5.88% 55, ,937 97,843 PRJ District Seminar & Meetings 236,000 A&G 5.45% 12, ,739 24,261 PRJ Public Affairs 907,341 A&G 6.00% 54, ,067 93,275 PRJ Project Management A&G 25.00% PRJ Public Inform Canal Safety 281,500 A&G 6.00% 16, ,562 28,938 PRJ Public Inform Elect Safety 187,450 A&G 6.00% 11, ,180 19,270 PRJ Community Service 36,000 A&G 6.00% 2,160 32,299 3,701 PRJ Safety/Environmental Compliance Admin 351,717 A&G 0.00% 315,561 36,157 PRJ Safety 605,857 A&G 0.00% 543,575 62,282 PRJ Environmental 469,015 A&G 0.00% 420,801 48,215 OM GENERAL MANAGER DIVISION 4,711,642 PRJ Human Resources 801,342 A&G 6.25% 50, ,964 82,378 PRJ Training 439,812 A&G 6.25% 27, ,599 45,213 PRJ Recruitments 567,062 A&G 6.25% 35, ,768 58,294 PRJ Employee Programs 135,698 A&G 6.25% 8, ,748 13,950 PRJ Retirement Administration 437,746 A&G 6.06% 26, ,745 45,000 OM HUMAN RESOURCES DIVISION 2,381,660 PRJ IT Administration 5,751,327 A&G 2.14% 123,358 5,160, ,236 PRJ IT Systems Support 2,513,836 A&G 2.00% 50,277 2,255, ,422 PRJ IT Applications Business Support 2,605,888 A&G 2.00% 52,118 2,338, ,885 PRJ IT Applications Operations Support A&G 0.00% PRJ Technical Operations 1,268,633 A&G 2.00% 25,373 1,138, ,416 PRJ Network/Desktop Support 910,144 A&G 2.00% 18, ,581 93,563

121 MID Allocation Report Table Operating Expenses 2018 Operating Expense Allocation Total Expenses Allocation Category DW A&G % DW A&G Electric Expenses Irrigation Expenses PRJ IT Security A&G 0.00% OM INFORMATION TECHNOLOGY DIVISION 13,049,829 PRJ Finance Admin 283,580 A&G 5.45% 15, ,428 29,152 PRJ Employee Cost Savings Prog PRJ Treasurer 380,060 A&G 5.45% 20, ,990 39,070 PRJ Financing Related Expense 126,000 A&G 0.00% 113,047 12,953 PRJ Retirement Investment Expense 1,002,500 A&G 6.50% 65, , ,057 PRJ Pricing/Risk Management 616,845 A&G 8.00% 49, ,433 63,412 PRJ Budget/Rates Administrator A&G PRJ Controller 649,871 A&G 5.45% 35, ,064 66,807 PRJ Accounting 1,075,932 A&G 5.45% 58, , ,606 PRJ Customer Services Admin 719,427 Electric 0.00% 719,427 PRJ Billing 2,625,030 Electric 0.00% 2,625,030 PRJ Call Center 1,940,600 Electric 0.00% 1,940,600 PRJ Cash Accounting 1,838,038 Electric 0.00% 1,838,038 PRJ Risk & Property 1,146,916 A&G 5.45% 62,492 1,029, ,903 PRJ Building Services 1,995,522 A&G 5.30% 105,696 1,790, ,140 PRJ Purchasing 671,152 A&G 2.41% 16, ,158 68,994 PRJ Materials Handling 804,714 A&G 0.00% 721,990 82,725 PRJ Equipment Clearing (3,013,357) A&G 0.00% (2,703,584) (309,773) PRJ Fleet Maintenance 636,579 A&G 1.43% 9, ,138 65,440 PRJ Vehicles & Equipment 2,376,778 A&G 0.00% 2,132, ,333 PRJ Energy Services 1,798,867 Electric 0.00% 1,798,867 PRJ Marketing Electric 0.00% PRJ Public Benefits Electric 0.00% PRJ Energy Management 4,258,182 Electric 0.00% 4,258,182 PRJ Solar Photovoltaic Electric PRJ Solar Photovoltaic PBI 2,500,000 Electric 0.00% 2,500,000 OM FINANCE DIVISION 24,433,236 PRJ Claims/Other Write Offs 251,100 A&G 0.00% 225,287 25,813 PRJ Don Pedro Rec Agency Expense 503,233 Irrigation 0.00% 503,233

