20130510Beach DIRECT.pdf

BEFoRE THE IDAHo PUBLIC LITILITIES CoMMISSIoN?61I HEy I 0 pt1 3: tr6
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPAI{Y FOR AUTHORITY TO
MODIFY ITS NET METERING
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
Idaho Conservation lrague
CASE NO. IPC-E-L2.27
DirectTestimonyof R Thomas Beach
May 10,2013
I Q: Please state your name, address, and business affiliation.
2 A: My name is R. Thomas Beach. I am principal consultant of the consulting firm
3 Crossborder Energy. My business address is 2560 Ninth Street, Suite 213A, Berkeley, California
4 94710.
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6 Q: Please describe your experience and qualifications.
7 Az I have over 30 years of experience in utility analysis including advising three California
8 Public Utilities Commissioners and serving as an expert witness in a wide range of utility
9 proceedings. Prior to this experience I earned degrees in English and Physics from Dartmouth
10 College and a Masters in Mechanical Engineering from the University of California, Berkeley.
11 My curriculum vita is attached to this testimony as Exhibit 201.
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13 Q: On whose behalf are you testifying in this proceeding?
14 A: I am appearing on behalf of the Idaho Conservation League (ICL). ICL intervened in this
15 case because they are concerned that Idaho Power's proposed Schedules 6 and 8 are an
16 unjustified change to the net metering program, Schedule 84.
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18 Q: Have you previously testified or appeared as a witness before the Idaho Public Utility
19 Commission?
20 A: No, I have not. However, I have testified on numerous occasions before state regulatory
2l commissions in California, Colorado, Nevada, New Mexico, Oregon, and Virginia. Exhibit 201
22 includes a current list of the testimony that I have sponsored in state regulatory proceedings
23 concerning electric and gas utilities. With respect to the net metering issues under consideration
24 in this case, I have testified on issues concerning net energy metering (NEM) and solar economics
1
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Idaho Conservation League
rPC-E-t2-27
1 in California, Colorado, New Mexico, and Virginia. I recently co-authored a major cost-benefit
2 analysis of NEM in California, which is the largest solar market in the U.S.'
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4 Q: Do you have any exhibits?
5 A: Yes. Exhibit 201 is my curriculum vita. Exhibit202 is a report produced for the Vermont
6 Public Service Department analyzingthe costs and benefits of net metering for Vermont,
7 including a literature survey of other similar cost/benefit studies. Exhibit 203 is a confidential
8 exhibit containing my calculation of the costs and benefits of a hypothetical net metered solar
9 system. Exhibit 204is Idaho Power's response to ICL's production request number t. Exhibit
l0 205 is a portion of a presentation by Idaho Power showing the preliminary change in avoided
I I costs between the 2011 IRP and the 2013 IRP.
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13 Q: Please summarizeyour testimony.
14 A: Electric consumers have the right to install their own, privately-financed, on-site
l5 renewable distributed generation (DG) and to interconnect that generation with the grid, thus
16 giving the DG customer the freedom to meet some or all of their energF needs.2 Net energy
17 metering (NEM) is a foundational policy that enables this freedom. NEM allows the DG
18 customer to receive a retail rate credit when the DG output exceeds the customer's on-site use,
19 essentially "running the meter backward." NEM is, at its essence, a billing arrangement which
20 provides a simple way to calculate the bill for a DG customer, considering that the customer at
2l times imports electricity from the grid and at other times exports power to the grid.
' Beach, R. Thomas, and McGuire, Patrick G., Evaluating the Benefits and Costs of Net Energlt
Metering in California (lanuary 2013), (hereafter "Crossborder NEM Study") Available at
http://votesolar.org/wp-content/uploads/2013/01/Crossborder-Energy-CA-Net-Metering-Cost-
Benefit-|an-20 I 3-final.pdf
'This right is provided under, the Public Utilities Regulatory Policies Act of 1978 (PURPA). See
18 CFR 5292.303.
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My testimony responds to the Idaho Commission's request, when they initially approved the
Schedule 84 net metering tariff, for a report comparing retail rates to the value of the net-metered
generation. In2002,Idaho Power proposed and the Idaho Commission approved Schedule 84
- Customer Energy Production - Net Metering. Since its inception, Schedule 84:
. charges customers the rate consistent with their class cost of service while the meter is
running forward;
. pays customers the retail rate consistent with their class of service while the meter is
running backward; and
' does not impose any monthly charges other than those provided on the customer's
standard service schedule.3
When reviewing Schedule 84, the Idaho PUC Staffargued that crediting net metering
generation at the full retail rate may "pay customers more than the actual value of the
generation," causing non-participating ratepayers to subsidize the net metering participants. a In
light of this alleged subsidy the Idaho Commission approved a cap on the overall program to
limit any potential impacts. Critically, the Commission directed Idaho Power, when the cap was
reached, to produce "a report regarding the required level of subsidization by non-participants"
and the "differential between the net metering price it pays at retail rates and the wholesale cost
of alternative power supplies."5
Responding to the Commission's directiv€, ffiy testimony compares the retail rate credits
paid to solar net metered customers (the primary costs of net metering) to the costs which Idaho
Power avoids by not having to procure and deliver alternative power supplies to net metered
customers (the benefits of net metering). Table 1 summarizes the costs and benefits that I have
calculated. My analysis concludes that, for Idaho Power's ratepayers today, the benefits of net
3 See Order No. 28951at 2, IPC-E-O1-39.
n Idat4.
' Id at 12.
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metering significantly exceed the costs, by a factor of 1.6 to 1.9. In other words, my analysis
shows that crediting NEM generation at the retail rate actually undervalues this new generation
source.
Table l: Summary of Idaho Power NEM Costs and Benefits
2)-year Levelized $ per MWh
Costs
Lost Utility Revenues
Integration Costs
Total Costs
Benefits
Energy
2O11IRP
2013lRP (estimated)
Capacity - both IRPs
Transmission - both IRPs
Total Benefits - 2011 IRP
Total Benefits - 2013IRP
Benefit / Cost Ratio
2O11IRP
2013IRP
$81
$a
$8s
$92
$64
$40
$32
$ 164
$ 136
1.9
1.6
Q: Please characterize the basic analytic process which you have used for this cost / benefit
analysis.
A: This analysis is a ratepayer impact measure (RIM) test, one of the standard cost-
effectiveness tests that are widely used by utilities throughout the U.S. (including by Idaho
Power) to evaluate the ratepayer impacts of Demand Side Management (DSM) p.ograms.6
Under the terms of the Memorandum of Understanding for Prudency Determination of DSM
Programs, Idaho Power uses three primary cost-effectiveness tests: the total resource cost test
(TRC), which "reflects the total benefits and costs to all customers (participants and non-
u See California Standard Practice Manual: Economic Analysis of Demand-Side Programs and
Projects (October 2001). Idaho Power's use of such tests is described in the 2011 IRP, Appendix
C, at66-67.
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participants) in the [utility service territory:" the utility cost test (UTC), which "calculates the
costs and benefits of the program from the perspective of . . . the utility implementing the
program; and the participant cost test (PCT), which "assesses the costs and benefits from the
perspective of the customer installing the measure."T The RIM test "examines the potential
impact the energy efficiency program has on rates overall" including impacts to customers who
do not participate in the DSM or net metering programs.s Be.uuse this is the strictest of the tests,
Idaho Power is "not required to use the non-participant ("no losers") test."e A RIM score above
one indicates that overall rates are likely to decrease due to the net metering program, as is the
case with Idaho Power's net metering program.
Q: Why do you apply a method dweloped for evaluating DSM programs to evaluate NEM
costs and benefits, when a NEM customer can go beyond reducing their own consumption and
deliver excess energy to Idaho Power's system?
A: In practice a NEM customer is most similar to an energy efficient customer and is
fundamentally different than an independent electrical generator seeking to sell their output to a
utilitf. I observe that the majority of the output of a net metered DG system serves the
customer's on-site load without ever touching the grid,to as illustrated in Figure 1, and in this
respect looks to the utility like an energy efficiency (EE) or demand-side management (DSM)
resource. By contrast, a qualifring facility or other independent electricity generator relies on the
' Order No 32331 at9 - 10, IPC-E-11-05.
8 National Action Plan for Energy Efficiency, Understanding Cost-Effectiveness of Energy Efficiency
Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers at 3-6
(November 2008).
' Order No 28894at7,IPC-E-O1-13.r0 The exact percentage used on-site will depend on the size of the solar DG system compared to
the customer's load, and on the customer's load profile through the day. For the typical (con't)
residential customer (such as shown in Figure 1 ), about 55o/o lo 7 5o/o of the DG output is used
on-site, with the rest exported to the grid.
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grid to sell the output of their generation system. Because of the focus on serving on-site load,
NEM should be evaluated in a manner that is consistent with how other demand-side resources
are assessed.
Figure 1: The 3 States of Net Metering
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5 6 7 8 9 1011L2L3t4t51617 1819202t2223
Customer Load by Hour in I Day
Traditional DSM programs pay customers an incentive to reduce on-site loads. For NEM
the "incentive" is crediting the small portion of the NEM customer's output that is exported to
the grid, instead of paying a wholesale power price. This incentive is conceptually no different
than a rebate, which is paid to a customer when the customer buys an energy-efficient air
conditioner or agrees to manage his irrigation pumping loads. Those DSM programs are
analyzed to ensure that the costs and benefits are balanced such that society as a whole benefits
and other ratepayers are not unduly burdened. Similarly, the purpose of my analysis of Idaho
Power's current NEM program is to ascertain whether the cost of NEM credits at the retail rate is
offset by the benefits to other ratepayers from the reduced demand and the new source of power
that the NEM customer brings to the grid.
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Q: Have other state utility regulators accepted this analpical method?
A: Yes, although there are relatively few examples because only recently are states beginning
to analyze net-metered DG. California uses the same set of cost-effectiveness tests and the same
avoided cost calculator to analyze the benefits of EE, DSM, and net-metered DG resources." The
state of Vermont also used this approach to assess the economics of net metering in Vermont. I
included this report as Exhibit 202 because of it includes a literature review of studies that have
looked at the costs and benefits of NEM and distributed generation.r2 The key point is that such
cost-effectiveness evaluations are widely used in many states, including Idaho, to evaluate DSM
programs, so using such an analysis for net-metered DG builds on a widely-accepted framework.
Q: Over what time horizon should the cost and benefits of net-metered DG be analyzed?
A: As with other DSM measures as well as supply-side resource options, the evaluation
should be over the life of the DG system. Accordingly, the analyses presented below are
conducted over a 2}-year period (2013-2032), and the results are expressed in terms of 2D-year
levelized costs and benefits. This also aligns with the 2}-year horizon Idaho Power uses to
evaluate utility resource options in the Integrated Resource Plan.
Q: Please describe howyou calculate the "costs" of a NEM system in your analysis.
" The California Public Utilities Commission (CPUC) has used this framework to evaluate the
state's solar incentive program. CSI Cost-Effectiveness Evaluation (April 20ll). Available at
ftp:llftp.cpuc.ca.gov/gopher-data/energy-division/csi/CSIo/o20Report-Complete-E3-Final.pdf
The CPUC also has used this approach to do a more focused evaluation of net metering. Net
Energy MeteringCost Effectiveness Evaluation, (March 2010). Available at
http://www.cpuc.ca. gov/NR/rdonlyr es I 0F 4238 5A- FDBE - 487 6 -9 AB3 -
E6 AD 522DB8 6 2/0/nem-combined.pdf
" Exhibit 202, Evaluation of Net Metering in Vermont Conducted Pursuant to Act 125 of 2012
(Vermont Public Service Department, |anuary 15,2013).
LPC-E-12-27 7
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Idaho Conservation League
I A: The principal costs of DG are the revenues that the utility loses as a result of NEM
2 customers serving their own loads and running the meter backward when they export power to
3 the grid. Table 2 is an analysis of the lost revenues for a hypothetical Idaho Power residential
4 customer with average usage who installs a 5.0 kW PV system in Boise and who pays the utility's
5 standard three-tier residential rate. I used the industry-standard PVWATTS calculator from the
6 National Renewable Energy Lab (NREL)" to project the hourly output of such a PV system, and
7 then aggregated that output by month and by Idaho Power's seasonal and peak time periods.
8 This PV output is presented in Table 3. Table 2 shows that the lost revenues are $644 per year in
9 2013, or about $78 per MWh. Assuming that rates escalate at3o/o per year and using the utility's
l0 7olo discount rate, the 20-year levelized lost revenues are $81 per MWh.
I I I have also considered whether Idaho Power might incur additional costs to integrate
12 solar DG resources into its system. Given the small amount of solar DG now on-line, such costs
13 would appear to be very modest, perhaps negligible. A recent Idaho Power wind integration
14 study reveals "customer demand is a strong determinant of Idaho Power's ability to integrate
15 wind."rn When wind generation occurs during low load periods, and as the amount of wind on
16 the system reaches a high percentage of loads, integration costs increase. But Idaho Power's own
17 IRP shows that the solar resources are a closer fit to the utility's loads. Further, the roughly 3
18 MW of NEM customers are far smaller than the several hundred MW of wind on Idaho Power's
19 system. Other utilities in the western U.S. that have analyzed both wind and solar integration
20 costs have found that solar integration costs are lower.'s Accordingly, we assume that solar
13 The NREL PwvATTscalculator is available at:
hxp : / / rr e dc. nr el. gov / s olar / calculato r s / PWV ATT S / v er sio n 1 /
'n Idaho Power 2011 IRP Update Wind Integration Study at 7, (filed with the Idaho PUC in
February of2013).
't For example, Arizona Public Service (APS) has found wind integration costs to be $3.25 per
MWh, and comparable solar costs to be $2.00 per MWh (in 2020). APS 2012 Integrated Resource
Plan, at 32. Black & Veatch, "Solar Photovoltaic (PV) Integration Cost Study" (B&V Project No.
IPC-E-12-27 8
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Idaho Conservation League
1 integration costs for Idaho Power are $4.00 per MWh, compared to the current wind integration
2 costs of $6.50 per MWh.
