Conf Call Nov07 Metering and Interconnection Survey
Metering and Interconnection Survey Results: Residential PV Steven Letendre, PhD IREC Consultant, Green Mountain College, VT & Mike Taylor Solar Electric Power Association November 16, 2007
Steven E. Letendre, PhD Associate Professor Business & Environmental Studies Green Mountain College letendres@greenmtn edu [email protected] 802-287-8303 (phone, work) 802-235-1369 802 235 1369 (phone (phone, home) Disclaimer: Comments made during this conference call by Steven y represent p the opinions p or p positions of Letendre do not necessarily the Interstate Renewable Energy Council or the Solar Electric 1 Power Association.
Agenda g • Big Picture • Survey Goals / Process • Survey y Results – utility respondent characteristics – net metering practices – interconnection practices – documentation and fees
• Preliminary Insights • Open O Discussion Di i /Q&A 2
The Big Picture • US PV markets are expanding • mostly gridconnected applications • 7,400 residential id ti l installations Source: IREC / PVNews: March, 2007
3
The Big Picture
PVNews: March, 2007
• PV industry ramping up production • Expanding residential PV very likely 4
The Big Picture
PVNews: March, 2007
5
Survey Goals 1. To understand the range of metering requirements, billing practices practices, and associated costs for photovoltaic (PV) systems interconnected at the distribution level 2. To understand the range of interconnection requirements and associated costs for customers connecting PV systems at the distribution level 3. From the survey results and professional experience, describe metering and interconnection best best-practices practices across identifiable categories that improve process and economic efficiencies for utilities and customers with PV systems at the distribution level 6
Survey y Process 1. SEPA collaborates with IREC, establish timelines and budget 2. Prepare survey instrument, peer review and test 3. Develop sample, conduct assessment, and process results Total
SEPA
NonSEPA
IOU
Muni
Coop
Other
Target List
94
47
47
31
35
27
1
Non-Target Li t List
27
19
8
5
19
3
0
Total
121
66
55
36
54
30
1
p Respondents
63
52
11
22
31
10
0 7
Survey Process: Regions Covered 4 3 1
2
3
3
2 J 1 NJ=
1
1 1
2
1
3
DE= 1
2
13
1 3
5 1 3
HI = 2
4 8
Utility Characteristics Descriptive Statistics: Number of Residential Customers Served
N
Mean
Min
Max
Total
63
567,304
660
4,500,000
IOU IOUs
22
Munis
31
219,850
660
1,237,000
Coops
10
22,685
2,450
90,000
1 304 454 120,000 1,304,454 120 000
4 500 000 4,500,000
9
Utility Characteristics 30
Total IOUs
Numbe er of Utilitie es
25 20
Munis Coops
15 10 5 0 < 10%
> 10% to < 30%
> 30% to < 50%
> 50% to < 70%
> 70% to < 90%
> 90%
Percent of Sales to Residenital Customers 10
Meter Technology Deployed Average Percent of Residential Customers by Meter Technology Total (N=57)
IOUs (N=21)
Munis (N=27)
Coops (N=9)
Percent Electromechanical Meters
72.7 %
70.0 %
76.3 %
68.3 %
Percent Solid State Meters
28.4 %
29.0 %
24.7 %
40.7 %
• 1/2 have TOU meters, ~average penetration 12% • 1/3 “smart” smart meters deployed ~average average penetration 22%
11
Meter Technology Deployed Smart Meter Planning fully implemented d l i ((complete deploying l t > 3 years)) deploying (complete < 3 years) planning (3 years plus deployment) planning (1 to 3 year deployment) no plans 0
2
4
6
8
10
12
14
16
18
Number of Utilities 12
Meter Reading Method Meter Reading Method
Average Percent for Residential Customers
On Site
67 3% 67.3%
Hand Held AMR
21.7%
Remote AMR
27.5%
Customer Reported
1.9%
Other
0.1%
Service Fees Mean
$7.51
Standard Deviation
$4.39
Median
$7.00
M d Mode
$6 00 $6.00
Range
$24.00
13
Solar Programs g •
2/3 of the utilities have a solar incentive program in place place.
