Analysis of Impact of Mass Implementation of DER. Richard Fowler Adam Toth, PE Jeff Mueller, PE

Transcription

1 Analysis of Impact of Mass Implementation of DER Richard Fowler Adam Toth, PE Jeff Mueller, PE

2 Topics of Discussion Engineering Considerations Results of Study of High Penetration of Solar DG on Various Feeders Rate Considerations Results from Case Study on Rate Impact to the System Based on Difference Rate Structures Results from Case Study on Rate Impact to Solar DG Customers Based on Different Rate Structures Real World Example of Howard Electric Cooperative s Implementation of Residential Time of Use Demands

3 Engineering Considerations Jeff Mueller

4 Model Increasing PV Penetration Model percentage of peak feeder load as PV in 5% increments Spread PV evenly across the system Focus 75% of PV in the first one-third of the feeder Focus 75% of PV in the last one-third of the feeder Model the same PV kw generation but with shoulder month load Analyzed shoulder month demand for the minimum daylight hour demand Minimum daylight hour demand was 22-33% of the peak demand 33% of peak demand was used in the shoulder month analysis

5 Model Increasing PV Penetration Capacitors were removed and load allocation performed with substation set at 98% Power Factor Substation and downline regulator voltage set at 124V All regulators operating in Co-Generation mode All PV inverter controls set to provide Watts and no VARs Modeled up to the point where feeders start to reverse flow through the substation breaker

6 Feeders Modeled Feeder Length Peak Demand Customers Summary 2-20 miles 2,000-13,365 kw 135 2,359 Customers Feeder # miles 6,772 kw 545 Customers Feeder #2 2.0 miles 2,087 kw 135 Customers Feeder # miles 5,992 kw 878 Customers Feeder # miles 13,365 kw 2,359 Customers Feeder # miles 4,309 kw 937 Customers Feeder # miles 4,750 kw 1,007 Customers Feeder #7 6.0 miles 4,308 kw 430 Customers Feeder #8 4.8 miles 7,778 kw 827 Customers Feeder # miles 6,874 kw 1,052 Customers Feeder # miles 6,386 kw 1,018 Customers

7 Feeders Modeled Normalized Feeder Comparison 0.7 Percent of Max Feeder Length Peak Demand Customers 20.2 miles 13,365 kw 2,359 Customers Feeder Number

8 Trends Minimum Voltage Minimum voltage increases with added PV Voltage (120V base) % 10% 20% 30% 40% Percent PV

9 Trends Losses (kw) Feeder #7 Losses Feeder losses decrease in peak months but may increase in shoulder months % 10% 20% 30% 40% Peak Load - Evenly Spread Peak Load - Last Third Min Load - Evenly Spread Min Load - Last Third

10 Feeder #6 1 Normalized Feeder Comparison Percent of Max Feeder Length Peak Demand Customers Feeder Number

11 Feeder #6 Substation

12 Feeder #6 No PV Peak Loading Substation V < < V < < V < 126 V > 126

13 Feeder #6 25% PV Peak Loading Substation V < < V < < V < 126 V > 126

14 Feeder #6 Reverse Flow 25% PV Min Loading Substation V < < V < < V < 126 V > 126

15 Feeder #4 1 Normalized Feeder Comparison Percent of Max Feeder Length Peak Demand Customers Feeder Number

16 Feeder #4 Substation

17 Feeder #4 No PV Peak Loading Substation V < < V < < V < 126 V > 126

18 Feeder #4 20% PV Peak Loading First Third Substation V < < V < < V < 126 V > 126

19 Feeder #4 20% PV Peak Loading Last Third Substation V < < V < < V < 126 V > 126

20 Feeder #4 20% PV Min Loading Last Third Substation V < < V < < V < 126 V > 126

21 Feeder #4 20% PV Min Loading First Third Substation V < < V < < V < 126 V > 126

22 Short Feeders 1 Normalized Feeder Comparison Percent of Max Feeder Length Peak Demand Customers Feeder Number

23 Short Feeders #2-35% PV Min Loading Last Third #7-35% PV Min Loading Last Third

24 Impacts to Distribution System Higher penetration levels will cause reverse power flow Impact capacitor settings, regulator settings, or recloser settings Peak settings vs low load settings Change transformer taps Voltage sags/swells/flicker could be more common with high penetration levels Blink/Operation on transmission line Cloud cover Voltage reading during shoulder months Will Min Load and Max Generation be more concern than peak?