122 MID Allocation Report Table Operating Expenses 2018 Operating Expense Allocation Total Expenses Allocation Category DW A&G % DW A&G Electric Expenses Irrigation Expenses PRJ Electric Retail Write Offs 2,300,000 Electric 0.00% 2,300,000 PRJ Insurance 2,002,326 A&G 0.00% 1,796, ,839 PRJ Permission and Municipal Fees 600,000 Electric 0.00% 600,000 PRJ Retiree Medical Expense 8,972,000 A&G 5.45% 488,859 8,049, ,322 PRJ Basic Unfunded Liability Amort. A&G 0.00% PRJ Warehouse Sales Cost 5,000 A&G 0.00% 4, PRJ WBO Costs 1,375,000 A&G 0.00% 1,233, ,350 OM OTHER E PENSES DIVISION 16,008,659 PRJ Electric Resources Admin 1,123,913 Electric 0.00% 1,123,913 PRJ Electric Resources/Planning 3,599,960 Electric 0.00% 3,599,960 PRJ Operations Admin 1,397,445 Electric 0.00% 1,397,445 PRJ Power Scheduling 2,939,494 Electric 0.00% 2,939,494 PRJ Control Center Dispatching 3,320,424 Electric 0.00% 3,320,424 OM ELECTRIC RESOURCES DIVISION 12,381,237 PRJ Transmission & Dist Admin 267,777 Electric 0.00% 267,777 PRJ General Engineering 980,817 Electric 0.00% 980,817 PRJ Trans/Dist Planning 669,312 Electric 0.00% 669,312 PRJ Trans/Dist Engineering 571,557 Electric 0.00% 571,557 PRJ Substation Engineering 598,013 Electric 0.00% 598,013 PRJ Mapping/Records 830,007 Electric 0.00% 830,007 PRJ Trouble General Maintenance 2,121,401 Electric 0.00% 2,121,401 PRJ Turn on/turn off 21,061 Electric 0.00% 21,061 PRJ Street Lighting 93,411 Electric 0.00% 93,411 PRJ Vegetation Management 1,978,416 Electric 0.00% 1,978,416 PRJ Trouble Administration 452,640 Electric 0.00% 452,640 PRJ Inspections 563,423 Electric 0.00% 563,423 PRJ Line Construction Admin 1,165,551 Electric 0.00% 1,165,551 PRJ LC Overhead Transmission 176,497 Electric 0.00% 176,497 PRJ LC Overhead Distrib Maint 1,622,501 Electric 0.00% 1,622,501 PRJ Line Construction General 1,148,326 Electric 0.00% 1,148,326 PRJ LC Underground Distribution 1,184,756 Electric 0.00% 1,184,756