•
30 administered by the utility 18 administered by the state ((or other entity) y)
•
approximately half funded through state taxes or other sources of funds and the other half funded based on ratepayer funds collected through a system benefits charge or other mechanism
•
17 voluntary 1 l programs, 10 were voluntarily l il offered ff d b by municipal utilities, 6 by investor owned, and 1 by a cooperative p utility y
•
most have been in existence between 3 – 10 years
14
Residential PV System Installations 2007 (through 6/30/2007) N=55
2006 N=52
Total (6/30/2007 and earlier) N=58
Mean
77
151
557
Median
11
17
28
Mode
0
0
0
316
593
2,183
Statistic
Standard Deviation
15
Net Metering (N=62) (N 62) Now required required, but w as offered voluntarily prior to requirement Voluntary utility program State legislative or regulatory requirement Not available 0
5
10
15
20
25
30
35
Number of Utilities 16
Net Metering & Meter Reading
Response Category
Number of Utilities
With no or minor adjustments, our primary metering reading system can accommodate a net-metered customer.
40
With significant i ifi t adjustments, dj t t our primary i metering t i reading di system can accommodate a net-metered customer.
10
An alternative means of meter reading is necessary for a net-metered customer.
6
17
Net Metering g & Meter Reading g • Modifications were needed to meter type and to billing system. TOU net metering will require significant modifications to billing system and severely limits choices of meters • The bi-directional meters can be probed by our meter readers using the same data collection devices as any other device as any other utility owned meter. • For time of use customers, requires meter to be reprogrammed for bi-directional energy gy tracking. g Standard rate customers require q no meter change. • Approximately 20 % of current meters are not compatible with NEM, i.e. not bi-directional; these meters will need to be replaced. • we change the meter to a bi-directional meter, but reading the two registers is easily accommodated by our existing meter reading systems. 18
Net Metering & Billing Response Category
Number of Utilities
With no or minor adjustments, our primary accounting/billing system can accommodate a net net-metered metered customer.
23
With significant adjustments, our primary accounting/billing system t can accommodate d t a net-metered t t d customer. t
22
An alternative means of accounting/billing is necessary for a net-metered customer.
10
19
Net Metering & Billing • Additional billing system logic to track month-to-month sellback credits. • Changes needed to be made to the customer billing system and more significant problem for primary (large) customers. • manual reconciliation for billing during interim required. New CIS / Billing S t System will ill b be iinstalled t ll d iin 2009 2009. • Integration with billing set-up has been very difficult to implement although g we are told the capability p y exists within the billing g system... y • Annually billed NEM customers must have their balances carried forward for 12 months and then a 'true-up' calculation must be performed. • We recently underwent major changes to our billing system to accommodate Net Metering Billing. Some customers still require manual billing • As mentioned above, a special billing format is required, and negative 20 indices create problems that must be manually corrected.
Metering Practices for New Net Metered Customers (N=56) Response Category
Number of Utilities
g meter only y Utilize the existing
8
Replace existing meter with a single new meter only
27
Utilize the existing meter and install a second meter
5
Replace the existing meter and install a second meter
8
Other
8
21
Metering Practices for New Net Metered Customers • Replace existing billing meter with a bi-directional meter and have the customer install a kWh meter at the output of the inverter. • Most of the time we can utilize the existing meter. Occasional we need to install an additional meter. • Utilize existing electro mechanical unit until deployment of AMR unit unit. If deployment of AMR done, then reprogram. • Utilize the existing meter and install a second meter for PV net metering plus production metering (production meter is only required to receive annual production incentive payments). • Utilize the existing g meter most of the time. If the existing g meter can't handle backward rotation, replace with a single meter capable of backward rotation. • We change the meter to a solid state meter capable of revenue quality reads on power flow in both directions. 22
Second Meter Location (N=21) ( ) Response Category
Number of Utilities
On the customer-side of the meter, between the inverter and the service panel, before any on-site consumption p of the solar g generation
13
At the point of common coupling, parallel to the consumption meter, after on-site consumption of the solar g generation
5
Other (please explain) • No second meter required. A $50 reprogramming fee for already deployed AMR meters. • N/A • Line-line, load load in series between distribution and service panel.
3
23
Purpose of Second Meter (N=18) (N 18) Response Category
Number of Utilities
To measure PV system output in excess of consumption consumption.