25 Future Impact for Higher Solar Penetration IEEE Standard 1547 Revisions Current Discussion at Tech Advantage Ride-Through Requirements Active Voltage and Reactive Power Control Smart Inventers Battery Technology

26 Rate Considerations Adam Toth

27 Rural Cooperative Case Study Analysis Performed from Two Distinct Perspectives Member/Consumer Cooperative Management Analyze Economic Impact on the Residential Class due to Variable: Levels of solar penetration Configurations of Residential solar facilities Billing mechanisms in place at the cooperative Service Availability charges

28 Rural Cooperative Load Details Approximately 11,000 meters 95% belong to the Residential Class Average monthly Residential consumer usage is 1,023 kwh Typical load profile in the absence of solar distributed generation Late afternoon & early evening peaking period during summer months Morning & evening peaking periods during the winter months

29 45,000 Utility Load Profile System Load (kw) 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 Summer Peak - 7/21/2017 Winter Peak - 12/19/2016 Shoulder Peak - 4/7/2017 Shoulder Day - 3/23/ Hour Beginning

30 Solar PV Generation Three distinct solar configurations utilized for analysis South facing facility on the roof at 30 tilt West facing facility on the roof at 30 tilt South facing facility with tracking capabilities at 20 tilt Generation capacity of 7 kw for each configuration Assumed installation in Springfield, MO Location carries implications for weather data Generation data collected using PVWatts Calculator (NREL)

31 7 Solar Generation Profiles 6 Generation (kw) Tracking Unit South Facing Rooftop West Facing Rooftop - (1) Hour Beginning

32 South Facing Rooftop Solar Summer Peak System Load (kw) 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000-7/21/ Hour Beginning No Solar 1% Penetration 5% Penetration 10% Penetration 20% Penetration 30% Penetration

33 South Facing Rooftop Solar Winter Peak System Load (kw) 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000-12/19/ Hour Beginning No Solar 1% Penetration 5% Penetration 10% Penetration 20% Penetration 30% Penetration

34 South Facing Rooftop Solar Shoulder Peak 4/7/ ,000 System Load (kw) 20,000 15,000 10,000 5, Hour Beginning No Solar 1% Penetration 5% Penetration 10% Penetration 20% Penetration 30% Penetration

35 South Facing Rooftop Solar Minimal Load Day System Load (kw) 20,000 15,000 10,000 5,000 - (5,000) (10,000) (15,000) 3/23/ Hour Beginning No Solar 1% Penetration 5% Penetration 10% Penetration 20% Penetration 30% Penetration

36 Rural Cooperative Economic Details Residential revenue per customer is approximately $1,616 annually Allocated operating expense per customer is approximately $1,467 annually 60.54% of expenses are attributable to wholesale power Wholesale power costs per unit sold to the Residential Class are as follows: Energy costs are $ per kwh Demand costs are $13.82 per monthly peak kw Combined costs are $ per kwh Residential consumers are billed according to a flat energy rate

37 Existing Billing Mechanism Flat Energy Rate Rate I Electric Revenue I Rate II Electric Revenue II Availability $26.00 $26.00 $10.00 $10.00 Energy $ $ $ $ Total - $ $134.68

38 Other Assumptions and Details Rates are designed to be revenue neutral in the absence of solar DG Required rate increases are calculated to maintain Gross Margin Gross Margin: Total class revenue less wholesale power costs allocated to the class Wholesale power requirement is reduced based on PV Watt output Demand and energy components of purchased power are reduced accordingly Rate impacts are analyzed at two different service availability charges $10 per month $26 per month