123 MID Allocation Report Table Operating Expenses 2018 Operating Expense Allocation Total Expenses Allocation Category DW A&G % DW A&G Electric Expenses Irrigation Expenses PRJ Insulating Equipment 26,500 Electric 0.00% 26,500 PRJ Substation 810,433 Electric 0.00% 810,433 PRJ Transmission Substation 1,958,666 Electric 0.00% 1,958,666 PRJ Distribution Substation 3,411,888 Electric 0.00% 3,411,888 PRJ Maintenance of Relays 1,272,141 Electric 0.00% 1,272,141 PRJ Meter Transformer 361,796 Electric 0.00% 361,796 PRJ Meter Maintenance 1,602,797 Electric 0.00% 1,602,797 PRJ Transformer Maintenance 247,193 Electric 0.00% 247,193 PRJ LM Receiver Maintenance 80,524 Electric 0.00% 80,524 OM ELECTRIC TRANSMISSION 24,217,402 PRJ Water Operations Admin 300,249 Irrigation 0.00% 300,249 PRJ Water Rights 772,500 Irrigation 33.33% 257, , ,494 PRJ Irrigation System Improvements 550,000 Irrigation 0.00% 550,000 PRJ LaGrange Water System 90,000 Irrigation 0.00% 90,000 PRJ Civil Engineering 933,770 Irrigation 0.00% 933,770 PRJ Surveying 502,976 Irrigation 0.00% 502,976 PRJ Conservation Improvements 143,824 Irrigation 0.00% 143,824 PRJ Water Measurement 154,497 Irrigation 0.00% 154,497 PRJ Water Data & Analysis 160,225 Irrigation 0.00% 160,225 PRJ Ground Water Management 129,349 Irrigation 50.00% 64,675 58,026 71,323 PRJ Don Pedro Watershed 444,750 Irrigation 33.33% 148, , ,753 PRJ Irrigation Admin 480,034 Irrigation 0.00% 480,034 PRJ Irrigation Services 1,885,639 Irrigation 0.00% 1,885,639 PRJ La Grange 60,321 Irrigation 33.33% 20,105 18,038 42,283 PRJ Upper Main Canal 220,421 Irrigation 33.33% 73,466 65, ,507 PRJ Modesto Reservoir 187,436 Irrigation 33.33% 62,473 56, ,386 PRJ Pumps 781,832 Irrigation 0.00% 781,832 PRJ Laterals and Ditches 2,542,798 Irrigation 0.00% 2,542,798 PRJ Gunite 973,531 Irrigation 0.00% 973,531 PRJ Irrigation Pipelines 162,095 Irrigation 0.00% 162,095 PRJ Structures 205,431 Irrigation 0.00% 205,431

124 MID Allocation Report Table Operating Expenses 2018 Operating Expense Allocation Total Expenses Allocation Category DW A&G % DW A&G Electric Expenses Irrigation Expenses PRJ Weed & Moss Control 1,121,285 Irrigation 0.00% 1,121,285 PRJ Landscaping 246,291 Irrigation 0.00% 246,291 OM WATER OPERATIONS DIVISION 13,049,254 District OM 113,798, % PS Purchase Power 150,436,193 Electric 150,436,193 PRJ Generation Admin 563,898 Electric 0.00% 563,898 PRJ Don Pedro Generation O&M 1,150,000 Electric 0.00% 1,150,000 PRJ New Hogan O&M 88,393 Electric 0.00% 88,393 PRJ Stone Drop O&M 33,585 Electric 0.00% 33,585 PRJ McClure O&M 1,120,818 Electric 0.00% 1,120,818 PRJ Woodland Operations 4,516,162 Electric 0.00% 4,516,162 PRJ Woodland Maintenance 4,484,405 Electric 0.00% 4,484,405 PRJ Ripon O&M 1,959,200 Electric 0.00% 1,959,200 PS Generation Fuel 22,827,247 Electric 22,827,247 District Power Supply $187,179, % Total Expense $300,978,752 $3,204,348 $283,355,349 $17,623,403