3
To measure total PV system output for state incentive program purposes.
2
To measure total T t t l PV system t output t t for f utility tilit incentive program purposes.
10
To measure total PV system output for other purposes. (please ( l explain) l i ) • For measuring SREC's. • To measure PV system output in specific intervals. • to measure the REC REC's s produced
3
24
Who Pays for the Second Meter (N=19) Response Category
Number of Utilities
Utility company
10
Customer
7
Varies / Other (please explain) • Customer pays for and provides the meter socket utility provides the meter • Varies from state to state.
2
Equipment Costs
Labor Costs
Mean
$81
$90
Minimum Mi i Value
$22
$40
Maximum V l Value
$240
$300
Statistic
Installation Costs for Second Meter (N=15)
25
Interconnection Establishing Technical Requirements for Interconnection (N=58) Other Utility y policy y based on other requirements Utility policy based on IEEE 1547 State regulations based on other requirements State regulations based on IEEE 1547 Case by case 0
5
10
15
20
25
Number of Utilities 26
Interconnection •
• •
46 of the 59 utilities responding indicated that a new PV installation must be inspected p by y a representative p of the utility company 4 indicated that an inspection was not needed 9 utilities indicated that inspection is done on a case by case basis Length of Time from Application to Final Approval Mean
Range
Average number of days (N 43) (N=43)
27.5
89
Minimum number of days (N=33)
13.5
59.5
Maximum number of days (N=34)
56.2
297 27
Interconnection Factors Leading to Delays in Final Approval Not a Factor
Somewhat of a Factor
A Significant Factor
Backlog of applications/insufficient processing staff (N=53)
32
14
7
Incomplete documentation f from customer t (N=52) (N 52)
7
27
18
Delays in permitting or inspection by local code official ffi i l (N (N=52) 52)
24
18
10
Issue with original installation requiring rework (N=51)
22
27
2
28
Interconnection Liability Coverage Requirement (N=57) R Response C Category t
N b off Utilities Number Utiliti
No proof of liability insurance is required
33
y requests q p proof of minimum liability y Utility coverage, but has no legal authority to require it
5
Utility policy specifies minimum liability coverage
13
State statute or regulatory order specifies minimum liability coverage
3
State statute or regulatory order specifies maximum liability coverage
3
average required = $250,000 (max $1 million and min $100,000) 29
Documentation & Fees Document
Yes/No
Number of Pages
Net Metering Application (N=47) (N 47)
26/21
10 = 0 - 5 p p. 3 = 6 – 10 p. 1 = 16 – 20 p.
Net Metering Agreement (N=46)
22/24
14 = 0 - 5 p. 3 = 6 – 10 p p. 1 = 11 – 15 p. 1 – 16 – 20 p.
Interconnection Application (N=48)
29/19
22 = 0 - 5 p. 3 = 6 – 10 p. 1 = 16 – 20 p.
Interconnection Agreement (N=-50)
40/10
16 = 0 - 5 p. 15 = 6 – 10 p. 3 = 11 – 15 p. 1 = 16 – 20 p. 1 = 25+ p.
Other (N=25) (N 25)
13/12
10 = 0 - 5 p p. 1 = 11 – 15 p. 1 = 21 – 25 p.
30
Documentation & Fees Fee
Yes/No
Amount
Interconnection Application Fee (N=52)
6/46
1 = $0 1 = > $25 to < $50 2 = > $75 to < $100 2 = > $100 to < $125
Net-Metering Application Fee (N=52)
2/50
1 = > $25 to < $50 1 = > $100 to < $125
Engineering g g Analysis y Fee ((N=49))
0/49
Other Fee
4/17
1 = > $0 to < $25 2 = > $25 to < $50 1 = > $150
Other, please specify: • Permit Fee • $50 if AMR deployed y and reprogramming g g is required. • Meter fees, as required. Production meter is $47. • The cost to install a manual disconnect switch.