39 Net Metering Most common billing mechanism for DG customers Customer is billed only for net energy consumption Over-generation is credited to the customer at: The retail rate of energy in the utility The utility s avoided cost when generation exceeds consumption The analysis utilizes the retail rates for energy billing and energy credits. Average billing kwh determinants are found below Solar Facility w/o Solar West Roof Unit South Roof Unit Tracking System Average Monthly Net Energy 1,023 kwh 342 kwh 193 kwh 17 kwh

40 Net Metering Average Consumer Monthly Bill Net Metering $26 Service Charge $10 Service Charge w/o Solar $ $ West Roof Unit $62.33 $51.68 South Roof Unit $46.54 $33.57 Tracking System $27.77 $12.03

41 Net Metering Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% Net Metering Availability Charge Single Axis Tracking Percent Gross Margin Lost South Facing Rooftop West Facing Rooftop $ % 0.55% 0.33% $ % 0.73% 0.47% $ % 2.77% 1.63% $ % 3.65% 2.35% $ % 5.54% 3.25% $ % 7.31% 4.71% $ % 11.07% 6.51% $ % 14.62% 9.42% $ % 16.61% 9.76% $ % 21.93% 14.12%

42 Net Metering Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% Net Metering Availability Charge Single Axis Tracking Percent Rate Increase Required South Facing Rooftop West Facing Rooftop $ % 0.30% 0.18% $ % 0.40% 0.26% $ % 1.56% 0.91% $ % 2.07% 1.32% $ % 3.22% 1.87% $ % 4.30% 2.73% $ % 6.93% 3.97% $ % 9.36% 5.84% $ % 11.24% 6.33% $ % 15.40% 9.43%

43 Non-Coincident Demand Adds a demand component to traditional Residential billing schemes Maximum non-coincident metered demand is billed each month Analysis assumes $5 charge for maximum monthly non-coin demand Average Residential consumer registers 7.25 kw of monthly non-coin demand Customers pay a monthly service availability charge of $10 or $26 Customers are billed for their net monthly energy consumption Billing determinants for the average consumer are found below Solar Facility Average Monthly Net Energy Average Monthly Non-Coin Demand w/o Solar 1,023 kwh 7.25 kw West Roof Unit 342 kwh 7.09 kw South Roof Unit 193 kwh 7.08 kw Tracking System 17 kwh 7.08 kw

44 Non-Coincident Demand Average Consumer Monthly Bill Non-Coincident Demand $26 Service Charge $10 Service Charge w/o Solar $ $ West Roof Unit $85.64 $74.99 South Roof Unit $75.08 $62.11 Tracking System $62.56 $46.82

45 Non-Coincident Demand Impact to the Cooperative Non-Coincident Demand Solar Penetration 1% 5% 10% 20% 30% Availability Charge Single Axis Tracking Percent Gross Margin Lost South Facing Rooftop West Facing Rooftop $ % 0.16% 0.01% $ % 0.34% 0.15% $ % 0.82% 0.03% $ % 1.71% 0.76% $ % 1.64% 0.07% $ % 3.41% 1.52% $ % 3.28% 0.14% $ % 6.82% 3.05% $ % 4.91% 0.21% $ % 10.23% 4.57%

46 Non-Coincident Demand Impact to the Cooperative Non-Coincident Demand Solar Penetration 1% 5% 10% 20% 30% Availability Charge Single Axis Tracking Percent Rate Increase Required South Facing Rooftop West Facing Rooftop $ % 0.09% 0.00% $ % 0.19% 0.08% $ % 0.46% 0.02% $ % 0.95% 0.42% $ % 0.93% 0.04% $ % 1.96% 0.87% $ % 1.96% 0.08% $ % 4.16% 1.82% $ % 3.08% 0.13% $ % 6.64% 2.87%

47 Time of Use - Demand Time of Use (TOU) Rates are implemented for various reasons Provide a more accurate portrayal of cost allocation across customer classes Encourage peak load reduction with pricing signals Billing demand units based on maximum metered demand during peak hours Study s rural cooperative TOU hours are those hours beginning 7, 8, 16, 17, 18, and 19 Demand charge is $5 per unit of peak hours demand