174880, November 2012). Available at:
http:/iwww.solarfu turearizona.com/B&VSolarPVlntegrationCostStudy.pdfIPC-E-12-27 9
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Table 3z PV Output (kv{h) for a 5 kW System in Boise, by Season and Peak period
Month Summer
On-peak
Summer
Mid-peak
Non-Summer
On-peak
Non-Summer
Mid-peak
Annual
Total
Ianuary 298 50 348
Februarv 403 67 470
March 581 97 678
April 687 114 801
Mav 790 r32 922
Iune 399 554 9s4
Iulv 437 575 1,0L2
Auqust 410 s42 9s3
September 677 113 790
October 553 92 646
November 339 57 396
December 281 47 328
Annual Total 1,246 1,671 4,610 768 8,296
Percent of
Outout
15o/o 20o/o 560/o 9o/o I00o/o
2
3 Q: What are the primary benefits of net-metered DG systems for Idaho Power's ratepayers?
4 A: A net-metered PV system provides a new source of power for the Idaho Power system,
5 and allows the utility to avoid €n€rg[, capacity, and transmission costs. Idaho Power avoids the
6 cost of procuring and delivering energy when a NEM customer meets their own demand on-site,
7 as well as when a NEM customer exports excess energy to be consumed by their neighbors. The
8 vast majority of NEM customers use solar panels that provide energy coincident with Idaho
9 Power's peak demands, thereby deferring or avoiding capacity additions. DG systems avoid
10 transmission costs because the energy generation occurs at the point of consumption and any
I I excess generation is delivered to the closest neighbor. Other potential benefits include avoiding
12 distribution costs, market price mitigation benefits, and enhanced grid security.
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Q:
A:
What alternate energy costs did you use?
I calculated the benefits by applying the alternate or marginal costs taken principally from
Idaho Power's 2011 Integrated Resource Plan (2011 IRP), from preliminary information which
the utility has released on its 2013 IRP, and from Idaho Power's most recent general rate case
filing. These are the alternate costs Idaho Power and the Idaho Commission use to evaluate
demand-side programs. The use of the DSM alternate costs are appropriate given that the
"primary thrust of net metering," like other demand-side programs, "is to provide customers the
opportunity to offset their own load and energy requirements"rT - in this case, by facilitating the
installation of privately-financed on-site renewable generation.
Idaho Power expects the alternate energy costs for the 2013 IRP to be lower than those in
its 201 I IRP. Accordingly, I have calculated DG / NEM benefits using both ( 1 ) the alternate
energy costs from the 201 1 IRP'8 and (2) an estimate of 2013IRP alternate energy costs based on
Idaho Power's October 2012 DSM Status Update.te To produce the 2013 IRP estimate, I reduced
the 2011 summer on-peak and non-summer mid-peak alternate costs by 25o/o, and, summer mid-
peak and all off-peak rates by 45o/o, to reflect lower gas and GHG costs. Table 4 shows both sets
of alternate energy costs. In Table 5, I apply these alternate energy costs to expected DG output
by cost period to determine the total energy-related benefits. The 2}-year levelized energy
benefits from a PV system are $92 per MWh using the 2011 IRP alternate energy costs and $64
per MWh with the estimated 2013 IRP values.
" Order No. 28951at 11.
'' Exhibit 204, Idaho Power's Response to ldaho Conservation League Production Request No. 1
(confirming the Company continues to use the 2011 IRP Alternate Costs for DSM resources);
Appendix C, at 67 -68 and Table DSM-2. The summer on-peak alternate costs reflect the variable
costs of a simple-cycle combustion turbine; the alternate costs in other time periods are based on
modeling of the regional power market.
'' Exhibit 205,Idaho Power's DSM Status Updatepresented to the 2013 IRP Advisory Committee
on October 1I,201,2. Showing a preliminary estimate of lower avoided costs than 2011.
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I Q: How did you value the capacity benefits of DG resources?
2 A: I assume that a PV system will contribute firm summer capacity equal to 600/o of the
3 system's nameplate (AC) capacity. Accordingly, a 5 kW PV system would have a firm capacity of
4 3 kW. I use the 2011 IRP capacity value of $94 per kW-year (escalated to ZOt: $), and assume a
5 summer peak loss factor of l3o/o.20 As shown in Table 6, the resulting capacity-related alternate
6 cost for PV is $40 per MWh of PV output.
7
8 Q: Isn't PV a "non-firm" source of power, such that it should receive no capacityvalue?
9 A: No. Idaho Power's own 2013 IRP screening data assigns a summer on-peak capacity for
10 distributed PY of 75o/o of these systems'nameplate capacity; thus, the utility assumes that 10 MW
11 of 4 kW PV systems distributed across southwest Idaho would have a summer on-peak capacity
12 of 7.5 MW.2r There have been many studies of the capacity value of solar PV, across the U.S.,
13 employing sophisticated techniques such as the use of reliability models to calculate the effective
14 load carrying capacity (ELCC) of solar resources." Idaho Power's IRP assumption that
l5 distributed PV has a capacityvalue of 75o/o of nameplate is probably too high even on its
'o ldaho Power 2011lUP,Appendix Cat6g,Table DSM-I.
" Idaho Power Supply-Side Resource Operating Inpufs, Presented to the 2013 IRP Advisory
Committee on December 13, 2012. Available at:
http://www.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp l20L3lDecMtgMaterials/Supp
lySideResourceStack_PeakCapacity. pdf
" These studies include:. Xcel Energy Services, Inc, An ELCC Analysis for Estimating the Capacity Value of Solar
Generation Resources on the Public Service Company of Colorado System, (February 2009).
A vailable at: http://www.solarfuturearizona.com/PSCO-Solar_ElCC_report_020909.pdf
' Hoff/Perez, Clean Power Research, Energy and Capacity Valuation of Photovoltaic Power
Generation in NewYork, (March 2008). Available at: bit.lyldPP2|1
' Hoff/Perez, Clean Power Research, Determination of Photovoltaic Effective Capacity for
New Jersey, (June 2012). Available at http://www.cleanpower.com/resources/pv-elcc-new-
jersey/
' Hoff/Perez, Clean Power Research, Determination of Photovoltaic Effective Capacity for
Nevada Power, (March 2012). Available at http://www.cleanpower.com/resources/pv-elcc-
nevada-power/
1
2
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5
6
7
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23
24
summer-peaking system, particularly for fixed array PV systems. A firm PV capacity value of
60%o of nameplate is more reasonable given the range of capacity values for PV calculated in the
available PV ELCC studies.
Q: Does solar DG avoid transmission costs?
A: Yes. Transmission costs are avoided because NEM generation is either used on-site or is
exported and immediately consumed by the NEM customer's neighbors without loading the
transmission system. DG at the distribution level which serves local loads in Idaho Power's
service territory will reduce demand on Idaho Power's transmission system. It is particularly
important to include avoided transmission costs given that Idaho Power is transmission-
constrained during summer peak periods, the Boardman to Hemingway Transmission line was
the preferred resource in the 2011 IRP, and Idaho Power continues to pursue a partnership in the
Gateway West transmission line.23
Q: Doesn't Idaho Power incur additional transmission and distribution (T&D) costs either
to serve or to accept power from net metered DG customers?
A: No. When the DG customer's meter runs forward, the DG customer pays for that service
at the full retail rate, including the full costs of the utility's T&D service. When the DG customer
is exporting and the meter runs backward, the DG customer functions as a generator, selling
power to ldaho Power at a price equal to the retail rate. As with any other generator from which
Idaho Power purchases energy, the utility takes title to the power at the DG customer's meter and
then delivers the power over its distribution system to other customers - the DG customer's
immediate neighbors. Idaho Power then sells that power to the neighbors and receives its full
retail rate in compensation - including the full retail T&D service charges - even though the
" Idaho Power 2011 IRP at6 - 7; http://www.gatewaywestproject.com/.
I utility has moved the power only a short distance without the use of its transmission system. In
2 sum, the utility is more than fully compensated for all use of its T&D system associated with the
3 services it provides to a net metered customer, and the transmission system costs which such a
4 transaction avoids should be accounted for as a benefit in determining whether the full retail rate
5 is the "right" price for net metered DG exports.
6
7 Q: How have you quantified such avoided transmission costs?
8 A: Idaho Power presented a marginal cost study in its most recent general rate case.2a This
9 study includes the utility's long-term marginal transmission costs - in other words, the
10 investment-related costs that the utility will save if demand on its transmission system is reduced
I I - based on the transmission capital budget over the 20lI-2020 period. These marginal
12 transmission costs are shown in Table 5.
13 Table 5z Marginal Transmission Costs
Month $ per kW-year
Ianuary
February
March
April
May
Iune
Iuly
August
September
October
November
December
2.39
2.29
3.48
0.96
12.59
27.70
32.75
23.02
20.38
6.66
6.93
33.85
t4
l5
t6
Summer Total 83.47
Solar generation peaks on summer afternoons when Idaho Power's demand is also high.
As a result, solar PV has particular value in avoiding transmission costs during Idaho Power's
'n 2011 Marginal Cost Analysis, Larkin Workpapers at 59-66, IPC-E-11-08, (April28,z}tl memo
from Scott Wright to Matt Larkin).
1 summer peak months (June - August). Accordingly, I used the fune - August data on marginal
2 transmission costs (escalated to 2013 $) to calculate the transmission benefits of solar DG, which
3 are about $30 per MWh, as summarized in Table 6.
4
5 Q: Please summarize the benefits of net-metered solar DG.
6 A: Table 6 summarizes these benefits -- $163 per MWh using the 2011 IRP alternate energy
7 costs and $ 135 per MWh using the estimat ed 2013 IRP alternate energy costs.
8 Table 6: Avoided Cost Benefits for a 5 kW System by Seasonal and Peak Period
Summer
On-neak
Summer
Mid-peak
Not Summer
On-neak
Not Summer
Mid-oeak
Annual
Total
Solar DG Outout I ^246 r.671 4.610 768 8.296
Energy - 2011 IRP
Alternate Energy
00-vr level $/MWh)$106.7 s92.82 $91.7r $70.79
Enersv ($)$133 $1 5s $423 $s4 $76s
Enersy Value ($A{Wh)$92.2s
Energy - 2013 IRP
Alternate Energy
(20-vr level$/MWh)$80.02 $s l.0s $68.78 $38.93
Enersv ($)$1 00 $85 $317 $30 $532
Enersy Value ($/MWh)$64. r 4
Capacity
Svstem Size 5.0 kw
Firm Solar (%)60%
Firm Solar (kW)3.0 kw
Capacity Alternate Cost
($lkW-vr)$98.76
Summer Peak Loss %t3%
Capacity Value
($ and $/MWh)$33s $40.3s
Transmission
Firm Solar ftW)3.0 kw
Summer Transmission
Marginal Cost ($/kW-vr)$87.70
Transmission Value
($ and $/lvlwh)$263 $3 l .71
Total Value - 20ll IRP $164.32
Total Value - 2013 IRP $136.20
t Q: What is the benefit-to-cost ratio for net-metered DG?
2 A: As shown in Tables 1 and 6, the benefit-to-cost ratio for net-metered DG ranges from 1.6
3 (2013IRP) to 1.9 (2011 IRP). I note that net-metered DG is cost-effective on an energybasis
4 alone using the 2011 IRP alternate energy costs.
5
6 Q: What would be the annual benefits for Idaho Power's non-participating ratepayers if 15
7 MW of net-metered solar DG were to be installed in Idaho Power's territory?
8 A: From Table 1, the net benefits of solar DG are $51 per MWh based on the 2013 IRP
9 alternate energF costs. The output of 15 MW of solar DG is 24,900 MWh per year. Thus, the
10 annual benefits from 15 MW of solar DG would be $1.3 million per year.
l1
12 Q: Do you consider your assessment of the benefits and costs of solar DG conservative?
13 A: Yes. First my analysis uses the RIM test, which is widely considered the most conservative
14 measure of the cost effectiveness of DSM programs. The RIM includes as a "cost" Idaho Power's
l5 forgone revenue attributable to a NEM customer who merely reduces their energy demands, but
16 still is a net purchaser of electricity, instead ofjust focusing on a NEM customer's export of excess
17 energy. Second, my analysis does not include additional benefits that other states have quantified
18 and accepted. Both of these factors would increase the benefit-to-cost ratio.
19 Many utilities, including Idaho Power, do not use the RIM test to decide whether to
20 implement energy efficiency programs. One reason is that the RIM test includes as a cost Idaho
2l Power's forgone revenues due to reduced energy bills.2s But like DSM programs, the majority of
22 the output of a NEM system serves the customer's on-site load and never touches the grid (the
23 "energy efficiency" portion of Figure 1). From the perspective of the impacts on the grid and on
24 other ratepayers, this portion of the DG output is akin to the installation of an energy efficiency
" NAPEEaI3-6.
I
2
J
4
5
6
7
8
9
10
11
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13
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22
23
measure, or to the customer simply choosing to use less power, and no utility would single out a
particular customer for extra charges if that customer decided to reduce his use of the utility's
product. Further, customers have PURPA rights to install renewable DG on their premises and
to serve their own load. From this perspective, it is only the exported portion of a NEM system
that impacts the grid or non-participating ratepayers. A more precise RIM evaluation of NEM
should focus only on the power exports, instead of the entire output of system, as my analysis
does.26
However, such an "export-only" analysis is more complex and must be done on an hourly
basis, as the amount of hourly exports depends on the size of the PV system relative to the
customer's load and on the hourly profiles of the customer's PV production and load. Because
NEM exports tend to occur in the afternoon when the power is most valuable, the per unit
benefits of NEM exports typically are larger than the per unit benefits of the entire DG output.
Thus, an export-only evaluation of NEM for Idaho Power would be likely to produce an even
higher benefit / cost ratio that those which I have calculated above.
