Chris Lund Financial Consultant Utility Financial Solutions, LLC - PowerPoint PPT Presentation

Chris Lund Financial Consultant Utility Financial Solutions, LLC clund@ufsweb.com 231-342-9798

 International consulting firm providing financial services to utilities across the county, Guam, Canada and the Caribbean  Instructors for cost of service and financial planning for APPA, and regularly requested to present for organizations across the country including MMEA & AWWA  APPA Hometown Connections Partner 2

Solar Primary Objectives • Value of solar valuation method to determine kWh credit • Long run, short run or blend? (typically short run for market based & full requirements utilities, typically long run for traditional self generation utilities) • Metering preference(s) • One or two meters? Digital or analog meters? • Billing preference(s) • Method to apply value of solar kWh credit? • Community solar strategy vs. rooftop • Project scope and future plans? • Solar with battery storage • Potential impacts of battery storage with solar – interactive case study example 3

 Utility Financial Solutions works with utilities to conduct an avoided cost (marginal cost) determination for the value of solar per kWh  The study is conducted using the respective utility’s load data and power supply resource mix  Solar production profile is based on irradiance data obtained from pvwatts.nrel.gov (sample shown for the Escanaba MI area)  Ultimate approach adopted should be based on potential State Utility Commission, local board / council directives and management preferences 4

 Most inaccurate method of distribution (& fixed cost recovery) is through a kWh charge  Distribution system is constructed to handle a customers peak demand or a classes peak demands and are not constructed to handle kWh’s 5

Rates based on kWh sales are high risk to utility for fixed cost recovery 6

(theoretical) 7

 Many utilities are moving toward or considering demand / TOU rates for distribution & fixed cost recovery for all customers: • Send better price signals to customers • Promote electric vehicles (off peak charging) • Reduce subsidies for customers with distributed generation 8

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 Short Run Avoided Cost (Marginal Cost) ◦ Savings in the short run ◦ Typically energy value weighted by solar production, plus predicted transmission savings, may include a demand or capacity value, no system loss savings for community solar ◦ (typically tracks with market et pricing) g)  Solar weight hted ed hourly rly mark rket et avera rage (typic icall lly day ahead local node pricin ing)  Distrib tribut utio ion system tem loss savin ings  May includ ude a demand nd or capacity ty value lue  Trans nsmission ion saving ings 10

 Long Run Avoided Cost (Marginal Cost) ◦ Theoretical savings in the long run ◦ Theoretical value of avoiding installing the next generating unit ◦ Traditionally based on natural gas plant but many utilities are basing value on utility scale solar  Avoid ided ed fuel el to run next xt plant nt (zero ro fuel cost for solar) r)  Avoid ided ed capacity ty (ins nsta tall, ll, O&M for next xt plant nt)  Distrib tribut utio ion system tem loss savin ings  Avoid ided ed trans nsmis ission on  Theo eoreti retical long run distrib tribut ution ion system tem savin ings (if any) y) Residential Rooftop Small Commercial Rooftop Community Solar Long Run $ 0.093430 $ 0.103770 $ 0.087170 Short Run $ 0.054510 $ 0.054510 $ 0.052890 11

Rooftop solar (behind customer meter) • Value of solar includes (increased by) system losses • Value of solar may include a long run distribution • savings, no short run distribution savings Community solar (solar garden in community) • Value of solar does NOT include system losses • Value of solar does NOT include long or short run • distribution savings 12