48 Time of Use - Demand In addition to the demand billing component, customers pay: Monthly service availability charge of $10 or $26 Retail rate for net energy consumed from the grid Billing determinants for the average consumer are found below Solar Facility Average Monthly Net Energy Average Monthly TOU Demand w/o Solar 1,023 kwh 7.00 kw West Roof Unit 342 kwh 6.86 kw South Roof Unit 193 kwh 6.81 kw Tracking System 17 kwh 6.80 kw

49 TOU Demand Average Consumer Monthly Bill Time of Use - Demand $26 Service Charge $10 Service Charge w/o Solar $ $ West Roof Unit $84.91 $74.26 South Roof Unit $73.97 $60.99 Tracking System $61.22 $45.48

50 TOU Demand Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% TOU Demand Availability Charge Single Axis Tracking Percent Gross Margin Lost South Facing Rooftop West Facing Rooftop $ % 0.18% 0.02% $ % 0.36% 0.16% $ % 0.90% 0.08% $ % 1.78% 0.81% $ % 1.79% 0.17% $ % 3.56% 1.62% $ % 3.58% 0.34% $ % 7.13% 3.25% $ % 5.37% 0.50% $ % 10.69% 4.87%

51 TOU Demand Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% TOU Demand Availability Charge Single Axis Tracking Percent Rate Increase Required South Facing Rooftop West Facing Rooftop $ % 0.10% 0.01% $ % 0.19% 0.09% $ % 0.50% 0.05% $ % 1.00% 0.45% $ % 1.02% 0.09% $ % 2.05% 0.92% $ % 2.14% 0.20% $ % 4.35% 1.94% $ % 3.38% 0.31% $ % 6.96% 3.06%

52 Time of Use - Energy Goals are essentially the same as those in the TOU Demand rate Billing units are strictly units of energy Distinct on-peak and off-peak periods On-Peak period includes hours beginning 7, 8, 16, 17, 18, and 19 On-Peak energy is billed at $ Off-Peak energy is billed at $ Billing determinants for the average consumer without solar are found below Solar Facility On-Peak Energy Off-Peak Energy w/o Solar West Roof Unit South Roof Unit Tracking System 27 (10)

53 TOU Energy Average Consumer Monthly Bill Time of Use - Energy $26 Service Charge $10 Service Charge w/o Solar $ $ West Roof Unit $63.68 $52.89 South Roof Unit $63.10 $48.33 Tracking System $32.16 $15.94

54 TOU Energy Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% TOU Energy Availability Charge Single Axis Tracking Percent Gross Margin Lost South Facing Rooftop West Facing Rooftop $ % 0.33% 0.31% $ % 0.53% 0.45% $ % 1.64% 1.53% $ % 2.65% 2.27% $ % 3.27% 3.07% $ % 5.29% 4.54% $ % 6.55% 6.13% $ % 10.58% 9.08% $ % 9.82% 9.20% $ % 15.87% 13.62%

55 TOU Energy Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% TOU Energy Availability Charge Single Axis Tracking Percent Rate Increase Required South Facing Rooftop West Facing Rooftop $ % 0.18% 0.17% $ % 0.29% 0.25% $ % 0.91% 0.86% $ % 1.49% 1.27% $ % 1.88% 1.76% $ % 3.08% 2.63% $ % 3.98% 3.73% $ % 6.60% 5.62% $ % 6.35% 5.94% $ % 10.69% 9.06%

56 Two-Channel Billing Channel 1 energy is consumed from the grid by the consumer Billed at the retail rate in this analysis Channel 2 energy is consumer generation fed back onto the grid Credited at another, generally lesser, rate $0.04 in the cooperative used for analysis Billing units for the average consumer are found below Solar Facility Channel 1 Channel 2 w/o Solar 1,023 0 West Roof Unit 629 (287) South Roof Unit 608 (414) Tracking System 575 (558)

57 Two Channel Average Consumer Monthly Bill Two Channel $26 Service Charge $10 Service Charge w/o Solar $ $ West Roof Unit $81.36 $75.21 South Roof Unit $73.99 $67.50 Tracking System $64.72 $57.71