Second, my analysis does not include a number of benefits of solar DG that have been
quantified and included in studies performed in other states. Other studies, such as the
California cost / benefit studies referenced above, have included avoided distribution costs, which
can be more difficult to analyze because the data on when distribution circuits peak and when
they are expected to reach capacity are hard to obtain and highly location-specific. Other benefits
which have been quantified include:
o Price mitigation benefits. Lower demand for electricity (and for the gas used to
produce the marginal kWh of power) has the broad benefit of lowering prices
across the gas and electric markets in which the utility operates.2T
'u The cost-benefit evaluations of NEM that have been conducted in California, as referenced in
Footnote 8 above, have focused exclusively on NEM exports.
" For example, a Lawrence Berkeley National Lab study has estimated that the consumer gas bill
savings associated with increased amounts of renewable energy and energy efficiency, expressed
1
2
J
4
5
6
7
8
9
10
Q:
A:
ll
t2
l3
t4
15
t6
Grid security. Renewable DG resources are installed as many small, distributed
systems and thus are highly unlikely to fail at the same time. They are also
located at the point of end use, and thus reduce the risk of outages due to
transmission or distribution system failures. This reduces the economic impacts
of power outages.
Economic development. Renewable DG produces more local job creation than
fossil generation, enhancing tax revenues.
One study of several eastern U.S. markets estimated these benefits collectively to be from
$100 to $140 per MWh.28 Given that the benefits I have quantified are decisively higher than the
costs, I have not tried to calculate these additional benefits for the Idaho Power system.
Does this conclude your direct testimony?
Yes, it does.
in terms of $ per MWh of renewable energy, range from $7.50 to $20 per MWh. Wiser, Ryan;
Bolinger, Mark; and St. Clair, Matt, Easing the Natural Gas Crisis: Reducing Natural Gas Prices
through Increased Deployment of Renewable Energy and Energy Efficiency at ix, (January 2005).
Available at: http ://eetd.lbl. gov/EA/EMP
" Hoff, Norris and Perez, The Value of Distributed Solar Electric Generation to New Jersey and
Pennsylvania, atTabLe ES-2 (November 2012). Available at http://mseia.net/site/lvp-
content/uploads I 2012/05/MSEIA- Final-Benefits-of-Solar-Report- 2 012- 11 -0 1.pdf
BEFORE THE IDAHO PUBLIC UTITITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFY ITS NET METERING
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC-E-I2-27
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 201
CURICULUM VITA FOR R. THOMAS BEACH
R. THOMAS Br,lcn
Principal Consultant Page I
Mr. Beach is principal consultant with the consulting firm Crossborder Energy. Crossborder
Energy provides economic consulting services and strategic advice on market and regulatory
issues conceming the natural gas and electric industries. The firm is based in Berkeley,
California, and its practice focuses on the energy markets in Califomia, the western U.S.,
Canada, and Mexico.
Since 1989, Mr. Beach has participated actively in most of the major energy policy debates in
California, including renewable energy development, the restructuring of the state's gas and
electric industries, the addition of new natural gas pipeline and storage capacity, and a wide
range of issues concerning California's large independent power community. From 1981
through 1989 he served at the California Public Utilities Commission, including five years as an
advisor to three CPUC commissioners. While at the CPUC, he was a key advisor on the
CPUC's restructuring of the natural gas industry in Califomia, and worked extensively on the
state's implementation of PURPA.
Annls oF EXPERTTSE
Renewable Energt Issues: extensive experience assisting clients with issues concerning
California's Renewable Portfolio Standard progftrm, including the calculation of the
state's Market Price Referent for new renewable generation. He has also worked for the
solar industry on the creation of the California Solar Initiative (the Million Solar Roofs),
as well as on a wide range of solar issues in other states.
Restructuring the Natural Gas and Electric Industries: consulting and expert testimony
on numerous issues involving the restructuring of the electric industry, including the
2000 - 2001 Western energy crisis.
Energt Markets: studies and consultation on the dynamics of natural gas and electric
markets, including the impacts of new pipeline capacity on natural gas prices and of
electric restructuring on wholesale electric prices.
Qualifying Facility Issues: consulting with QF clients on a broad range of issues
involving independent power facilities in the Western U.S. He is one of the leading
experts in Califomia on the calculation of avoided cost prices. Other QF issues on
which he has worked include complex QF contract restructurings, electric transmission
and interconnection issues, property tax matters, standby rates, QF efficiency standards,
and natural gas rates for cogenerators. Crossborder Energy's QF clients include the full
range of QF technologies, both fossil-fueled and renewable.
Pricing Policy in Regulated Industries: consulting and expert testimony on natural gas
pipeline rates and on marginal cost-based rates for natural gas and electric utilities.
Crossborder Energt
R. TnovrAS Bnlcn
Principal Consultant Page2
t.
Eouclrron
Mr. Beach holds a B.A. in English and physics from Darftnouth College, and an M.E. in
mechanical engineering from the University of California at Berkeley.
Aclnnurc HoNoRS
Graduated from Dartmouth with high honors in physics and honors in English.
Chewon Fellowship, U.C. Berkeley, 1978-79
PnornssroNAl AccREDrrATroN
Registered professional engineer in the state of California.
Expnnr Wrrxnss Trsrruoxy BEFoRE run CPUC
Prepared Direct Testimony on Behalf of Pacific Gas & Electric Company/Pacific Gas
Transmission (I. 88-12-027 - July 15, 1989)
' Competitive and environmental benefits of new natural gas pipeline capacity to
California.
a. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A.
89-08-024 - November 10, 1989)b. Prepared Rebuttal Testimony on Behalf of the Canadian Producer Group (A.
89-08-024 - November 30, 1989)
. Natural gas procurement policy; gas costforecasting.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (R. 88-08-018
- December 7, 1989)
. Brokering of interstate pipeline capacity.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029
-November l, 1990)
. Natural gas procurement policy; gas cost forecasting; brokerage fees.
Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission and the Canadian Producer Group (I. 86-06-005 - December 21,1990)
. Firm and interruptible rates for noncore natural gos users
')
3.
4.
5.
Crossborder Energt
R. THOMAS BTIcH
Principal Consultant Page 3
6. a. Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - January 25,l99l)b. Prepared Responsive Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - March 29,1991)
. Brokering of interstate pipeline capacity; intrastate transportation policies.
7. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A.
90-08-029/Phase II -April 17, l99l)
. Natural gas brokerage and transportfees.
8. Prepared Direct Testimony on Behalf of LUZ Partnership Management (A.91-01-027
-July 15, l99l)
. Natural gas parity rates for cogenerqtors and solar powerplants.
9. Prepared Joint Testimony of R. Thomas Beach and Dr. Robert B. Weisenmiller on Behalf
of the California Cogeneration Council (I. 89-07-004 - July 15, l99l)
. Avoided cost pricing; use of published natural gas price indices to set avoided
c o s t pr ic e s for qualifu ing fac il iti e s.
10. a. Prepared Direct Testimony on Behalf of the Indicated Expansion Shippers (A.
89-04-033 - October 28,1991)b. Prepared Rebuttal Testimony on Behalf of the Indicated Expansion Shippers
(A. 89-04-0033 - November 26,1991)
. Natural gas pipeline rate design; cost/benefit analysis of rolled-in rates.
ll. Prepared Direct Testimony on Behalf of the Independent Petroleum Association of
Canada (A. 9l-04-003 - January 17, 1992)
. Natural gas procurement policy; prudence of past gas purchases.
12. a. Prepared Direct Testimony on Behalf of the California Cogeneration Council
(I.86-06-005lPhase II - June 18,1992)b. Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
(I. 86-06-005/Phase II - July 2,1992)
. Long-Run Marginal Cost (LRMC) rate designfor natural gas utilities.
13. Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
92-10-017 - February 19, 1993)
. Pedormance-basedratemakingforelectricutilities.
Crossborder Energt
R. THOMAS Bnlctr
Principal Consultant Page 4
14.
l5
16.
17.
18.
19.
20.
Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-02-0141A.93-03-053
-May 21,1993)
. Natural gas transportation service for wholesale customers.
a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A. 92-12-043 1 A. 93-03 -03 8 - June 28, 1993)b. Prepared Rebuttal Testimony of Behalf of the Canadian Association of
Petroleum Producers (A.92-12-0431A.93-03-038 - July 8, 1993)
. Natural gas pipeline rate design issues.
a. Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-05-023 -November 10, 1993)b. Prepared Rebuttal Testimony on Behalf of the SEGS Projects (C. 93-05-023 -January 10,1994)
. Utility overchargesfor natural gas service; cogenerotion parity issues.
Prepared Direct Testimony on Behalf of the City of Vernon (A. 93-09-0061A.
93-08-0221A. 93-09-048 - June 17,1994)
. Natural gas rate designfor wholesale customers; retail competition issues.
Prepared Direct Testimony of R. Thomas Beach on Behalf of the SEGS Projects (A.
94-01-021 - August 5, 1994)
. Natural gas rate design issues; rate parity for solar power plants.
Prepared Direct Testimony on Transition Cost Issues on Behalf of Watson Cogeneration
Company (R. 94-04-03111.94-04-032 - December 5,1994)
. Policy issues concerning the calculation, allocation, and recovery of transition
costs associated with electric industry restructuring.
Prepared Direct Testimony on Nuclear Cost Recovery Issues on Behalf of the California
Co generation Counc il (A. 93 - 12-025 ll. 9 4 -02 -002 - February | 4, I 99 5)
' Recovery of above-market nuclear plant costs under electric restructuring.
Prepared Direct Testimony on Behalf of the Sacramento Municipal Utility District (A.
94-1 l-01 5 - June 16, 1995)
. Natural gas rate design; unbundled mainline transportation rates.
21.
Crossborder Energ,t
R. THOMAS Bnlcrl
Principal Consultant Page 5
22. Prepared Direct Testimony on Behalf of Watson Cogeneration Company (A. 95-05-049
-September 11, 1995)
. Incremental Energt Rates; air quality compliance costs.
23. a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A. 92-12-043 I A. 93 -03 -03 8/A. 94-05 -0 3 5 I A. 9 4-06-03 4 I A.
94-09-0561A. 94-06-044 - January 30, 1996)b. Prepared Rebuual Testimony on Behalf of the Canadian Association of
Petroleum Producers (A. 92-12-043 I A. 93 -03 -03 8/A. 94-05 -0 3 5 I A.
94-06-0341A. 94-09-0 561 A. 94-06-044 - February 28, 1996)
. Natural gas market dynamics; gas pipeline rate design.
24. Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 96-03-031 - July 12,1996)
o Natural gas rate design: parity rates for cogenerators.
25. Prepared Direct Testimony on Behalf of the City of Vernon (A. 96-10-038 -August 6,
teeT)
. Impacts of a major utility merger on competition in natural gas and electric
markets.
26. a. Prepared Direct Testimony on Behalf of the Electricity Generation Coalition
(A. 97-03-002 - December 18,1997)b. Prepared Rebuttal Testimony on Behalf of the Electricity Generation Coalition
(A. 97-03-002 - January 9, 1998)
o Natural gas rate designfor gas-fired electric generators.
27. Prepared Direct Testimony on Behalf of the City of Vernon (A. 97-03-015 - January
16,1998)
. Natural gas service to Baja, Califurnia, Mexico.
Crossborder Energt
R. THOMAS Bn.IcTT
Principal Consultant Page 6
28.Prepared Direct Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (A. 98-10-012/A. 98-10-031/A. 98-07-005
-March 4,1999).
Prepared Direct Testimony on Behalf of the California Cogeneration Council
(A. 98-10-0l2lA. 98-01-031/A. 98-07-005 - March 15, 1999).
Prepared Direct Testimony on Behalf of the California Cogeneration Council
(A. 98-10-0121A.98-01-031/A. 98-07-005 - June 25,1999).
Natural gas cost allocation and rate designfor gas-fired electric generators.
Prepared Direct Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-ll-022 - February 11, 2000).
Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-ll-022 - March 6, 2000).
Prepared Direct Testimony on Line Loss Issues of behalf of the California
Cogeneration Council (R. 99-l l-022 - April 28,2000).
Supplemental Direct Testimony in Response to ALJ Cooke's Request on behalf
ofthe California Cogeneration Council and Watson Cogeneration Company
(R. 99-l l-022 - April 28,2000).
Prepared Rebuttal Testimony on Line Loss Issues on behalf of the California
Cogeneration Council (R. 99-l l-022 - May 8, 2000).
Market-based, avoided cost pricingfor the electric output of gas-fired
cogenerationfocilities in the Califurnia market; electric line losses.
Direct Testimony on behalf of the Indicated Electric Generators in Support of
the Comprehensive Gas OII Settlement Agreement for Southern Califomia Gas
Company and San Diego Gas & Electric Company (I. 99-07-003 - May 5,
2000).
Rebuttal Testimony in Support of the Comprehensive Settlement Agreement on
behalf of the Indicated Electric Generators (I. 99-07-003 - May 19, 2000).
Testimony in support of a comprehensive restructuring of natural gas rates and
services on the Southern California Gas Company system. Natural gas cost
allocation and rate designfor gas-fired electric generators.
Prepared Direct Testimony on the Cogeneration Gas Allowance on behalf of the
California Cogeneration Council (A. 00-04-002 - September l, 2000).
Prepared Direct Testimony on behalf of Southern Enerry California (A.
00-04-002 - September l, 2000).
Natural gas cost allocation and rate designfor gas-fired electric generators.
29. a.
b.
c.
d.
e.
30.
b.
31. a.
b.
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32. a.
b.
Prepared Direct Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - September 18, 2000).
Prepared Rebuttal Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - October 6,2000).
o Rate designfor a natural gas "peaking service."
a. Prepared Direct Testimony on behalf of PG&E National Enerry Group &
Calpine Corporation (I. 00- I 1 -002-Apil 25, 2001).b. Prepared Rebuttal Testimony on behalf of PG&E National Enerry Group &
Calpine Corporation (I. 00-l l-002-May 15,2001).
