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

SLIDE 1

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

SLIDE 2

2

 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

SLIDE 3

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

SLIDE 4

 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

SLIDE 5

 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

SLIDE 6

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

6

SLIDE 7

(theoretical)

7

SLIDE 8

 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

SLIDE 9

9

SLIDE 10

 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

SLIDE 11

 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

n

 Theo eoreti retical long run distrib tribut ution ion system tem savin ings (if any) y)

11

Residential Rooftop Small Commercial Rooftop Community Solar Long Run 0.093430 $ 0.103770 $ 0.087170 $ Short Run 0.054510 $ 0.054510 $ 0.052890 $

SLIDE 12

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

SLIDE 13

13

2017 Average Snow Days - Marquette MI KW Unit Days Hours Possible kWh kWh Produced Theoretical Capacity factor Non Snow Days factor kWh Produced reduced by Snow Days Capacity factor reduced by Snow Days Monthly Production Percent Monthly Production Rank kWh Production at time of Monthly Solar Peak 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 production per KW of installed solar kWh production loss due to snow 1,096

12.85%

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

SLIDE 14

14

SLIDE 15

15

SLIDE 16

 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

SLIDE 17

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

17

SLIDE 18

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

18

SLIDE 19

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

19

SLIDE 20

Net Billing – Digital Revenue Meter Solar not Metered

20

SLIDE 21

Net Billing – Analog Revenue Meter Solar not Metered

21

SLIDE 22

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

SLIDE 23

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

SLIDE 24

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

grid

24

SLIDE 25

 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

SLIDE 26

 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

SLIDE 27