125 MID Allocation Report Table 5 Three Year Total Actual Other Revenue ( ) Actual Revenue by Line of Service 2 Percentage of Revenue by Function Sum of Actual Other Revenue 1 Grand Total Discretionary 3 Irrigation All as A&G Electric Discretionary Irrigation All as A&G Electric Customer Services Fees Rev $5,009,148 $0 $0 $0 $5,009, % 0.0% 0.0% 100.0% Don Pedro Rec Agency Revenue 1,161,617 1,161, % 100.0% 0.0% 0.0% DW Admin Fees Revenue 6,375,084 6,375, % 0.0% 100.0% 0.0% Facilities Charge 1,714,238 1,714, % 0.0% 0.0% 100.0% Fiber Optic Revenue 518, , % 0.0% 0.0% 0.0% Gain or Loss on Sale of Assets 268, , ,152 (79,135) 0.0% 85.5% 44.0% 29.5% Interest Income 14,154,629 7,156,076 5,643 6,992, % 0.0% 0.0% 49.4% Late Penalties 6,082,911 6,082, % 0.0% 0.0% 0.0% Misc. Cost Recovery 108, , % 0.0% 100.0% 0.0% Misc. Operating Income 3,961,957 8, ,944 3,090, % 0.2% 21.8% 78.0% Other Entities Admin Fees Revenue 2,321,926 2,321, % 0.0% 100.0% 0.0% Rental of District Property 2,778,465 2,778, % 0.0% 0.0% 0.0% Retirement Fund Revenue 2,621,105 2,621, % 0.0% 100.0% 0.0% Revenue Aid to Construction 9,233,482 9,233, % 0.0% 0.0% 100.0% Warehouse Sales 374, , % 0.0% 0.0% 0.0% WBO Income $8,918,655 $0 $135,138 $63,081 $8,720, % 1.5% 0.7% 97.8% 1 Other revenue is a budget category designated by MID 2 MID records actual Other Revenues by line of service 3 Other revenue designated digressionary are based on consulting team recommendations not the MID accounting system

126 MID Allocation Report Table 6 Budgeted 2018 Revenues Allocation Total Revenue 2018 Budgeted Revenue Allocation Total Revenue Electric Irrigation A&G Discretionary 3 Electric Irrigation Discretionary PRJ Electric Wholesale Rev $9,538, % $0 $0 $9,538,133 PRJ El Transmission Rev Retail 100.0% PRJ Electric Operating Revenue 330,762, % 330,762,941 PRJ Environmental Energy Adjustment 18,998, % 18,998,567 PRJ Greenhouse Gases Adjustment PRJ Capital Infrastructure Adjustment 7,040, % 7,040,872 Electric Revenue 366,340,513 PRJ Raw Water Revenue 4,082, % 4,082,743 PRJ FERC Instream Flow Revenue 1,620, % 1,620,812 PRJ Domestic Water Revenue 19,272,389 PRJ Storm Water Revenue 1,441, % 1,441,051 Water Revenue 26,416,995 PRJ Customer Services Fees Rev 1,400, % 0% 0.0% 0.0% 1,400,000 PRJ Don Pedro Rec Agency Revenue 341, % 100% 0.0% 0.0% 341,700 PRJ DW Admin Fees Revenue 3,297, % 0% 100.0% 0.0% 2,958, ,971 PRJ Facilities Charge 560, % 0% 0.0% 0.0% 560,000 PRJ Fiber Optic Revenue 172, % 0% 0.0% 100.0% 172,800 PRJ Gain or Loss on Sale of Assets 50, % 86% 44.0% 0.0% 4,988 45,012 PRJ Interest Income 2 4,900, % 0% 0.0% 50.6% 2,420,600 2,479,400 PRJ Late Penalties 2,650, % 0% 0.0% 100.0% 2,650,000 PRJ Misc. Cost Recovery 19, % 0% 100.0% 0.0% 17,495 2,005 PRJ Misc. Operating Income 550, % 0% 21.8% 0.0% 536,574 13,426 PRJ Other Entities Admin Fees Revenue 835, % 0% 100.0% 0.0% 749,162 85,838 PRJ Rental of District Property 1,000, % 0% 0.0% 100.0% 1,000,000 PRJ Retirement Fund Revenue 825, % 0% 100.0% 0.0% 740,190 84,810 PRJ Revenue Aid to Construction 1,000, % 0% 0.0% 0.0% 1,000,000 PRJ Warehouse Sales 150, % 0% 0.0% 100.0% 150,000 PRJ WBO Income 1,375, % 2% 0.7% 0.0% $1,353,386 $21,614 $0 Rev Other Revenues 1 $19,126,378 Total Revenue $368,543,184 $8,077,981 $15,990,333 1 Allocation percentages based on the last three years of actuals 2 Interest allocation based on California Government Code section The consulting team worked with MID s attorney to identify discretionary revenues