. Terms and conditions of natural gas service to electric generators; gas
curtailment policies.
a. Prepared Direct Testimony on behalf of the California Cogeneration Council
(R. 99-l l-022-Illf.ay 7,2001).b. Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
(R. 99-11-022-May 30, 2001).
o Avoided cost pricingfor olternative energl producers in California.
a. Prepared Direct Testimony of R. Thomas Beach in Support of the Application of
Wild Goose Storage Inc. (A. 0l-06-029-June 18, 2001).b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Wild Goose
Storage (A. 0 1 -06-029-November 2, 200 1 )
. Consumer benefitsfrom expanded natural gas storage capacity in Califurnia.
Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino (I. 0l -06-047-December 14, 2001)
' Reasonableness review of a natural gas utility's procurement proctices and
storage operations.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 0 1 - I 0 -024,-May 31, 2002)b. Prepared Supplemental Testimony of R. Thomas Beach on behalf of the
California Cogeneration Council (R. 0 1 - 1 0 -024-May 3 l, 2002)
. Electric procurement policies for Califurnia's electric utilities in the aftermath of
the California energt crisis.
JJ.
34.
35.
36.
37.
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R. THOMAS Bucn
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38.
39.
40.
41.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technolory Association (R. 02-01-01l-June 6,2002)
. "Exitfees" for direct occess customers in Califtrnia.
Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino (A.02-02-012 - August 5,2002)
. General rate case issuesfor a natural gas utility; reasonableness review of a
notural gas utility's procurement practices.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association (A. 98-07-003 - February 7,2003)
' Recovery of past utility procurement costsfrom direct access customers.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council, the California Manufacturers & Technolory
Association, Calpine Corporation, and Mirant Americasr lnc. (A 0l-10-011
-February 28,2003)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council, the California Manufacturers & Technolory
Association, Calpine Corporation, and Mirant Americas, Inc. (A 01-10-01I
-March 24,2003)
o Rate design issues for PaciJic Gas & Electric's gas transmission system (Gas
Accord II).
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technolory Association; Calpine Corporation; Duke
Enerry North America; Mirant Americas, Inc.; Watson Cogeneration
Company; and West Coast Power,Inc. (R. 02-06-041- March 21,2003)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technolory Association; Calpine Corporation; Duke
Enerry North America; Mirant Americas, Inc.; Watson Cogeneration
Company; and West Coast Power, Inc. (R. 02-06-041- April 4,2003)
' Cost allocation of above-market interstate pipeline costs for the California
natural gas utilities.
Prepared Direct Testimony of R. Thomas Beach and Nancy Rader on behalf of the
California Wind Enerry Association (R. 01-10-024 - April 1, 2003)
' Design and implementation of a Renewable Portfolio Standard in California.
42.
43.
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R. THOMAS Bn,rcH
Principal Consultant Page 9
44. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 01-10-024 - June 23, 2003)b. Prepared Supplemental Testimony of R. Thomas Beach on behalf of the
California Cogeneration Council (R. 0l-10-024 - Jtne29,2003)
. Power procurement policies for electric utilities in Califurnia.
45. Prepared Direct Testimony of R. Thomas Beach on behalf of the Indicated Commercial
Parties (02-05-004 - August 29,2003)
. Electric revenue allocation ond rate designfor commercial customers in southern
Califurnia.
46. a. Prepared Direct Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-021 - July
16,2004)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-021 - July
26,2004)
. Policy and rate design issues for Pacific Gas & Electric's gas transmission
system (Gas Accord IID.
47. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 04-04-003 - August 6,2004)
. Policy and contract issues concerning cogeneration QFs in Califtrnia.
48. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council and the California Manufacturers and Technolory
Association (A. 04-07-044 - January 11, 2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council and the California Manufacturers and Technolory
Association (A. 04-07 -044 - January 28, 2005)
. Natural gas cost allocation and rate designfor large transportation customers in
northern Califurnia.
49. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 04-06-024 - March 7,2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 04-06-024 - Apri|26,2005)
. Electric marginal costs, reyenue allocation, and rate designfor commercial and
industrial electric customers in northern California.
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Principal Consultant Page l0
50. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Solar
Enerry Industries Association (R. 04-03 -017 - April 28, 2005)
. Cost-ffictiveness of the Million Solar Roofs Program.
51. Prepared Direct Testimony of R. Thomas Beach on behalf of Watson Cogeneration
Company, the Indicated Producers, and the California Manufacturing and
Technolory Association (4.04-12-004 - Jluly 29,2005)
. Natural gas rate design policy; integration of gas utility systems.
52. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 04-04-003/R. 04-04-025 - August 31, 2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 04-04-003/R. 04-04-025 - October 28,2005)
. Avoided cost rates and contracting policies for QFs in Califurnia
53. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 05-05-023 - January 20,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 05-05-023 - February 24,2006)
' Electric marginal costs, revenue allocotion, and rate designfor commercial and
industrial electric customers in southern Califurnia.
54. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Producers ( R. 04-08-018 - January 30,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Producers ( R. 04-08-018 - February 21,2006)
' Transportation and balancing issues concerning California gas production.
55. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technologr Association and the Indicated Commercial Parties
(A. 06-03-005 - October 27,2006)
' Electric marginal costs, revenue allocation, and rqte designfor commercial and
industrial electric customers in northern Califtrnia.
56. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 05-12-030 - March 29,2006)
' Review and approval of a new contract with a gas-Jired cogeneration project.
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R. THOMAS Bnlcn
Principal Consultant Page ll
57.a. Prepared Direct Testimony of R. Thomas Beach on behalf of Watson
Cogeneration, Indicated Producers, the California Cogeneration Council,
and the California Manufacturers and Technolory Association (A.04-12-004
-July 14,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Watson
Cogeneration, Indicated Producers, the California Cogeneration Council,
and the California Manufacturers and Technolory Association (A. 04-12-004
-July 31,2006)
. Restructuring of the natural gas system in southern California to include firm
capacity rights; unbundling of natural gas services; risUreward issuesfor
natural gas utilities.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 06-02-013 - March 2,2007)
. Utility procurement policies concerning gas-Jired cogenerationfacilities.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A.07-01-047 - August 10,2007)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar
Alliance (A. 07-01-047 - September 24,2007)
. Electric rate design issues that impact customers installing solar photovoltaic
systems.
a. Prepared Direct Testimony of R,. Thomas Beach on Behalf of Gas Transmission
Northwest Corporation (A. 07-12-021- May 15, 2008)b. Prepared Rebuttal Testimony of R,. Thomas Beach on Behalf of Gas
Transmission Northwest Corporation (A.07-12-021 - June 13, 2008)
. Utility subscription to new natural gas pipeline capacity serving California.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A.08-03-015 - September 12,2008)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar
Alliance (A. 08-03-015 - October 3, 2008)
. Issues concerning the design of a utility-sponsored program to install 500 MW of
utility- and independently-owne d solar photovoltaic systems.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
08-03-002 - October 31, 2008)
60.
58.
59.
6t.
62.
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R. THOMAS BnICTT
Principal Consultant Page 12
63.
64.
65.
66.
67.
. Electric rate design issues that impact customers installing solar photovoltaic
systems.
a. Phase II Direct Testimony of R. Thomas Beach on behalf of Indicated
Producers, the California Cogeneration Council, California Manufacturers
and Technolory Association, and Watson Cogeneration Company (A.
08-02-001 - December 23,2008)b. Phase II Rebuttal Testimony of R. Thomas Beach on behalf of Indicated
Producers, the California Cogeneration Council, California Manufacturers
and Technolory Association, and Watson Cogeneration Company (A.
08-02-001 - January 27,2009)
o Natural gas cost allocation and rate design issues for large customers.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 09-05-026 - November 4,2009)
. Natural gas cost allocation and rate design issues for large customers.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of Indicated
Producers and Watson Cogeneration Company (A. 10-03-028 - October 5,
2010)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Indicated
Producers and Watson Cogeneration Company (A. l0-03-028 - October 26,
2010)
. Revisions to a program ofJirm backbone capacity rights on natural gas pipelines.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
I 0-03-01 4 - October 6, 2010)
. Electric rate design issues that impact customers installing solar photovoltaic
systems.
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Indicated Settling
Parties (A. 09-09-013 - October I l, 2010)
. Testimony on proposed modifications to a broad-based settlement of rate-related
issues on the Pactfic Gas & Electric natural gas pipeline system.
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Principal Consultant Page 13
68. a. Supplemental Prepared Direct Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 6,2010)b. Supplemental Prepared Rebuttal Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 13,2010)c. Supplemental Prepared Reply Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 20,2010)
. Local reliability benefits of a new natural gas storage facility.
ExprRr WrrxBss TBsuuoNv BproRB rHp Cor,oRADo Punlrc UrrlrrrBs ConnvrrssroN
l. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Colorado Solar
Energy Industries Association and the Solar Alliance, (Docket No. 09AL-2998 - October
2,2009).
. Electric rate design policies to encourage the use of distributed solar generation.
2. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Vote Solar Initiative
and the Interstate Renewable Energy Council, (Docket No. l lA-418E - September 21,
20rt).
. Development of a community solar programfor Xcel Energt.
ExpnRt WttxBss Tnsrrproxy BEFoRE rnr Puslrc SERvrcE CovrurssroN oF Npv^lo.c,
l. Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 97-2001-May 28, 1997)
. Avoided cost pricingfor the electric output of geothermal generationfocilities in
Nevada.
2. Pre-filed Direct Testimony on Behalf of Nevada Sun-Peak Limited Partnership
(Docket No. 97-6008-September 5, 1997)
3. Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(DocketNo. 98-2002 - June 18, 1998)
. Market-based, avoided cost pricingfor the electric output of geothermal
ge ner ation fac il itie s in N ev ada.
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Principal Consultant Page 14
Exppnr WrrNrss TrsrrivrouvBBroRB rnr Nnw Mexrco Punlrc Rncur..r,rrox CourrurssroN
1.Direct Testimony of R. Thomas Beach on Behalf of the Interstate Renewable Enerry
Council (Case No. 1 0-00086-UT-February 28, 20ll)
. Testimony on proposed standby rates for new distributed generation projects;
cost-ffictiveness of DG in New Mexico.
Direct Testimony and Exhibits of R. Thomas Beach on behalf of the New Mexico
Independent Power Producers, (Case No. I l-00265-UT, October 3,2011)
. Cost capfor the Renewable Portfolio Standard program in New Mexico
ExpBnr Wrrxrss TssrIvloxv BBpoRr rnB Punlrc UrrlrrrEs ConnurrssroN oF Onrcox
l.Direct Testimony of Behalf of Weyerhaeuser Company (UM I 129 - August 3,
2004)
Surrebuttal Testimony of Behalf of Weyerhaeuser Company (UM I129 -October 14,2004)
Direct Testimony of Behalf of Weyerhaeuser Company and the Industrial
Customers of Northwest Utilities (UM ll29 I Phase II - February 27,2006)
Rebuttal Testimony of Behalf of \ileyerhaeuser Company and the Industrial
Customers of Northwest Utilities (UM ll29 lPhase II - April 7,2006)
Policies to promote the development of cogeneration and other qualifuing
facilities in Oregon.
Expsnr Wrrxpss TpsrrproNv Brronr rHs VrRcrxr,r ConpoRATIoN Coprurrssrox
1. Direct Testimony and Exhibits of R. Thomas Beach on Behalf of the Maryland - District
of Columbia - Virginia Solar Energy Industries Association, (Case No.
PUE-2011-00088, October 11, 2011)
' Standby rates for net-metered solar customers, and the cost-effectiveness of net
metering.
a.
b.
2. a.
b.
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R. THOMAS Brrcn
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LrrrcluoN ExpBnrnNcB
Mr. Beach has been retained as an expert in a variety of civil litigation matters. His work
has included the preparation of reports on the following topics:
. The calculation of damages in disputes over the pricing terms of natural gas sales
contracts (2 separate cases).
. The valuation of a contract for the purchase of power produced from wind generators.
. The compliance of cogeneration facilities with the policies and regulations applicable to
Qualiffing Facilities (QFs) under PURPA in California.
. Audit reports on the obligations of buyers and sellers under direct access electric
contracts in the California market (2 separate cases).
. The valuation of interstate pipeline capacrty contacts (3 separate cases).
In several of these matters, Mr. Beach was deposed by opposing counsel. Mr. Beach has also
testified at trial in the bankruptcy of a major U.S. energy company, and has been retained as a
consultant in anti-trust litigation concerning the California natural gas market in the period prior
to and during the2000-2001 California energy crisis.
Crossborder Energt
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLTCATTON OF rDAHO POWER )
coMpANy FoR AUTHORJTY TO ) CASE NO. LPC-E-12-27
MODIFY ITS NET METERING )
SERVICE AND TO INCREASE THE )
GENERATION CAPACITY LIMIT. )
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 202
EVALUATION OF NET METERING IN VERMONT CONDUCTED PURSUANT TO ACT 125
oF 20t2
VERMONT PUBTIC SERVICE DEPARTMENT
IANUARY 15,2013
Evaluation of Net Metering in Vermont
Conducted Pursuant to Act L25 of 20Lz
Public Service Department
January 15,2013
1 Introduction
Act 125 of the 2012 Vermont legislative session directed the Public Service Department (Department) to
complete an evaluation of net metering in Vermont:
No loter thon lanuary 75,201.3, the deportment of public service (the deportment) sholl perform
a general evoluation of Vermont's net metering statute, rules, and procedures ond shall submit
the evoluotion and ony accomponying recommendotions to the general assembly. Among any
other issues reloted to net metering thot the deportment moy deem relevont, the report shall
include on onalysis of whether and to what extent customers using net metering systems under
30 V.S.A. 5 279a are subsidized by other retoil electric customers who do not employ net
metering. The onalysis olso sholl include on examinotion of any benefits or costs of net metering
systems to Vermont's electric distribution ond transmission systems and the extent to which
customers owning net metering systems do or do not contribute to the fixed costs of Vermont's
retoil electric utilities. Prior to completing the evoluation and submitting the report, the
department shall offer an opportunity for interested persons such as the retail electric utilities
and renewoble energy developers and advocotes to submit information and comment.