58 Two Channel Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% Two Channel Availability Charge Single Axis Tracking Percent Gross Margin Lost South Facing Rooftop West Facing Rooftop $ % 0.18% 0.07% $ % 0.27% 0.15% $ % 0.89% 0.33% $ % 1.34% 0.75% $ % 1.79% 0.65% $ % 2.68% 1.50% $ % 3.58% 1.31% $ % 5.35% 2.99% $ % 5.37% 1.96% $ % 8.03% 4.49%

59 Two Channel Impact to the Cooperative Solar Penetration 1% 5% 10% 20% 30% Two Channel Availability Charge Single Axis Tracking Percent Rate Increase Required South Facing Rooftop West Facing Rooftop $ % 0.10% 0.04% $ % 0.15% 0.08% $ % 0.50% 0.18% $ % 0.75% 0.42% $ % 1.02% 0.37% $ % 1.53% 0.85% $ % 2.14% 0.77% $ % 3.23% 1.79% $ % 3.38% 1.21% $ % 5.14% 2.81%

60 Cooperative Impact Summary South Facing Rooftop Solar Solar Penetration 1% 5% 10% 20% 30% Availability Charge Net Metering Non- Coincident Demand Percent Gross Margin Lost Time of Use Demand Time of Use Energy Two Channel $ % 0.16% 0.18% 0.33% 0.18% $ % 0.34% 0.36% 0.53% 0.27% $ % 0.82% 0.90% 1.64% 0.89% $ % 1.71% 1.78% 2.65% 1.34% $ % 1.64% 1.79% 3.27% 1.79% $ % 3.41% 3.56% 5.29% 2.68% $ % 3.28% 3.58% 6.55% 3.58% $ % 6.82% 7.13% 10.58% 5.35% $ % 4.91% 5.37% 9.82% 5.37% $ % 10.23% 10.69% 15.87% 8.03%

61 Cooperative Impact Summary South Facing Rooftop Solar Solar Penetration 1% 5% 10% 20% 30% Availability Charge Net Metering Percent Rate Increase Required Non- Coincident Demand Time of Use Demand Time of Use Energy Two Channel $ % 0.09% 0.10% 0.18% 0.10% $ % 0.19% 0.19% 0.29% 0.15% $ % 0.46% 0.50% 0.91% 0.50% $ % 0.95% 1.00% 1.49% 0.75% $ % 0.93% 1.02% 1.88% 1.02% $ % 1.96% 2.05% 3.08% 1.53% $ % 1.96% 2.14% 3.98% 2.14% $ % 4.16% 4.35% 6.60% 3.23% $ % 3.08% 3.38% 6.35% 3.38% $ % 6.64% 6.96% 10.69% 5.14%

62 Howard Electric Case Study Richard Fowler

63

64 What is Demand?

65 Why Demand Rates? Ensures each member pays their fair share. Howard Electric is not anti-solar.we are anti-subsidies. Helps to ease our poorer members subsidizing the wealthier members. Other examples of heavy peak setters: Instantaneous Water Heaters Electric Strip Heat Welders

66 Member 1 Solar Production vs. AECI's Peak 1 a.m. 2 a.m. 3 a.m. 4 a.m. 5 a.m. 6 a.m. 7 a.m. 8 a.m. 9 a.m. 10 a.m. 11 a.m. 12 p.m. 1 p.m. 2 p.m. 3 p.m. 4 p.m. 5 p.m. 6 p.m. 7 p.m. 8 p.m. 9 p.m. 10 p.m. 11 p.m. 12 a.m AECI MW/AC Member 1 KW/DC

67 Member 2 Solar Peak vs. AECI's Peak 1 a.m. 2 a.m. 3 a.m. 4 a.m. 5 a.m. 6 a.m. 7 a.m. 8 a.m. 9 a.m. 10 a.m. 11 a.m. 12 p.m. 1 p.m. 2 p.m. 3 p.m. 4 p.m. 5 p.m. 6 p.m. 7 p.m. 8 p.m. 9 p.m. 10 p.m. 11 p.m. 12 a.m AECI MW/AC Member 2 KW/DC