127 MID Allocation Report Table Net Revenues Projected Net Revenue Electric Fund Irrigation Fund Domestic Water Discretionary Fund 2018 Budget $ Millions $ Millions $ Millions $ Millions Source of Funds Rate Revenue $356.8 $4.1 Other Revenue Direct 1 $7.1 $10.2 $19.3 A&G $4.6 $0.5 $3.3 Discretionary $9.0 $6.5 $16.0 Total Source of Funds $377.5 $21.3 $22.6 $16.0 Use of Funds O&M 1 $249.1 $12.9 $8.7 A&G $41.0 $4.7 $3.3 Capital $6.5 $3.7 $10.6 Debt Service $94.6 Discretionary Transfer $15.5 Total Use of Funds $391.2 $21.3 $22.6 $15.5 Net (Rev Exp) $13.7 $0.0 $0.0 $0.5 1 Includes Canal Right of Way and Don Pedro Hydro Electric Value

128 MID Allocation Report Table 8 Don Pedro Energy Value Energy Price Don Pedro Generation (MWh) Don Pedro Energy Value ($) Year CAISO NP15 Energy Prices Inflation Index CAISO NP15 in 2018$ Drought Dry Average Wet Drought Dry Average Wet 2009 $ $ , , , ,000 $2,463,388 $4,233,947 $7,698,086 $11,547, $ $ , , , ,000 $2,624,605 $4,511,040 $8,201,892 $12,302, $ $ , , , ,000 $2,151,534 $3,697,949 $6,723,543 $10,085, $ $ , , , ,000 $1,997,672 $3,433,499 $6,242,725 $9,364, $ $ , , , ,000 $2,821,657 $4,849,722 $8,817,677 $13,226, $ $ , , , ,000 $3,187,113 $5,477,850 $9,959,727 $14,939, $ $ , , , ,000 $2,188,427 $3,761,359 $6,838,835 $10,258, $ $ , , , ,000 $1,917,548 $3,295,785 $5,992,337 $8,988, $ $ , , , ,000 $2,163,443 $3,718,417 $6,760,758 $10,141, $ $ , , , ,000 $2,391,280 $4,110,013 $7,472,750 $11,209,125

129 MID Allocation Report Table 9 Don Pedro Capacity Value Year Don Pedro Capacity (MW) Inflation Index Low Case: Cost of capacity from an existing plant Historic RA prices ($ kw Month) LOW CASE LOW CASE Capacity Prices Capacity ($ kw Year) Prices in 2018 (Nominal $) $ LOW CASE Don Pedro Capacity Value ($) High Case: Cost of capacity from a new POU built plant HIGH CASE HIGH CASE Capacity Prices Capacity Prices ($ kw Year) ($ kw Year) (2018 (Nominal $) $) HIGH CASE Don Pedro Capacity Value ($) $ $1,698,766 $73.65 $85.36 $5,292, $ $1,679,340 $74.50 $85.36 $5,292, $ $1,669,310 $76.09 $85.36 $5,292, $ $2,246,520 $77.46 $85.36 $5,292, $ $2,148,937 $78.61 $85.36 $5,292, $ $2,110,290 $80.05 $85.36 $5,292, $ $1,920,634 $81.01 $85.36 $5,292, $ $1,795,539 $82.06 $85.36 $5,292, $ $1,673,235 $83.50 $85.36 $5,292, $1,882,508 $85.36 $85.36 $5,292,229