The Department undertook several steps to address the legislative request and evaluate Vermont's net
metering statute, rules, and procedures. Background and current statistics regarding net metering in
Vermont are presented in Section 2 of this report. Section 3 describes the analysis the Department
conducted to evaluate whether, and to what extent, customers employing net metering are subsidized
by other customers. Section 4 concludes the report with a general assessment of the state's net
metering statute, rules, and procedures.
The Department issued a Request for lnformation, focused on the cross-subsidization analysis but
welcoming comments on all aspects of the study, on September L7 ,20L2. The results and analysis
reported here were informed by comments submitted by eleven interested persons, organizations, and
businesses (including utilities and renewable energy advocates). The Department also held several
meetings with commenters to better understand their comments and solicit further information. The
Department also received stakeholder comments on both the draft report document and draft
spreadsheet tool, both of which were released on December 27,2012.
2 Background
2.L A Brief History of Net Metering in Vermont
The 1998 legislative session enacted a net metering law (30 V.S.A. 5219a), requiring electric utilities to
permit customers to generate their own power using small-scale renewable energy systems of 15 kW or
less (including fuel cells using a renewable fuel). Farm systems were allowed to be larger, with a cap of
100 kW. Any power generated by these systems could be fed back to the utility, running the electric
meter backwards, if generation exceeded load at any given time.
Amendments in 1999, 2OO2 and 2008 permitted the installation of more net metered capacity,
increased the allowable size of systems, and added the use of non-renewably fueled combined heat and
power units of 20 kW or less. Beginning in 2OO2 "group net metering" was allowed, but was restricted
to farmers. The 2008 amendments lifted this restriction, increased the permissible size per installation
to 250 kW, simplified the permitting process for systems under 150 kW, and raised the ceiling on the
total installed capaci{ from one percent to two percent of peak load. ln 2011, the Vermont General
Assembly expanded the permissible size limit per installation to 500 kW, simplified the administration
for net metering groups, allowed a registration process for photovoltaic (PV) systems 5 kW and under,
increased the overall net metering capacity cap per utility to 4 percent of the 1995 utility system peak or
previous year's peak (whichever is higher), and created a solar credit payment for all customers who
have installed PV net metered systems. The solar credit payment has the effect of increasing the value
of generation to net metered customers up to 20 cents per kWh in the year the system is installed.
During the 2012 session the registration process was expanded to pV projects 10 kW and under, and the
process for group net metering billing and monetization of credits was clarified.
2.2 Status of Net Metering in Vermont
Net metering has experienced rapid growth over the last four years as the demand for local renewable
energy has grown, costs have come down, and access to renewables has broadened. As can be seen in Figure
1, solar PV has had the most substantial growth of all the renewable technologies. The number of PV
systems applying for net metering permits annually has grown by a factor of more than four since 2008.
5.,!:E
o
o!
E,z
Net Metering Applications Per Year
700
600
500
400
300
200
100
0
I
I
I
II
II-IIII
1999 2000 2001 2002 2003 2004 2005 2005 2007 2008 2009 2010 20\t 20t2
I Methane 0 0 0 0 0 1 0 0 0 1 2 2 0 2
IWind 5 1 6 4 11 11 18 18 29 2L L7 t2 4 8
I Solar 9 18 t7 L2 19 39 57 60 90 740 226 425 358 603
Figure t. Number of net metering opplications & registrations onnually. (2072 data os oI72/5/12.)
With the recent rise in number of PV installations, solar now accounts for almost 88% of all net metering
systems. Wind turbines represent under 8% of the systems and hydro just 3% (see figure 2.)
Net Metered Capacity
by Type
Figure 2. Net metering opplicotions & registrations by technology type.
To date, there have been no net metered fuel cells or combined heat and power systems in Vermont.
The exponential increase in the number of PV system installations has driven not only the overall
number of net metered systems but also the total growth of net metered system capacityl to over 20
MW (see figure 3).
Net Metering Applications - kW Capacity by Year and Type
1999 2000 2007 2002 2003 2004 2005 2006 2007 2008 2009 20tO 20tt 2012
Figure 3. Capacity of net metering applications by type. (2072 data as of 72/5/12.)
The capacity histogram (figure 4) shows that 59% of net metering systems permitted to date are less
than 5 kW,26% are between 5-10 kW and fewer than two percent are larger than 100kW.
I The capacity of a generator is the maximum output that the generator is capable of producing. It is an instantaneous
measure, and measured in Watts, kilowatts (kW), megawatts (MW), etc. Energy production is measured over time -
a I kW generator operating at that level for an hour produces one kilowatt-hour (kWh) of energy. Vermont's
summer peak load is near 1000 MW, and the state uses about 5.5 terawatt-hours each year.
5
1999 2000 2007 2002 2003 2004 2005 2006 2007 2008 2009 2010 2071 2072
Cumulatve
Capacity 54.85 t03.5!196.3!,Ai <,157.49 703.07 t009.!1303.:1797.(2834.i ;304.!11391 t4376 20910
I Methane 0.00 0.00 0.00 0.00 0.00 65.00 0.00 0.00 0.00 19.00 39.00 126.7:0.00 69.30
IWind 31.91 9.50 27.95 30.00 98.50 83.94 I18.5:101.5 t43.2!144.4t 191.91 179.5:223.5(L37.4t
I Solar 22.95 39.24 64.81 18.22 L14.4?96.64 188.3r 191.81 350.5:374.7t L927.C ;780.i 2751.!iAl 1
kW Capacity Histogram of
500
450
400
.g 3s0
E3 300
3 zsoot 2oo,z 150
100
50
0
&fuOalbLb ^ L$ P po f 4,o &o ,O ,9o,,$tro&O4?o
Capacity kW AC
Figure 4. Capocity (in kW AC) of oll net metered PV system applications
While the growth has been rapid and 20MW of small net metered systems represents a level of success
that some didn't think would be achieved, it represents a very small fraction of Vermont's overall
electrical portfolio. Only one utility (Washington Electric Cooperative) has more than 1% of their
customers participating in net metering. There are some smaller utilities that are approaching the 4%
capacity cap, but it is important to remember that the cap is based on capacity and not power
production. Net metering systems produce less than 1% of the power Vermont uses each year or about
35 GWh per year'.
3 Cross-SubsidizationAnalysis
This section describes the quantitative analysis conducted by the Department to examine the question
raised explicitly in Act L25: "... the report sholl include on anolysis of whether and to whot extent
customers using net metering systems under 30 V.S.A. 5 219a ore subsidized by other retail electric
customers who do not employ net metering." ln conducting this analysis, the Department was greatly
aided by information and suggestions received from numerous stakeholders through written comments,
data submittals, and meetings.
3.1 Literature review
ln order to frame the analysis for determining whether net metering represents a "cost-shift" from non-
participating ratepayers to net metering customers, the Department conducted a broad-based literature
review of relevant papers and studies. This review included over two dozen publications from a wide
variety of sources, including the National Renewable Energy Laboratory (NREL), the Solar America Board
' ln 2011, Vermont utilities sold 5,554 GWh of electricity to their customers.
for Codes and Standards (Solar ABCs), and a number of states and utilities on either the subject of net
metering benefits generally, or specifically on the rate impacts of net metering. Few of the publications
reviewed were directly comparable with each other, or with the specific net metering rules and
regulations in Vermont. However, information gleaned from these publications provided context that
informed assumptions made in the Department model.
One of the challenges facing Vermont is that the only one other state - California - has conducted a full
analysis of the cost-shift question (i.e., a full cost-benefit analysis) from a utility and ratepayer
perspective. The California study3 (and its subsequent updatesa's), along with two prior values-only
studies performed for specific utilities (Arizona Public Service6 and Austin EnergyT'8) form the basis for a
generalized methodology for analyzing the costs and benefits of net metering proposed by the Solar
America Board for Codes and Standardse. This methodology, however, only looks at exported (rather
than gross) generation from net-metered solar photovoltaic systems. For reasons explained below,
Vermont has chosen to look at gross generation, and at generation from a number of allowed types of
net metering technologies - not only solar. Therefore, the methodology serves as a good guidepost and
checkpoint for our work, but not an exact template.
Three other relevant statewide studies have been performed: two in New York and one in
Pennsylvania/New Jersey. One of the New York studies is a broad review of the benefits and costs to
ratepayers of increasing in-state solar capacity to 5,000 MW by 2O25to; while the other looks at the
overall costs and benefits of distributed solar to ratepayers and taxpayers in the New York City area1l.
The PA/NJ study is similar to the latterl'. The assumptions and methodologies used in these studies
were also helpful in framing our analysis.
Table l below summarizesthe results of relevant publications. Each study is unique, with distinct
definitions for the costs and benefits analyzed. ln many cases, costs and benefits not included in this
' Energy and Environmental Economics, lnc. (2010). Net energy metering (NEM) cost effectiveness evoluotion (E3
study). Available at http://www.cpuc.ca.govlPUC/energy/DistGen/nem_eval.htm.
o Beach, Thomas R. and Patrick G. McGuire (20121. Re-evoluoting the Cost-Effectiveness of Net Energy Metering in
Co I ifo rn i o. Berke ley, CA: Crossbo rder Energy.
s Beach, Thomas R. and Patrick G. McGuire (2}t2l. Evoluoting the Benefits ond Costs of Net Energy Metering for
Residentiol Customers in Colifornio. Berkeley, CA: Crossborder Energy.
' Distributed Renewoble Energy Operoting lmpocts ond Valuotion Study (20091. Seattle, WA: R.W. Beck.
'Braun, Jerry, Thomas E. Hoff, Michael Kuhn, Benjamin Norris, and Richard Perez (2006). The Value of
Distributed Photovoltaics to Austin Energt and the City of Austin. Napa, CA: Clean Power Research, LLC.t Ha*ey, Tim, Thomas E. Hoff, Leslie Libby, Benjamin L. Norris, and Karl R. Rabago (2012): Designing Austin
Energt's Solar TariffUsing a Distributed PV Volue Calculator. Austin, TX and Napa, CA: Austin Energy and
Clean Power Research.
' Keyes, Jason B. and Joseph F. Wiedman l2OL2). A Generolized Approoch to Assessing the Rate tmpocts of Net
Energy Metering. Solar America Board for Codes and Standards,
New York Solor Study: An Anolysis ofthe Benefits ond Costs of lncreosing Generation from Photovoltoic Devices in
New York (2012l'. Albany, NY: New York State Energy Research and Development Authority.
" Hoff, Thomas E., Richard Perez, and Ken Zweibel (2011). Solor Power Generotion in the IJS: Too Expensive, or o
Borgoin? Albany, NY: Clean Power Research, LLC.
" Hoff ,Thomas E., Benjamin L. Norris, and Richard Perez (2012). The Value of Distributed Solor Electric Generotion
to NewJersey ond Pennsylvono. Albany, NY: Clean Power Research, LLC.
7
table are discussed. Additional details of select studies are provided in a more extensive literature
review document, posted at http://publicservice.vermont.sov/tooics/renewable enerqv/net meterins.
Details of this Public Service Department study are included in Table l for comparison purposes.
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3.2 Cross-subsidization analysis decisions
Based upon the landscape of methodologies revealed in the broad literature review, the Department
made three threshold decisions regarding its cross-subsidization analysis framework, each described in
greater detail below:
o To examine the cost-benefit from a statewide ratepayer perspective, with consideration of two
scenarios which include and do not include monetary value for reductions in greenhouse gas
emissions;
o To include a clear, defined set of assumptions of the costs and benefits of net metering; and
o To include costs and benefits associated with all generation by net metering systems, rather
than only that generation that is exported to the electric grid.
The following subsections describe the conclusions the Department reached on each of these points.
The Department modeled the costs and benefits of net metered generation from three technologies:
fixed solar photovoltaic (PV), 2-axis tracking solar PV, and wind power. While there are a handful of net-
metered generators in Vermont that use agricultural methane or hydropower, over 95% of net-metered
generation uses either solar or wind power. ln addition, the Legislature has made special allowance for
agricultural methane in the Standard Offer program. The Department expects that the vast majority of
new net metering generation will continue to be powered by solar and wind energy.
3.2.L Ratepayer perspective
There are a number of different cost-benefit tests that an analysis could pursue to determine the impact
of net metering, each reflecting the different perspective.l3 The Department concluded that Act 125
requires a statewide ratepayer perspective. This is the appropriate analysis to evaluate any potential
subsidization of net metering participants by other Vermont retail electric customers. For simplicity and
clarity, the Department decided to consider the weighted average costs and benefits across all of the
state's utilities rather than model the costs and benefits for each utility separately.
ln addition, the Department supplements the state utility ratepayer perspective by the avoided costs of
greenhouse gas emissions that are currently externalized due to market failures. This calculation
attempts to quantify what the ratepayer costs and benefits would be if these costs were internalized in
" One perrpective is that of the participant (net metered customer), who receives lower electric bills in exchange
for expending the capital for the project. A ratepayer cost-benefit test captures costs and benefits to a utility's
ratepayers (including both those who install net metered systems and those who do not). This perspective
depends on the regulatory structure where utility recovers the costs from, and shares the benefits with, its
customers. Moving to a larger universe of impacted people, a study can examine the impact on all the ratepayers
in the state of Vermont. The largest scale is society as a whole.
Depending on the perspective considered for a cost-benefit analysis, a particular flow of value could be considered
a cost, a benefit, or a transfer. For example, the utility's cost from lost bill revenue is the participant's benefit from
reduced electric bills. Reduced Vermont contribution to regional transmission costs (for transmission already built)
is a benefit if the boundary is drawn at the utility or state level, but is simply a transfer of burden to other New
England ratepayers if society as a whole is considered. Under current policies, costs due to many environmental
impacts, such as greenhouse gas emissions, are borne by society as a whole, not just by Vermont or any single
utility's ratepayers.