31
Initial Insights • 7 utilities with 500 or more residential PV installations – – – – – – – –
4 IOU & 3 Munis net metering, 5 years or longer don’tt require a second meter don Interconnection standards based on IEEE 1547 no inspection necessary no liability insurance required don’t charge any fees have one or more FTEs to process applications
• accounting / billing issues across the board • incomplete customer documentation and installer delays prevalent throughout
32
Discussion / Q&A
33
Steven E. Letendre, PhD Associate Professor Business & Environmental Studies Green Mountain College letendres@greenmtn edu [email protected] 802-287-8303 (phone, work) 802-235-1369 802 235 1369 (phone (phone, home) Disclaimer: Comments made during this conference call by Steven y represent p the opinions p or p positions of Letendre do not necessarily the Interstate Renewable Energy Council or the Solar Electric 1 Power Association.
Agenda g • Big Picture • Survey Goals / Process • Survey y Results – utility respondent characteristics – net metering practices – interconnection practices – documentation and fees
• Preliminary Insights • Open O Discussion Di i /Q&A 2
The Big Picture • US PV markets are expanding • mostly gridconnected applications • 7,400 residential id ti l installations Source: IREC / PVNews: March, 2007
3
The Big Picture
PVNews: March, 2007
• PV industry ramping up production • Expanding residential PV very likely 4
The Big Picture
PVNews: March, 2007
5
Survey Goals 1. To understand the range of metering requirements, billing practices practices, and associated costs for photovoltaic (PV) systems interconnected at the distribution level 2. To understand the range of interconnection requirements and associated costs for customers connecting PV systems at the distribution level 3. From the survey results and professional experience, describe metering and interconnection best best-practices practices across identifiable categories that improve process and economic efficiencies for utilities and customers with PV systems at the distribution level 6
Survey y Process 1. SEPA collaborates with IREC, establish timelines and budget 2. Prepare survey instrument, peer review and test 3. Develop sample, conduct assessment, and process results Total
SEPA
NonSEPA
IOU
Muni
Coop
Other
Target List
94
47
47
31
35
27
1
Non-Target Li t List
27
19
8
5
19
3
0
Total
121
66
55
36
54
30
1
p Respondents
63
52
11
22
31
10
0 7
Survey Process: Regions Covered 4 3 1
2
3
3
2 J 1 NJ=
1
1 1
2
1
3
DE= 1
2
13
1 3
5 1 3
HI = 2
4 8
Utility Characteristics Descriptive Statistics: Number of Residential Customers Served
N
Mean
Min
Max
Total
63
567,304
660
4,500,000
IOU IOUs
22
Munis
31
219,850
660
1,237,000
Coops
10
22,685
2,450
90,000
1 304 454 120,000 1,304,454 120 000
4 500 000 4,500,000
9
Utility Characteristics 30
Total IOUs
Numbe er of Utilitie es
25 20
Munis Coops
15 10 5 0 < 10%
> 10% to < 30%
> 30% to < 50%
> 50% to < 70%
> 70% to < 90%
> 90%
Percent of Sales to Residenital Customers 10
Meter Technology Deployed Average Percent of Residential Customers by Meter Technology Total (N=57)
IOUs (N=21)
Munis (N=27)
Coops (N=9)
Percent Electromechanical Meters
72.7 %
70.0 %
76.3 %
68.3 %
Percent Solid State Meters
28.4 %
29.0 %
24.7 %
40.7 %
• 1/2 have TOU meters, ~average penetration 12% • 1/3 “smart” smart meters deployed ~average average penetration 22%
11
Meter Technology Deployed Smart Meter Planning fully implemented d l i ((complete deploying l t > 3 years)) deploying (complete < 3 years) planning (3 years plus deployment) planning (1 to 3 year deployment) no plans 0
2
4
6
8
10
12
14
16
18
Number of Utilities 12
Meter Reading Method Meter Reading Method
Average Percent for Residential Customers
On Site
67 3% 67.3%
Hand Held AMR
21.7%
Remote AMR
27.5%
Customer Reported
1.9%
Other
0.1%
Service Fees Mean
$7.51
Standard Deviation
$4.39
Median
$7.00
M d Mode
$6 00 $6.00
Range
$24.00
13
Solar Programs g •
2/3 of the utilities have a solar incentive program in place place.