68 Time of Day Rates Why Not a Higher KWH Charge During Peak Instead of KW Demand Rates? 6 Actual Accounts of HEC s system December 2017 Demand kwh Usage During Peak Home kw kwh Home kw kwh Home kw 14.4 kwh Home kw 16.7 kwh Home kw 22.4 kwh Home kw 29.7 kwh Annual 20 per kwh $1, $2, $1, $1, $ $ Home kw Cost to Co-op $1, $1, $1, $ $ $ kw x $10.42 x 12 months

69 Why not charge a higher availability charge? Availability charges are only a piece of the puzzle. Higher availability charges can punish members who don t contribute to setting a peak. High availability charges give members no options. Demand charges allow all members, low income included, an option to reduce their bill. Availability Charge Demand Charge KWH Charge

70 What about opt-in demand rates? Opt-In rates are counterproductive Allow solar members an out on paying their fair share

71 Why use a demand rate that resets each month instead of a ratcheted demand? Howard Electric s residential demand resets every month. Ratcheted demand once a household sets a high peak they keep it for 11 months unless it goes higher. How are co-ops billed for demand?

72 Do demand rates cause you to sell less KWH s? Things that are shrinking cooperative KWH sales: AECI s Take Control & Save program Energy efficient appliances Additional insulation But, demand rates don t shrink KWH s, they move KWHs away from peak. If you dry your clothes in off-peak hours, you re still using the KWHs to dry your clothes.

73 Why Phase in Demand Rates? Allows members time: Learn what demand is Adjust to new charge on bill Decide if they want to shave peak & how to do it

74 What other cooperatives are using demand rates? Butler Electric Co-op - El Dorado, Kansas $5 per KW Mid-Carolina Electric Co-op Lexington, South Carolina $12 per KW Howard Electric Cooperative Fayette, Missouri 75 per KW in 2016 increasing to $5 by 2018

75 A Closer Look at Butler Electric Co-op For 2015 the average consumer saved: $138 and $825 over the last 6 years That means the average residential customer, who conserved during our 3 hour peaking window, received approximately 1 month free each year compared to what their bill would have been under the old rate format. The Cooperative saved a similar amount on its Power Bill That s what made this all work

76 Question #3 - Working to Keep Rates Low Customer Service % 1% 2% 3% 1% 4% 5% 8% 7% 9% 9% 7% 10% 14% 15% 20% 23% 22% 25% 27% 27% 30% Poor Fair Good 33% 32% 38% 40% 42% 50% 51% 58% 57% 60% 62% 69% 67% 69% 70% 75% 72% 80% 2015 Final Customer Survey Results 85% 83% 90% 100%

77 What process did Howard Electric use to put in demand rates? Cost of Service Study Surveyed our members Employee Meetings Backpage communication Webpage / Facebook communication

78 If Howard electric designed rates that would allow you to control your rising electric costs more by changing the time you use certain appliances, how likely would you be willing to participate in this program, if it reduced your electric bill? Don't Know, 1% Not interested at all, 12% Not very interested, 13% Definitely Interested, 27% Probably Interested, 47%

79 Grain Bins & Demand Rates Grain Bin Capacity KW Demand $ Increase Value of $3.00 # of $3.00 to Cover Demand Increase 3, $0.81 $9,000 15, $7.10 $45, , $ $375, , $ $645,

80 Demands During Peak Time for Howard Electric Members January 2015 Demand July 2015 Demand October 2015 Demand In researching the demand on accounts, there are no home only accounts with over a 15 KW demand.

81 At $2.50 per KW, a Demand Difference of = to a cost difference of $31.52 At $5.00 per KW, a Demand Difference of = to a cost difference of $63.04

82 At $2.50 per KW, a Demand Difference of = to a cost difference of $42.72 At $5.00 per KW, a Demand Difference of = to a cost difference of $85.44

83 Contact Information Richard Fowler, Howard Electric Cooperative Adam Toth, Vice President, Toth and Associates Jeff Mueller, Vice President, Toth and Associates