10
the electricity market. The Department finds this addition appropriate given the State's emphasis on
greenhouse gas emission reductions, exemplified in statutory priorities (see, for example, 10 V.S.A. S
578 and 30 V.S.A. S 8001), and especially the statutory guidance in 30 V.S.A. S 218c to consider "the
value of the financial risks associated with greenhouse gas emissions from various power sources."
3.2.2 Costs and benefits
The Department examined the relevant literature, as well as the structure of New England and Vermont
electricity markets and regulation to identify the following costs:
o Lost revenue (due to participants paying smaller electric bills)
o The Vermont solar credit, for solar PV systems
o Net metering-related administrative costs (engineering, billing, etc.)
The Department identified the following benefits:
o Avoided energy costs, including avoided costs of line losses and avoided internalized
greenhouse gas emission costs
o Avoided capacity costs, including avoided costs of line losses
o Avoided regional transmission costs (costs for built or un-built pooled transmission facilities, or
PTF, embodied in the ISO-NE Regional Network Service charge and other regional changes
allocated in a similar fashion)
r Avoided in-state transmission and distribution costs (avoiding the construction of new non-PTF
facilities)
o Market price suppression
o Value associated with SPEED generation
Net costs and benefits were calculated both including and excluding the value of avoided greenhouse
gas emissions that are currently not internalized in the cost of energy. Ratepayers face a risk that more
greenhouse gas costs will be internalized in the future, potentially leading to stranded assets.
Costs and benefits are determined from a Vermont ratepayer perspective; transfers from entities which
are not Vermont ratepayers to Vermont ratepayers are included; any potential transfers between
Vermont ratepayers are not included.
The assumptions used for each of these costs and benefits are described in more detail in Section 3.3
below.
3,2.3 Generation to include
The literature review conducted for this study revealed one particular analytic choice made by the
Department that is different from some similar studies undertaken elsewhere: other analyses consider
the costs and benefits of only the generation that is exported to the grid from the site of the net
metering generator. That is, they do not consider the costs and benefits to the consumer, utility, or
society of generation that offsets load on-site. The Department considered the analytical option used by
others, but determined that this choice is not appropriate for Vermont because it would have been
unresponsive to the charge from Act 125 which asks for an evaluation and analysis of 30 V.S.A. 5 219a as
7L
a whole. lnstead, the Department's analysis considers all generation from net metering systems. Other
reasons for this choice include:
o The net metering solar credit is based on all generation;
o Simplified permitting is allowed for small net metering generators whether they produce
enough to spin their host's meter backwards or not;
o Generation from a net metering system can offset not only a customer's load but also service
and other charges;
o Group net metering and virtual group net metering options are available in Vermont. ln these
instances, generators are likely to be connected directly to the grid, and balancing of production
with load is only accounted for on paper each billing period rather than physically in net electric
energy flow through a meter.
3.3 Modelingassumptions
The spreadsheet modella estimates the costs and benefits incurred as a result of any single net metering
installation installed in 2013 or a later year. lt projects costs and benefits over the 2O-year period
following installation, allowing examination of the potential changing costs and benefits over that period
as well as calculation of a levelized net benefit or cost per kWh over 20 years.
3.3.1 What the model does not do
While model calculations are precise, and reflect the Department's best point estimate, they do not
estimate the width of the range of uncertainty surrounding each estimate due to the compounding
effect of multiple assumptions, each of which has its own uncertainty. ln addition, the model does not:
. Capture economic impacts outside of the utility-ratepayer context, such as job or economic
impacts from the renewable electricity industry or changes to the economics of energy
consumption among net metering participants or non-participants.
o ldentify impacts on energy prices, load shapes, or other inputs to the analysis that may have
already occurred due to deployment of net metering systems in Vermont. For systems modeled
as installed in years after 20L3, the model does not account for potential changes in Vermont's
load shape or other inputs that may occur prior to installation.
. Capture potential changes in rate structures or regional costs, including those due to net
metering. lt models only the marginal impact of net metering under a "current policy'' baseline
scenario. That is, it does not model a situation in which rate structures change over time (such
as adoption of time-of-use rates), or the impact that increasing net metering may have on future
rates or rate structures.
. Capture nonlinear or feedback effects in which additional deployment of net metering in
subsequent years may change marginal costs or benefits attributable to systems installed in
earlier years (such as through changes in load shape and resulting peak coincidence). For
example, it does not capture changes in the costs or benefits (such as avoided infrastructure
costs) attributed to systems deployed in 2013 that might occur if future net metering, or other
la Available for download from http://publicservicedept.vermont.sov/topics/renewable enersv/net meterins.
12
generation or efficiency deployment, changes the state's load shape and therefore the need for
or cost of infrastructure.
o lnclude impact from advanced metering infrastructure or other grid modernization
technologies, and the resulting potential changes to rate structures.
o Account for integration costs (incremental costs due to the need to change the output of other
resources to account for intermittency). These costs are expected to be very small for systems of
the size eligible for net metering in Vermont.
o lnclude monetary values for environmental impacts other than avoided greenhouse gas
emissions or value as SPEED resources.
. Capture differences between utilities. All numbers used are weighted statewide or region-wide
averaSes.
o Capture potential cross-subsidization between utilities. This should be very small as the costs
and benefits studied are utility-specific. Second-order effects of net metering are possible if net
metering penetration or the distribution of net metering technologies is very different between
utility service territories.
3.3.2 Economic assumptions
3.3.2.7 Inflation
The baseline expected long-term inflation estimate is2.45%. This is based on the market expectations
for inflation, measured by the difference between the return on inflation-protected and non-inflation-
protected long-term (>10 year) U.S. Treasury bonds (as measured in late November,2OL2l.
3.3.2.2 Discount rate
The Department's analysis uses two discount rates. One, referred to as the "ratepayer" discount rate, is
based on the cost of capital to individual ratepayers. The other, referred to as the "statewide" discount
rate, is based on a societal perspective on time preference in which the state as a whole has less strong
time preference than do individual ratepayers.
The ratepayer discount rate assumed in the Department's analysis is 8.03%. This rate was derived based
on analysis conducted by the U.S. Department of Energy for use in analysis of the cost-effectiveness of
appliance energy conservation standards.ls The analysis that U.S. DOE conducts for these standards
includes examination of the cost of capital faced by U.S. residential, commercial, and industrial energy
consumers. The Department weighted the three average values used in recent U.S. DOE rulemaking
proceedings by the three sectors' share of Vermont load, then adjusted for inflation.
The statewide discount rate assumed in the Department's analysis is5.52%. The Department assumes
that the state as a whole has a time preference similar to that of society at large. The Public Service
tt See, for example, analysis conducted for the standards of furnace fans
(httos://wwwl.eere.enerev.eovlbuildings/aooliance standards/residential/furnace fans.html)and electric motors
(httos://wwwl.eere.enerev.sov/buildinss/appliance standards/commercial/electric motors.html).
Board has adopted a value of 3%in real terms for societal screening of energy efficiency measures; this
value is 3% adjusted for inflation.l6
3.3.3 Costs and Benefits
ln the context ofthis study, "costs" and "benefits" are measured from the ratepayer standpoint. The
utility regulatory structure in Vermont (including GMP's alternative regulation plan, the co-op structure
of VEC and WEC, and the municipal structure of the state's other utilities) results in the relevant set of
costs and benefits faced by the state's utilities being passed to the state's ratepayers. For example,
utility costs include lost revenue, the solar credit, and administrative costs. Benefits include avoided
energy, capacity, transmission, and distribution costs. As a result, the proposed analytical framework
treats utility costs as ratepayer costs, and utility benefits as ratepayer benefits.lT
3.3.3.1 Costs
3.3.3.1.1 Reduction in utility revenue
Net metering reduces utility revenue by enabling a participating customer to provide some of their own
electricity (including, at times, spinning their meter backward while exporting energy), which reduces
their monthly bill. ln order to calculate the size of this reduction due to a modeled net metering
installation, the model requires the energy produced per year, along with the expected average
customer rate, and any solar credit. The current average electric rate applicable to most net metering
installations is 1.4.7 cents/kWh. This is the average residential electric rate; after the passage of Act 125
in the 2012 legislative session the vast majority of net metering installations in the state should be
credited at the residential rate. This is because these installations are in fact residential, or because they
are commercial accounts billed under a demand or time-of-use tariff - Act 125 established that such
commercial customers receive credit for net metered generation at the residential rate.
Generally speaking, electric rates are composed of energy, capacity, transmission, and other costs.
(Other costs include personnel/O&M and the carrying costs of the utility's investments in poles and
wires.) In order to project costs and benefits into the future, the Department has built a simple tool to
build a self-consistent projection of rates based on forecast market costs of energy and capacity,
forecast transmission costs, and an assumption that other utility costs will rise at some rate, for which
the Department chose to use the rate of inflation.
The analysis assumes that energy costs in rates are composed of a mixture of the market energy costs
seen in New England over the preceding L0 years: 2Oo/obased on market energy prices in the year in
question, 40% based on the average ofthe previous 5 years, and 40% based on the average ofthe
previous 10 years. Vermont's utilities enter into contracts of varying lengths, and the prices they are
willing to pay are based on the energy prices at the time, as well as projected energy prices. See the
discussion of "avoided energy costs" below for detail regarding the market energy price forecast.
" The discount rate is 5.52% rather than 5.45% because the two rates are most appropriately multiplied rather
than added. 1.0245x1.03 = 1.0552.
17 Externalities, such as the externalized portion of the value of greenhouse gas emission reductions, no not follow
this pattern.
The analysis assumes that market capacity costs equivalent to 50% of Vermont's peak are included in
rates; the remainder of capacity is self-supplied and therefore not subject to market fluctuations. (These
self-supplied capacity costs are included in the "other" category for utility infrastructure, O&M, etc.) See
the discussion of "avoided capacity costs" below for detail regarding the market capacity price forecast.
Regional transmission costs, embodied in the ISO-NE administered Regional Network Service charge,
account for the independent transmission portion of electric rates. The analysis assumes that these
costs are distributed in an even fashion across all of Vermont's kWh. See the discussion of "avoided
regional transmission costs" below for detail regarding the RNS forecast.
Once 20L2 energy, capacity, and transmission costs are removed from2Ol2 rates, the remainder must
reflect other costs.18 The Department assumed that these costs rise at the rate of general inflation. The
analysis makes one adjustment to account for known current circumstances: the guaranteed merger
savings resulting from the merger of GMP and CVPS. These savings come out of the "other" category,
and are assumed to total 5144 million in nominal dollars in 2OL2to 2021, then to continue at the same
annual nominal level in 2022 and later that they achieve in 2021.
The rate forecast resulting from this analysis is shown in Table 2, located in Section 3.3.3.2.L.
Solar photovoltaic net metering systems are eligible for a "solar credit" in addition to the value of their
rates. This credit is calculated by subtracting the residential rate from 20 cents/kWh. Therefore, the
state average solar credit in 2013 should be 5.3 cents per kWh generated. The value of this credit is fixed
for ten years for each installation at the value it had at the time the system was commissioned. As a
result, by the end of ten years the cost of each kWh provided by the solar net metering system could
significantly exceed 20 cents. The solar credit is guaranteed to each system for ten years. For systems
installed in later years, when rates are expected to be higher in nominal terms, the solar credit is
assumed to be correspondingly smaller.
3.3.3.7.2 Administrative costs
The Department did not receive quantitative data from any commenter regarding appropriate
administrative costs. The Department developed a set of assumed costs based on qualitative comments
that the current administrative burden on distribution utilities is split between two main tasks:
evaluating systems as they are submitted (a one-time cost related to engineering assessment and other
setup costs) and billing (which is predominantly a cost for group net metered systems, as billing
individual net metering is already or very easily automated). Based on qualitative comments, the
Department assumed that the total cost for these two tasks is approximately 5200,000 dollars per year
for the current pace and scale of net metering in Vermont, split roughly in half between initial costs and
on-going costs. To a rough approximation, this corresponds to a setup cost of approximately S20 per kW
of net metering system capacity, ongoing costs of about S20 per kW per year for billing group net
metered systems, and no on-going billing cost for individual net metered systems. The Department also
assumed that efficiencies in billing systems (aided by the standardization resulting from the Board's
" These other costs are also reflected in the monthly customer charge, which does not play a significant role in the
determination of net metering costs and benefits.
order regarding billing standards and procedures) would result in billing costs per kW falling at a rate of
20% per year.
3.3.3.2 Benefi*
3.3.3.2.7 Avoided enerry cost
From the perspective of the regional electric grid or a utility purchasing power to meet its load, net
metering looks like a load reduction. A utility therefore purchases somewhat less power to meet the
needs of their customers. While Vermont utilities purchase much of their energy through long-term
contracts, this kind of moment-by-moment change in load is reflected in changes in purchases or sales
on the ISO-NE day-ahead or spot markets. As a result, the Department assumes that the energy source
displaced or avoided by the use of net metering is energy purchased on these ISO-NE markets (the
difference between day-ahead and spot markets over the course of the year is minor).
Variable generators, like many of the types of generators deployed in Vermont for net metering, may
exhibit some correlation with the weather and therefore with market prices. For example, the season
and time of most solar irradiance is correlated (although imperfectly) with the peak summer loads, and
therefore somewhat higher regional electricity prices. ln order to capture this real correlation, the
Department calculated a hypothetical 2011 avoided energy cost on an hourly basis by multiplying the
production of real Vermont generators by the hourly price set in the ISO-NE market. This 2011 annual
total value was then updated to 2013 and beyond by scaling the annual total price according to a market
price forecast. The Department used hourly generation data from the Standard Offer program and net
metering systems deployed around Vermont.le Significant deployment of such systems has continued
this year, but relatively few systems operated for all of 2011. These calculations indicate that fixed solar
PV has a weighted average avoided energy price LO% higher than the annual ISO-NE average spot
market price, 2-axis tracking solar PV is L3% higher, and small wind is 5% lower.