•
30 administered by the utility 18 administered by the state ((or other entity) y)
•
approximately half funded through state taxes or other sources of funds and the other half funded based on ratepayer funds collected through a system benefits charge or other mechanism
•
17 voluntary 1 l programs, 10 were voluntarily l il offered ff d b by municipal utilities, 6 by investor owned, and 1 by a cooperative p utility y
•
most have been in existence between 3 – 10 years
14
Residential PV System Installations 2007 (through 6/30/2007) N=55
2006 N=52
Total (6/30/2007 and earlier) N=58
Mean
77
151
557
Median
11
17
28
Mode
0
0
0
316
593
2,183
Statistic
Standard Deviation
15
Net Metering (N=62) (N 62) Now required required, but w as offered voluntarily prior to requirement Voluntary utility program State legislative or regulatory requirement Not available 0
5
10
15
20
25
30
35
Number of Utilities 16
Net Metering & Meter Reading
Response Category
Number of Utilities
With no or minor adjustments, our primary metering reading system can accommodate a net-metered customer.
40
With significant i ifi t adjustments, dj t t our primary i metering t i reading di system can accommodate a net-metered customer.
10
An alternative means of meter reading is necessary for a net-metered customer.
6
17
Net Metering g & Meter Reading g • Modifications were needed to meter type and to billing system. TOU net metering will require significant modifications to billing system and severely limits choices of meters • The bi-directional meters can be probed by our meter readers using the same data collection devices as any other device as any other utility owned meter. • For time of use customers, requires meter to be reprogrammed for bi-directional energy gy tracking. g Standard rate customers require q no meter change. • Approximately 20 % of current meters are not compatible with NEM, i.e. not bi-directional; these meters will need to be replaced. • we change the meter to a bi-directional meter, but reading the two registers is easily accommodated by our existing meter reading systems. 18
Net Metering & Billing Response Category
Number of Utilities
With no or minor adjustments, our primary accounting/billing system can accommodate a net net-metered metered customer.
23
With significant adjustments, our primary accounting/billing system t can accommodate d t a net-metered t t d customer. t
22
An alternative means of accounting/billing is necessary for a net-metered customer.
10
19
Net Metering & Billing • Additional billing system logic to track month-to-month sellback credits. • Changes needed to be made to the customer billing system and more significant problem for primary (large) customers. • manual reconciliation for billing during interim required. New CIS / Billing S t System will ill b be iinstalled t ll d iin 2009 2009. • Integration with billing set-up has been very difficult to implement although g we are told the capability p y exists within the billing g system... y • Annually billed NEM customers must have their balances carried forward for 12 months and then a 'true-up' calculation must be performed. • We recently underwent major changes to our billing system to accommodate Net Metering Billing. Some customers still require manual billing • As mentioned above, a special billing format is required, and negative 20 indices create problems that must be manually corrected.
Metering Practices for New Net Metered Customers (N=56) Response Category
Number of Utilities
g meter only y Utilize the existing
8
Replace existing meter with a single new meter only
27
Utilize the existing meter and install a second meter
5
Replace the existing meter and install a second meter
8
Other
8
21
Metering Practices for New Net Metered Customers • Replace existing billing meter with a bi-directional meter and have the customer install a kWh meter at the output of the inverter. • Most of the time we can utilize the existing meter. Occasional we need to install an additional meter. • Utilize existing electro mechanical unit until deployment of AMR unit unit. If deployment of AMR done, then reprogram. • Utilize the existing meter and install a second meter for PV net metering plus production metering (production meter is only required to receive annual production incentive payments). • Utilize the existing g meter most of the time. If the existing g meter can't handle backward rotation, replace with a single meter capable of backward rotation. • We change the meter to a solid state meter capable of revenue quality reads on power flow in both directions. 22
Second Meter Location (N=21) ( ) Response Category
Number of Utilities
On the customer-side of the meter, between the inverter and the service panel, before any on-site consumption p of the solar g generation
13
At the point of common coupling, parallel to the consumption meter, after on-site consumption of the solar g generation
5
Other (please explain) • No second meter required. A $50 reprogramming fee for already deployed AMR meters. • N/A • Line-line, load load in series between distribution and service panel.
3
23
Purpose of Second Meter (N=18) (N 18) Response Category
Number of Utilities
To measure PV system output in excess of consumption consumption.
3
To measure total PV system output for state incentive program purposes.
2
To measure total T t t l PV system t output t t for f utility tilit incentive program purposes.