130 MID Allocation Report Table 10 Don Pedro Cost Paid by Electric Year Don Pedro A&G 1 Don Pedro Generation 2 Capital 3 DP FERC Relicensing Actual 4 Total 2009 $253,493 $1,504,828 $6,996 $0 $1,765, $6,470 $1,318,862 $12,179 $37,245 $1,374, $805 $1,182,151 $22,921 $142,784 $1,348, $5,558 $1,212,171 $31,837 $256,502 $1,506, $10,892 $1,367,233 $63,586 $375,660 $1,817, $7,041 $1,242,443 $153,744 $496,140 $1,899, $1,092 $1,044,636 $293,004 $589,311 $1,928, $0 $1,168,096 $419,437 $729,901 $2,317, $23,578 $1,150,000 $592,666 $835,553 $2,601, $224,325 $1,150,000 $714,650 $934,718 $3,023,693 1 Consists of Electric portion PRJ MID Water Rights in 2018 dollars 2 Consists of Electric portion PRJ Don Pedro Generation O&M in 2018 dollars 3 Assumes Don Pedro capital expenses since the FERC relicensing process have been financed at 4.5% for 30 years 4 Assumes FERC relicensing costs have been financed at 4.5% for 30 years

131 MID Allocation Report Table 11 Incremental Don Pedro Hydro Value Flow Estimate Generation Amount Energy Value Capacity Value Total Hydro Value Don Pedro Cost Paid by Incremental Hydro Electric Value MWH $ $ $ $ $ Drought Year 64,000 $2,184,682 $1,882,508 $4,067,190 $3,023,693 $1,043,496 Dry Year 110,000 $3,754,922 $1,882,508 $5,637,430 $3,023,693 $2,613,737 Average Year 200,000 $7,472,750 $1,882,508 $9,355,258 $3,023,693 $6,331,565 Wet Year 300,000 $10,240,697 $1,882,508 $12,123,205 $3,023,693 $9,099,511

132 MID Allocation Report Table 12 Canal Right of Way Value T&D Line Voltage Level 1 T&D Distance (Miles) Percent of Total T&D Miles Right of Way Width (Feet) 12 kv % kv % kv % kv % kv % 140 1,257.8 Weighted Average Right of Way Width kv lines are not located on canals

133 MID Allocation Report Table 13 Canal Right of Way Value Right of Way Value Amount Poles on canals 2,580 Typical Span Between Poles (Linear Feet) 300 Right of Way (Linear Feet) 774,000 Right of Way (Miles) 147 Average Width of Right of Way (Feet) 51 Right of Way (Square Feet) 39,566,912 Square Feet per Acre 43,560 Right of Way (Acres) BLM Rental Zone 9 Rate per Acre $ Right of Way Value $414,699

134 APPENDIX 3: GLOSSARY OF TERMS Term 12CP A&G AB COS COSA CP Electric FERC GWh Hetch Hetchy kv M-S-R MID MW MWh NCP O&M PG&E PPA RPS T&D TANC Test Year WAPA Definition Average of the coincident demands for each month of the year Administrative and General Assembly Bill Cost of Service Cost of Service Analysis The sum of demands that occur at the time of (coincident with) system peak demand The Electric Business Line of MID Federal Energy Regulatory Commission gigawatt-hour Hetch Hetchy hydroelectric project kilo-volt (1000 Volts) MID, Santa Clara, and Redding Modesto Irrigation District megawatt megawatt-hour Sum of maximum demands for each customer class Operating and Maintenance Pacific Gas & Electric Company Power Purchase Agreement Renewable Portfolio Standard Transmission and Distribution Transmission Agency of Northern California MID's 2018 Budget Western Area Power Administration November 19, 2018 MRW & Associates, LLC

135 MID Cost of Service Study Modesto Irrigation District William A. Monsen and Michael G. Colantuono ater Esq. and Electric Cost of Service Update December 4, , 2017 ; WORK 1