The Department assumed that the capacity factor for each solar technology is projected capacity factor
using the NREL PVWatts tool for a location in Montpelier, using all PVWatts default settings. The
assumed capacity factor for wind is the 2011 capacity factor of the real Vermont generator used to
calculate the correlation. Separating the capacity factor from the price-performance correlation allows
the analysis to correct for differences between the typical capacity factors expected over many years for
a generic facility and the capacity factors exhibited for a limited number of generators in only one year.
Output from net-metered generators is expected to decay at a low rate as the generator ages. The
Department has assumed a rate of 0.5% per year; this is based on typical degradation rates for solar PV
systems.
The Department's market energy price forecast is based on known fonivard market energy prices for the
first five years, then known forward natural gas prices for years 5 to 10. Natural gas prices are an
1s Including a fixed solar array in Ferrisburgh, a two-axis solar tracker array in Shelburne, and a 100 kW wind
turbine near the Burlington airport.
16
appropriate proxy for scaling electricity prices because the marginal generator in New England, which
sets the price, is almost always a natural gas generator. Prices beyond 10 years are based on
extrapolation of the electricity and natural gas price trends seen in the market-derived forecast for years
1-10. Using forward market prices implicitly includes the value of net metering as a known-price hedge
against a volatile price of energy or natural gas. This is because the prices used in developing the
Department's fit are the known prices to lock in supply years into the future; these prices already have a
market-determined price risk adjustment included. The resulting energy price forecast (in nominal
dollars) is shown in Table 2. The values used in this analysis are averages of the market price forecast
conducted on three separate dates in October and November,2Ot2.
Energy generated by net metering systems on distribution circuits in Vermont is used locally, often on
the same property or within a few miles. Therefore, line losses from this energy are insignificant. The
energy being displaced, however, would be purchased on the bulk system and then transported to load,
with resulting line losses. Analysis conducted by utilities and the Department for the development of the
Vermont energy efficiency screening tool concluded that typical marginal line losses are about 9%. A
very similar line loss factor applies to capacity; the Department has assumed it to be the same factor of
9o/o.
L7
Table 2: Department assumptions and forecosts of ovoided energy, capacity, regionol transmission, and
in-state tronsmission ond distribution costs, olong with ossumed self-consistent residential rote forecost,
developed for this study. Values are in nominal dollors.
Residential
Rates
{s/kwht
Energy
(5/MWh)
Capacity
(s/kw-
monthl
Regional
transmission
(PrF) (s/kw-
monthl
Vermont
T&D (non-
PTF)
($/kw-
monthl
2012
2013
20t4
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
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s0.208
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So.zos
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3.3.3.2.2 Avoided capacity cost
Capacity costs are charged by ISO-NE to each of the region's utilities in order to offset the region's
payments to generators through the Forward Capacity Market. (This market assures that enough
capacity is available in the region to meet load during extreme weather or grid emergencies.) These
18
costs are allocated to each utility based on its share of the ISO-NE regional peak load. The value
provided by net metering systems is based on average performance (power output) during the time of
peak system demand. For the bulk grid perspective, net metering systems look like a reduction in
demand, and therefore reduce the utility's cost for capacity.
There are multiple potential methods to measure the effective capacity of generators with respect to
different purposes. ln determining the peak coincidence factors described in this or following
subsections, the Department used the average performance of real in-state generators during particular
times of day and particular months, as it determined were appropriate for the purpose at hand based on
known cost allocation mechanisms or parallels with the treatment of energy efficiency. For example, the
Department estimated economic peak coincidence for each generation technology by examining 20L0,
201L and 2012 performance of examples of each technology during afternoons in the month of July;
ISO-NE peaks typically occur during July afternoons. These values were calculated based on the output
of ten 2-axis tracking solar PV generators, four fixed solar PV generators, and two small wind generators.
The resulting capacity peak coincidence values are shown in Table 3.
The capacity price forecast assumed by the Department, and used by default in the model, is based on
recent electric utility regulatory filings including lntegrated Resource Plans and purchase power
acquisitions. The resulting capacity price forecast (in nominal dollars) is shown in Table 2.
Table 3: Deportment ossumptions of net-metered generotors' performonce during peak times used to
calculote values of avoided capocity, ovoided regional RNS cosf, and ovoided in-stote transmission and
distribution infrastructure. Each value shows the froction of the system's roted copacity thot is assumed
in the calculation of the volue of the three avoided costs. For exomple, in colculating the value of avoided
capocity costs due to a fixed solor PV system with o nomeplote capocity of 100 kW, the system is
assumed to reduce capacity costs by the some omount as o system thot can output 49.5 kW ond is
alwoys running or perfectly dispatchable. These values were colculoted bosed on the output of ten 2-axis
tracking solor PV generators, four fixed solor PV generotors, ond two small wind generotors.
Capacity RNS ln-state T&D
Fixed PV
Tracking PV
Wind
0.495
0.595
0.045
o.2t6
0.263
0,069
o.476
0.562
0.050
3.3.3.2.3 Avoided regional transmission costs
Regional Network Service (RNS) costs are charged by ISO-NE to each of the region's utilities to pay for
the cost of upgrades to the region's bulk transmission infrastructure. These are costs that have already
been incurred, or are required to meet reliability standards, and thus cannot be entirely avoided - only
their allocation among New England ratepayers can be changed. Avoiding these costs through net
metering shifts the costs to ratepayers in other states. These costs are allocated to each utility based on
its share of the monthly peak load within Vermont. The model uses values calculated by examining
performance of Vermont generators during hour ranges when monthly peaks have occurred in Vermont
over the last 5 years. The resulting average monthly peak coincidence values are shown in Table 3.
19
The values assigned to this cost are based on the ISO-NE forecast of the next 5 years' worth of RNS
costs, and escalated based on historical increases in the Handy-Whitman lndex of public utility
construction costs. ISO-NE forecast RNS costs increase al L0% or more per year from 2012 to 2017, but
the Department assumes that flattening regional peak loads, including demand response and distributed
generation, will reduce this growth rate. The resulting regional transmission price forecast (in nominal
dollars) is shown in Table 2.
3.3.3.2.4 Avoided in-state transmission and distribution costs
ln-state transmission and distribution costs are those costs incurred by the state's distribution utilities or
VELCO and which are not subject to regional cost allocation. The values used in this model are derived
from those in the recently completed avoided transmission and distribution cost working group for the
update to the electric energy efficiency cost-effectiveness screening tool. This working group consisted
of representatives from the state's distribution, transmission, and efficiency utilities, and the
Department. The values used in the model have been converted to nominal dollars using the assumed
rate of inflation.
The in-state transmission and distribution upgrades deferred due to load reduction or on-site generation
(such as net metering) are driven by reliability concerns. Therefore, rather than average peak
coincidence for a net metering technology, the critical value is how much generation the grid can rely on
seeing at peak times. Therefore, the Department calculated a "reliability" peak coincidence value,
separate from the "economic" peak coincidence used in avoided capacity and regional transmission cost
calculations. The Department calculated a reliability peak coincidence by calculating the average
generator performance of several Vermont generators during June, July, and August afternoons. This
corresponds to the methodology that ISO-NE uses to value energy efficiency in the Forward Capacity
Market, results of which are used for transmission planning purposes. The resulting reliability peak
coincidence values are shown in Table 3.
3.3.3.2,5 Marketpricesuppression
Reductions in load shift the relationship between the supply curve and demand curve for both energy
and capacity, resulting in changes in market price.20 Because net metering looks like load reduction, the
Department has approximated the market price suppression effect using analysis based on the 2011
Avoided Energy Supply Cost (AESC) study's calculation of the demand reduction induced price effect
("DRlPE") for Vermont. Energy DRIPE is a fraction of the value of avoided energy supply (starting at 9%
and decaying over time), while capacity DRIPE has varying values over time, averaging to between 52
and 53 per kW-year. The assumptions regarding load, prices, and other factors used in the AESC study
do not correspond directly to the assumptions used in this study, and load reduction with the particular
load shapes corresponding to solar PV or wind generation are likely dissimilar from those from energy
efficiency. As a result, the value attributed to net metering generation from this mechanism is very
much approximate.
20 This kind of market price suppression is a transfer between generators and ratepayers, so it is a benefit from a
ratepayer perspective but would not be included in a societal cost-benefit analysis.
20
3.3.3.2.6 Value associated with meeting SPEED goals
The model allows for assignment of a value that ratepayers see that is attributable to the type of
generation used by net metering systems installed by other customers. The analysis does not include, or
attempt to quantify, the value of renewable attributes (such as RECs) to the participating customer, who
is assumed to retain ownership of those attributes. Ratepayers see monetary value associated with the
type of net metering technology and resource used by other customers' net metering through the fact
that net-metered generation would help the state's utilities meet their SPEED goals. (The state has goals
of 2oo/o new SPEED resources by 2Ot7 and75% renewable electricity bV 2032.1lf a utility were to acquire
SPEED resources elsewhere, there would likely be a small premium cost compared to market costs. This
avoided premium is a benefit to all utility ratepayers from net-metered generation. Based on
conversations with commenters the Department assumes this value is S5/MWh (fixed in nominal dollar
terms).
3.3.3.2.7 Climate change
The Department's analysis calculates the costs and benefits of net metering to the state's non-
participating ratepayers both with and without the estimated externalized cost of greenhouse gas
emissions. lt should be noted that these benefits from a marginal net metering installation in Vermont
do not flow to Vermonter ratepayers in direct monetary terms. lnstead, they reflect both a societal cost
that is avoided and the size of potential risk that Vermont ratepayers avoid by reducing greenhouse gas
emissions. lf these environmental costs were fully internalized, for example into the cost of energy,
ratepayers would bear those costs. The Department is assuming a value of S80 per metric ton of CO2
emissions reduced (in 52011); this is the societal value adopted by the Public Service Board for use in
energy efficiency screening, and is intended to reflect the marginal cost of abatement. About 52 of the
S80 is internalized in utility costs through the Regional Greenhouse Gas lnitiative, so the analysis
incorporates an additional cost of about S78 (in 52011) for cases in which costs of environmental
externalities are included.
CO2 emission reductions are calculated by using the 201.0 ISO-New England marginal emission rate of
943 lbs/MWh." ISO-NE grid operations and markets almost always result in a gas generator dispatched
as the marginal plant, so this value is comparable to the emissions from a natural gas generator. The
Department's analysis does not track or account for emission or abatement of other greenhouse gasses.
3.4 Results of Cross-Subsidization Analysis
3.4.1 Systems Examined
This report presents the results of the cross-subsidization analysis for 5 systems, representing typical
cases in Vermont:
o A 4 kW fixed solar PV system, net metered by a single residenceo A 4 kW 2-axis tracking solar PV system, net metered by a single residenceo A 4 kW wind generator, net metered by a single residenceo A 100 kW fixed solar PV system, net metered by a group
'' http://w**.iso-ne.com/genrtion-resrcs/reports/emission/final-2010-emissions_report_v2.pdf
2L
. A 100 kW 2-axis tracking solar PV system, net metered by a group
o A 100 kW wind generator, net metered by a group
3.4.2 Results for Systems Installed in 2013
The methodology described in section 3.3 allows the model to calculate costs incurred and benefits
received from each typical net-metered generator on an annual basis. These values may also be
combined into a 20-year levelized value. A levelized value is the constant value per kWh generated that
has the same present value as the projected string of costs and/or benefits over the 20-year study
period. This section presents graphs of the annual costs and benefits along with levelized costs, benefits,
and net costs (costs minus benefits). Benefits are presented both with and without externalized carbon
emission costs; levelized values are also presented from both an individual ratepayer and statewide
perspective (corresponding to different discount rates).
22
3.4,2,1 4 kW fixed solar PV system, net metered by a single residence
A 4 kW fixed solar PV system would generate about 4,500 kwh annually with a capacity factor ol L3.O%.
Figure 5. Annuol costs ond benefits associated with a 4 kW fixed solar PV residentiol system installed in
2073.
Table 4. Levelized cost, benefit, ond net benefit of a 4 kW fixed solar PV residential system instolled in
2073 to other rotepayers individually ("ratepoye/') or statewide.
Units: S per kWh GHG value included
Ratepayer 0.22L
0.tmo
0.350
ll
6.E 0.300
Eot
o 0.250
=E
E o.2m
Eoo
o 0,150
6oIJ
E o.rmtE
0.050
0.000
-
test5 p61 [!![
rar lepfit5 pr [!t/fi
-
. Benefits per kwh w/ GHG
"d9"d|"dr&""$"^s"".f ".sr"n$"C".$dr$r&"rd8"""tr"{t"d,""dP
23
3,4.2.2 4 kW tracking solar PV system, netmetered by a single residence
A 4 kW 2-axis tracking solar PV system would generate about 6,000 kwh annually with a capacity factor
of L7.t%.
Figure 6. Annuol costs and benefits associoted with o 4 kW trocking solor PV residentiol system instolled
in 2013.
Table 5. Levelized cost, benefit, and net benefit of o 4 kW trocking solor PV residentiol system instolled in
2073 to other rotepayers individuolly ("ratepoyef ) or stotewide.
0.'100
0.350
<r|
E o.*
EoE
o 0.250!o
E o.2oo
troll
o 0.150
6o
E o.rmtrc
0.050
0.000
-
costs per kwh
--- Benefits per kwh
-
. Benefits per kWh w/ GHG
ua / \---tt'
,d9"d9"S"e"rd$ro."-f "&t"S"Srd".$"S"&""dr."tr.f ".g"".'r""P
GHG value included
24
3.4.2.3 4 kW wind generator, netmetered by a single residence
A 4 kW wind generator generates approximately 2,500 kWh per year, with a capacity factor of 7.4%.lf
such a generator were sited optimally, it could have a significantly higher capacity factor and generate
more electricity. However, the per-kWh costs and benefits described here would be unlikely to change
significantly.
Figure 7. Annuol costs ond benefits ossocioted with a 4 kW residentiol wind generator instolled in 2073.
Table 5. Levelized cost, benefit, and net benefit of a 4 kW residentialwind generotor instolled in 2073 to
other ratepoyers individually ("ratepayer") or stotewide.