10
To measure total PV system output for other purposes. (please ( l explain) l i ) • For measuring SREC's. • To measure PV system output in specific intervals. • to measure the REC REC's s produced
3
24
Who Pays for the Second Meter (N=19) Response Category
Number of Utilities
Utility company
10
Customer
7
Varies / Other (please explain) • Customer pays for and provides the meter socket utility provides the meter • Varies from state to state.
2
Equipment Costs
Labor Costs
Mean
$81
$90
Minimum Mi i Value
$22
$40
Maximum V l Value
$240
$300
Statistic
Installation Costs for Second Meter (N=15)
25
Interconnection Establishing Technical Requirements for Interconnection (N=58) Other Utility y policy y based on other requirements Utility policy based on IEEE 1547 State regulations based on other requirements State regulations based on IEEE 1547 Case by case 0
5
10
15
20
25
Number of Utilities 26
Interconnection •
• •
46 of the 59 utilities responding indicated that a new PV installation must be inspected p by y a representative p of the utility company 4 indicated that an inspection was not needed 9 utilities indicated that inspection is done on a case by case basis Length of Time from Application to Final Approval Mean
Range
Average number of days (N 43) (N=43)
27.5
89
Minimum number of days (N=33)
13.5
59.5
Maximum number of days (N=34)
56.2
297 27
Interconnection Factors Leading to Delays in Final Approval Not a Factor
Somewhat of a Factor
A Significant Factor
Backlog of applications/insufficient processing staff (N=53)
32
14
7
Incomplete documentation f from customer t (N=52) (N 52)
7
27
18
Delays in permitting or inspection by local code official ffi i l (N (N=52) 52)
24
18
10
Issue with original installation requiring rework (N=51)
22
27
2
28
Interconnection Liability Coverage Requirement (N=57) R Response C Category t
N b off Utilities Number Utiliti
No proof of liability insurance is required
33
y requests q p proof of minimum liability y Utility coverage, but has no legal authority to require it
5
Utility policy specifies minimum liability coverage
13
State statute or regulatory order specifies minimum liability coverage
3
State statute or regulatory order specifies maximum liability coverage
3
average required = $250,000 (max $1 million and min $100,000) 29
Documentation & Fees Document
Yes/No
Number of Pages
Net Metering Application (N=47) (N 47)
26/21
10 = 0 - 5 p p. 3 = 6 – 10 p. 1 = 16 – 20 p.
Net Metering Agreement (N=46)
22/24
14 = 0 - 5 p. 3 = 6 – 10 p p. 1 = 11 – 15 p. 1 – 16 – 20 p.
Interconnection Application (N=48)
29/19
22 = 0 - 5 p. 3 = 6 – 10 p. 1 = 16 – 20 p.
Interconnection Agreement (N=-50)
40/10
16 = 0 - 5 p. 15 = 6 – 10 p. 3 = 11 – 15 p. 1 = 16 – 20 p. 1 = 25+ p.
Other (N=25) (N 25)
13/12
10 = 0 - 5 p p. 1 = 11 – 15 p. 1 = 21 – 25 p.
30
Documentation & Fees Fee
Yes/No
Amount
Interconnection Application Fee (N=52)
6/46
1 = $0 1 = > $25 to < $50 2 = > $75 to < $100 2 = > $100 to < $125
Net-Metering Application Fee (N=52)
2/50
1 = > $25 to < $50 1 = > $100 to < $125
Engineering g g Analysis y Fee ((N=49))
0/49
Other Fee
4/17
1 = > $0 to < $25 2 = > $25 to < $50 1 = > $150
Other, please specify: • Permit Fee • $50 if AMR deployed y and reprogramming g g is required. • Meter fees, as required. Production meter is $47. • The cost to install a manual disconnect switch.
31
Initial Insights • 7 utilities with 500 or more residential PV installations – – – – – – – –
4 IOU & 3 Munis net metering, 5 years or longer don’tt require a second meter don Interconnection standards based on IEEE 1547 no inspection necessary no liability insurance required don’t charge any fees have one or more FTEs to process applications
• accounting / billing issues across the board • incomplete customer documentation and installer delays prevalent throughout
32
Discussion / Q&A
33