Average annual solar production forEscanabaMI Residential Rooftop fora Standard Fixed (roof mount) 1KW Unit Array Tilt (deg): Average from: 18.4349, 26.5651and 45. Irradiance datafrom NREL and compiled by UFS kWh Non Capacity Production Theoretical Snow kWh Produced factor Monthly Monthly at time of Average Snow Days - Capacity Days reduced by reduced by Production Production Monthly Marquette MI kWh Produced factor factor Snow Days Snow Days Percent Rank Solar Peak 2017 KW Unit Days Hours Possible kWh 1 20.05 1 31 744 744 61 8.15% 35.34% 21 2.88% 1.96% 12 0.2413 2 13.21 1 28 672 672 73 10.88% 52.83% 39 5.75% 3.52% 10 0.3990 3 8.49 1 31 744 744 121 16.30% 72.61% 88 11.84% 8.03% 7 0.6051 4 2.95 1 30 720 720 132 18.30% 90.17% 119 16.50% 10.83% 5 0.7514 5 0.12 1 31 744 744 145 19.48% 99.62% 144 19.41% 13.17% 2 0.8117 6 0.00 1 30 720 720 144 20.04% 100.00% 144 20.04% 13.16% 3 0.8235 7 0.00 1 31 744 744 150 20.10% 100.00% 150 20.10% 13.64% 1 0.7610 8 0.00 1 31 744 744 133 17.86% 100.00% 133 17.86% 12.12% 4 0.7651 9 0.00 1 30 720 720 112 15.62% 100.00% 112 15.62% 10.26% 6 0.7392 10 0.59 1 31 744 744 83 11.15% 98.10% 81 10.94% 7.42% 8 0.6638 11 6.84 1 30 720 720 54 7.47% 77.20% 42 5.77% 3.79% 9 0.4786 12 16.86 1 31 744 744 50 6.77% 45.61% 23 3.09% 2.09% 11 0.2713 69.10 365 8760 8,760 1,258 14.36% 81.07% 1,096 12.52% 100.00% Average annual kWh kWh production production per KW of loss due to installed solar snow 1,096 -12.85% 13

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 Buy All Sell All with Digital Meter (two meters)  Buy All Sell All with Analog Meter (two meters)  Net Metering with Additional Charge (single meter)  Net Billing with Digital Meter (single meter)  Net Billing with Analog Meter (single meter)  Net Metering (Traditional) (single meter) 16

Buy all Sell all – Digital Revenue Meter, Solar is Metered 17

Buy all Sell all – Analog Revenue Meter, Solar is Metered 18

Net Metering with Additional Charge – Analog or Digital Revenue Meter Solar not Metered 19

Net Billing – Digital Revenue Meter Solar not Metered 20

Net Billing – Analog Revenue Meter Solar not Metered 21

Net Metering (traditional) – Analog or Digital Revenue Meter Solar not Metered (Worse for accuracy & utility fixed cost recovery. However, some states still require net metering) 22

Preferred valuation method (long run, short run or blend?) • System Metering and Billing Capabilities (how to apply value of solar ) • • May be different based on Community solar, rooftop and solar array size Current and Future Rate Structures (Demand, TOU…) • Right Sizing – Many Utilities are implementing guidelines that specify the • allowable size of distributed generation resource(s) the customer is allowed to install. Examples of how a utility may want to consider this for future customer solar installs: • Allow solar install up to greater of :  110% of a customer’s peak demand “before solar”  Or 100% of a customer’s average annual kWh usage “before solar” (net zero) ◦ Utility may specify maximum customer allowed solar install (example up to 20 KW array allowed within right sizing, installs above 20 KW by negotiation) System Verification – May consider procedures to ensure installed size and • future additions to a distributed generation resource. Periodic Review – Utility should review and update the value of solar credit • and implementation methods as significant assumptions change. • This will typically mirror general rate making timing (usually annually) . • Some utilities calculate value of solar credit monthly. 23

 Rate “Smart Export Program” (Source: puc.hawaii.gov)  Solar + Battery + Smart Inverter  TOU value of solar credit for excess pushed to grid 24

 Rate “Grid Supply+ Program” (Source: puc.hawaii.gov)  Solar + Smart Inverter (controlled by utility)  Fixed value of solar credit for excess pushed to grid, excess curtailed by utility to maintain a stable grid 25

 Battery storage justification ◦ Financial (optimize time value of energy) ◦ Backup (provide backup power to grid power) ◦ Power quality (maintain more consistent power)  Financial value dependent on time value of energy ◦ TOU energy rate ◦ Demand / capacity peaks ◦ Transmission peaks  Loss of energy when batteries are charged (typical 11% loss ~ 89% efficiency) 26

Chris Lund Financial Consultant Utility Financial Solutions, LLC clund@ufsweb.com 231-342-9798