0.1100
0.350
1t|
E o.*
Eot
o 0.250
=t
S o.zm
Eo!
o 0.1y)
o(J
E o.rmtE
0.050
0.0(n
-
Costs per kwh
- -- Benefits per kwh
-
. Benefits per kwh w/ GHG
"d9"d9"d9"e""$d"d9".drt"S"Soso$"d"&"".O"&""dr"d"dt'rdP
25
3,4.2.4 700 kWfixed solar PV system, group netmetered
A 100 kW fixed solar PV system would generate about 114,000 kWh annually with a capacity factor of
L3.O%.
Figure 8. Annuol costs and benefits ossociated with o 100 kW fixed solar PV group net-metered system
installed in 2073.
Table 7. Levelized cost, benefit, ond net benefit of a 700 kW fixed solor PV group net-metered system
installed in 2073 to other rotepayers individually ("ratepoyer") or stotewide.
0.350
lrl
E o.r*
EoEo 0.2503E
E o.2mcoII
o 0.19)
or,
E o.rmgtr
0.050
0.000
-
costs per kwh
r r r $gn6fits per kwh
-
. Benefits per kwh u GHG
"d9""f ".sf ".$"""d$r&trd".&"ad,PadP.!..f ao+.f "eo"Sn&t"d""'rt"dn"d
26
3.4.2.5 700 kW tracking solar PV system, group netmetered
A 100 kW 2-axis tracking solar PV system would generate about 150,000 kWh annually with a capacity
factor of L7.Lo/o.
Figure 9. Annual costs ond benefits ossocioted with o 700 kW tracking solar PV group net-metered
system instolled in 2073.
Table 8. Levelized cost, benefit, ond net benefit of o 700 kW trocking solar PV group net-metered system
instolled in 2073 to other ratepayers individually ("rotepaye/') or statewide.
0.400
0.350
{r}
E ,.r*
EotE o.zso
=E
S o.zm
Eoo
o 0.1506oI
E o.rmEc
0.050
0.000
-
Costs per kwh
-- - Benefits per kwh
-
.BenefitsperkwhvGHG
"*"$"S"e""S"&""Sp""SnS..$,-s"d"^&"fo.,.&trdrdrd,-a
27
3,4,2,6 700 kW wind generator, group net metered
A 100 kW wind generator generates approximately 65,000 kWh per year, with a capacity factor of 7.4%.
lf such a generator were sited optimally, it could have a significantly higher capacity factor and generate
more electricity. However, the per-kWh costs and benefits described here would be unlikely to change
significantly.
Figure tO. Annual costs ond benefits associated with o 700 kW group net-metered wind generator
instolled in 2073.
Table 9. Levelized cost, benefit, ond net benefit of a 700 kW group net-metered wind generator installed
in 2073 to other rotepoyers individuolly ("ratepoye/') or statewide.
3.4.3 Systems Installed in ComingYears
Costs of energy, capacity, and transmission which contribute to electric rates may also be avoided by a
net metered generator. These costs are projected to change over time. ln addition, as electric rates rise
the solar credit that applies to a newly installed net metered solar generator is expected to fall. This
leads to the guestion of how the analysis of cross-subsidization presented in the previous section is
likely to change for systems installed in future years.
0.400
0.350
{^
6E 0.3fi).E
oEo 0.25t)sl!
E o.2oo
oo
o 0.150
o
E o.rmEtr
0.050
0.0m
-
te515 psl l\ /tt
roo ls1sfit5 pEp [\i![
-
. Benefits per kwh w/ GHG
"d9"d9""f "&""r$ros,o9p""S"Srd.d""tr"d,""$"&"""trrdP"dt'"d*
28
While the analysis described in this section is necessarily more uncertain than the analysis presented in
the previous section, it does provide some directional information and insights regarding future costs
and benefits. The limitations of the model the Department developed for the cross-subsidization
analysis also limit this analysis. ln particular, the avoided transmission and distribution costs attributable
to net metered generation depend on the State's and utilities' load shapes (particularly including the
timing of monthly and seasonal demand peaks). Load shapes will change as net metering is deployed,
saturation of appliances changes, and electric energy efficiency measures are implemented. Projections
of costs and benefits are necessarily more uncertain as they reach further into the future.
ln orderto undertake this secondary analysis, the Department modeled the costs and benefits, as in
Section 3.3, but for systems installed in years after 20L3. The following figures illustrate the changes in
net costs and benefits for residential-scale systems installed in subsequent years. (The results of large-
scale systems are similar, as illustrated in the previous section, and are omitted here for brevity.)
Qualitatively, the benefits of solar PV net metered generation increase more quickly than the costs (due
in large part to the decreasing solar credit), so that solar PV systems installed in later years have greater
net benefit than systems installed in 2013. The same is not true for wind generation.
Figure t1.. Levelized net benefit of a 4 kW individual net metered fixed solor PV system installed in eoch
year 2013 to 2018. Four lines show the net benefits from the perspective of a typical Vermont ratepoyer,
from the statewide perspective of oll rotepoyers, ond both including and excluding the volue of GHG
emission reductions due to system operation.
3
6E'E
oc
G0,c0o
ozto
Eo
oJ
0.05
0.04
0.03
0.02
0.01
0.00
+Ratepayer- no G HG
+Ratepayer--GHG
internalized
+Statewide-" noGHG
-t+Statewide -- GHG
internalized
Year of system lnstallation
29
Figure 12. Levelized net benefit of o 4 kW individuol net metered 2-oxis tacking solor PV system instolled
in eoch yeor 2013 to 2018. Four lines show the net benefits from the perspective of a typical Vermont
rotepayer, from the statewide perspective of oll rotepoyers, and both including ond excluding the volue
of GHG emission reductions due to system operation.
0.07
o-05
E! o.os
0
E o.*.E
o5 o.o:Eog3 0.02
(,cz 0.01!tU.!6 o.oo
oJ
..a-Ratepayer- noGHG
.a-Ratepayer - GHG
internalized
+Statewide-- noGHG
-L-Statewide -GHG
internalized
-0.01
-0.02
Year of System lnstallation
Figure 13. Levelized net benefit of o 4 kW individual net metered wind generator system instolled in each
yeor 2013 to 2018. Four lines show the net benefits from the perspective of o typicol Vermont ratepoyer,
from the statewide perspective of all rotepoyers, ond both including ond excluding the value of GHG
emission reductions due to system operotion.
0.00
-0.01
-0.02
-0.03
2013 20L4 20t5 2076 2017
3I
E -o.oscoco6 -0.06
Ez
E -0.07g
9 -o.oaI
-0.09
-0.10
+Ratepayer-- noGHG
+Ratepayer- GHG
internalized
-.FStatewide -- noG HG
*-Statewide -GHG
internalized
Year of System lnstallation
30
3.4.4 Concluding Remarks on Cross-Subsidization
The analysis presented in the preceding sections indicates that net metered systems do not impose a
significant net cost to ratepayers who are not net metering participants. Net benefits from solar
photovoltaic systems, which represent nearly 88o/o of net metering systems, are either positive or
negative depending on the discount rate chosen and whether the value of non-internalized greenhouse
gas emissions are included or not included respectively. There would be real long-term risk to ratepayers
if decisions were made that assume no increase in the internalization of these costs over the 20-year
analysis period for this study. lmpacts on transmission and distribution infrastructure costs are a
significant component of the value of net-metered systems. Solar PV has much greater coincidence of
generation with times of peak demand than does wind power; this results in more net benefits for solar
PV than for wind. Wind power has net costs whether greenhouse gas emissions costs are included or
not. Given the relatively small scale of wind system net metering in Vermont, the Department does not
consider this to be a significant cost to ratepayers.
4 General assessment of Vermont's net metering statute, rules, and
procedures
The Department has reviewed the relevant statutes, rules, and general policy in Vermont, and the
results of the cross-subsidization analysis described in Section 3. The Department's general assessment
is that Vermont's current net metering policy is a successful aspect of State's overall energy strategy
that is cost-effectively advancing the state's renewable energy goals. Net metering in Vermont has
undergone a significant growth, enabled in part by changes in state policy and statutes, as well as by
changes in technology costs and business models. ln addition to the costs and benefits discussed in the
preceding sections, net metering has enabled the growth of numerous small businesses, which employ
hundreds of Vermonters and form an important part of the foundation of Vermont's clean energy
economy. Based on this success and the analysis presented in this report, the Department has
concluded that there is no need for statutory changes at this time.
The Department highlights the process, led by the Public Service Board (PSB), to clarify and make more
uniform the billing standards and practices associated with net metering. The PSB issued an order with
billing standards and procedures on November L4,20L2, and has the authority to revise these standards
as may be warranted. While additional changes may be required as utilities and regulators understand
billing cases and configurations not yet covered in the standards, utilities should expeditiously update
their tariffs and procedures to match the Board's order. These efforts should provide clarity and
uniformity; lack of clarity and uniformity had been an area of concern to the Department. Stability in
utility procedures and state policies would provide an opportunity to better understand the impacts of
current policies and allow regulatory processes to come up to date. For example, such stability should
allow the PSB to update their net metering rule (5.100) to reflect statutory changes and updated
interconnection standards since the rule was last updated. The PSB has the authority to raise the 4%
capacity cap for each utility, reducing any future need to raise that cap through statutory change.
31
BEFORE THE IDAHO PUBLIC UTITITIES COMMISSION
IN THE MATTER OF THE )
APPLTCATTON OF rDAHO POWER )
COMPANY FOR AUTHORITY TO ) CASE NO. lPC-8.12-27
MODIFY ITS NET METERING )
SERYICE AND TO INCREASE THE )
GENERATION CAPACITY LIMIT. )
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
CONFIDENTIAL
EXHIBIT 203
ANALYSIS OF CUSTOMER BILLS BEFORE AND AFTER SOI/.R NEM SYSTEM USING
IDAHO POWER CONFTDENTIAL RESPONSE TO rCL PRODUCTTON REQUEST NO. 13.
Exhibit 203
BEACH, Di
Idaho Conservation League
IPC-E-12-27
BEFORS THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFY ITS NET METERING
SERVICE AND TO INCRXASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC-E-I2-27
Idaho Consenration League
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 204
IDAHO POWER RESPONSE TO ICL PRODUCTION REQUETS NO I
REQUEST NO. 1: Please provide the most recently used altemate costs for
analyzing demand skJe resources. Please provide these costs for each hour of the year
and for the future 20 years. Please provide these costs in excel spreadsheet or other
digitalformat.
RESPONSE TO REQUEST NO. 1: The most recent costs for analping
demand-side resources were produced in the 2011 lntegrated Resource Planning
flRP') process. ln addition, Attachment 1 (attached hereto) contains hourly avoided
costs from January 1,2011, to December 31 ,2029. Attachment 2 (attached hereto)
contains copies of the 2011 IRP Appendix C, pages 66 to 71 . This section of Appendix
C explains the derivation of the Demand-Side Management ("DSM") altemative costs.
These costs are averaged in timeof-use type pricing categories for analysis of DSM
resources. Please note, the Summer On-Peak prices are calculated using ldaho
Powe/s 30-year levelized capacity, variable ene(,y, and operating costs of a 170
megawatt ("MW') Simple Cycle Combustion Turbine.
The response to this Request was prepared by Pete Pengilly, Customer
Research and Analysis Leader, ldaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REOUEST OF THE IDAHO CONSERVATION LEAGUE TO IDAHO POWER COMPANY - 2
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFY ITS NET METERING
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC-E-12-27
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 205
IDAHO POWER 2013 IRP DSM STATUTS UPDATE
ocToBER tr,2ol3
2013IRP DSM Status Update, slide 4
2013 IRP DSM Status Update -
2011vs. 2013 IRP Cost
Comparison
Average Annual DSM Ahematlve
costs (nomlnal$/Mwh)
S18o
S160
Sr4o
$t2o
$1oo
S8o
S5o
$40
$20
$o
,dP ,st "dF ,s" d
-2013
tRp Summer Mk, peak Hou6
-2011
IRP Summe. Mid Peak Houts
Comparison of Summer Mid-Peak Hours (7am-1pm and 9-11pm)
between 2011 and 2013 IRP Alternative
CERTIFICATE OF SERVICE
I hereby certifr that on this 10th day of May 2013,I delivered true and correct
copies of the foregoing DIRECT TESTIMONY OF R. THOMAS BEACH ON BEHALF
OF THE IDAHO CONSERVATION LEAGUE to the following persons via the method of
service noted:
Hand delivery:
Jean Jewell
Commission Secretary (Original, nine copies, and one CD-ROM provided)
Idaho Public Utilities Commission
427W. Washington St.
Boise,lD 83702-5983
City of Boise
R. Stephen Rutherford
City of Boise City,Idaho
P.O. Box 500
Boise, ID 83701-0500
BoiseCityAttorney@cityofboise. org
Iohn R. Hammond, Jr.
Batt Fisher Pusch & Alderman, LLP
P.O. Box 500
Boise,ID 83701
[e-mail]
Idaho Clean Energy Association
Dean J. Miller
McDevitt & Miller, LLP
P.O. Box 2564-83701
Boise,Idaho 83702
j [e-mail]
Snake River Alliance
Ken Miller
Clean Energy Program Director
Snake River Alliance
P.O. Box 1731
Boise,ID 83701
Electronic Mail:
Lisa D. Nordstrom
Regulatory Dockets
Matt Larkin
Greg Said
Idaho Power Company
P.O. Box 70
Boise,Idaho 83707
lnordstrom@idahopower. com
[e-mail]
[e-mail]
[e-mail]
PowerWorks. LLC
Chris Aepelbacher, Project Engineer
5420W. Wicher Road
Glenns Ferry, Idaho 83623
[e-mail]
Pioneer Power, LLC
Peter I. Richardson
Richardson & O'Leary
5ls N. 27 thSt
Boise,Idaho 83702
[e-mail]
]ohn Steiner
24597 Collett RD
Oreana, Idaho 83650-5070
[e-mail]
kmiller@snaker
Benjamin J. Otto
CERTIFICATE OF SERVICE IPC-E-t2-27