20220921Comments.pdf

Marie Callaway Kellner (ISB No. 8470)
710 N 6ft Steet
PO Box 844
Boise,ID 83701
(208) s37-7993
mkellner@idahoconservation. org
Attorney for the Idaho Conservation League
BEFORE THE IDAIIO PI]BLIC UTILITIES COMNIISSION
*,t i,: li2
IN THE MATTER OF IDAHO )
POWER COMPAI\Y'S )
APPLICATION TO COMPLETE )
THE STUDY REVIEW PTIASE OF )
THE COMPRETTENSTVE STUDY )
OF COSTS AI\[D BEI\IEFITS OF ON. )
SITE GENERATION & FOR )
AUTIIORITY TO IMPLEMENT )
CIIAI\GES TO SCHED[ILES 6,8, )
AI\D 24 )
CASE NO. IPC.E-22-22
IDAHO CONSERVATION LEAGUE
INITIAL COMMENT
Introduction
The Idaho Conservation League ("ICL") submits to the Idaho Public Utilities
Commission ("Commission") the following initial comments regarding Idaho Power Company's
("[PC" or "Company'') Value of Distributed Energy Resources Study ("VODER study" or
"study''). ICL supports the development of dishibuted solar generation and other dishibuted
energy resources (*DER") as key components of a reliable, cost effective, and carbon neutral
energy portfolio. ICL appreciates the Company's clarity and detailed explanations in the
VODER study and reppects its continued commitnent to industry, customer, and community
involvement. Its engagement is welcome, and critical to resolve complex policy and technical
issues in the public interest. Nonetheless, ICL is concemed that the VODER study undervalues
Ipeno Punlrc Uru.trIrs CourraIssIoN, Case No. IPC-E-22-22
Idaho Conservation League, Initial lntervenor Comment
Page I
dishibuted generation to a degree that will inhibit development and contribute to an adverse
economic and regulatory environment in future policy decisions.
ICL co-commissioned Crossborder Energyr to review IPC's VODER study. The resulting
critique ("Crossborder review" or "critique", included with comment as "ATTACHMENT A")
assesses IPC's VODER study using data from IPC's integrated resource plan ("IRP";, discovery
productions, and publicly available data. The Crossborder review concludes that [PC's choice of
assumptions and methodologies undervalue distributed resources and corresponding export
credit rate ("ECR"). Additionally, the critique identifies benefits and costs that are quantifiable
and measurable, and avoided costs that effect rates that IPC was required to studf but were
either omitted, diminished, or defined outside its scope of review. On both the listed price
components and other identifiable costs and benefits, the VODER study substantially
undervalues distributed energy resources.
Just as Order No. 35284 directed IPC to assess five components of the value of solar
resources3, the Crossborder review applied the same data sets or reasonable, necessary
altematives to industry recognized methods and assumptions for each component. The resulting
ECR recommendations are more favorable to DERs and consistent with industry standards and
regional prices. Crossborder demonstates that differing analytic choices by reasonable,
competent industry professionals produce widely varying figures, and that IPC's choices in the
VODER study consistently devalued its distributed energy ECR.
This comment focuses on the VODER study's ECR estimates and other identifiable costs
and benefits. Methodological critiques and altemative ECR estimates presented by the
I Crossborder Energy is an energy consulting firm. Thomas Beach is its principal and prepared the commissioned
review (CV included with comment as "ATTACHMENT B").
2 Order No. 35284 at 27 Case No. IPC-E-21-21.
3 Id. at 14.
loeno Punuc UnurrEs CouurssroN, Case No. IPC-E-22-22
Idaho Conservation League, Initial lntervenor Comment
Page2
Crossborder review are introduced for each of the five components of the ECR: a) avoided
energy costs; b) avoided generation capacity; c) transmission and distribution ("T&D") deferral;
d) line losses; and e) integration costs. Fuel hedging benefits and avoided costs ofcarbon
emissions are introduced as quantifiable components of the value of DERs that affect rates.
Other environmental and extemal costs identified in the Crossborder review are separately
discussed.
ICL's initial comment and the attached Crossborder review highlight the importance of
selecting an appropriate set of assumptions and methodologies in assessing energy value.
Accordingly, ICL asserts that the VODER study underestimates the value of solar generation by
relying on dated data, unfavorable assumptions, and methodologies that selectively disfavor
distributed energy resources.
Discussion
1. Idaho Power Company's VODER study consistently applies assumptions and
methodologies that minimize the estimated Export Credit Rate.
ICL disputes the VODER study's estimated ECR. While IPC's analysis generally
complies with the Commission's direction to study individual components of ECR, it
consistently does so with assumptions and methodologies that minimize the estimated value of
solar generation. ICL does not claim the Company's analysis is facially wrong. However, we are
concerned that the study repeatedly exercises discretion in its calculations that favor the
Company's programmatic and business aims at the expense of distributed generation
development.
Ioeno Pust.rc UrLtrtes CouutsstoN, Case No. IPC-E-22-22
Idaho Conservation League, hritial lntervenor Comment
Page 3
ICL previously raised concenm about the objectivity and incentives of an internal study
when establishing the project framework.a Others parties also requested third-party study
preparation or review.s While the Commission balanced the needs for a cost-effective and
system-specific study, the study order recognizes the "argument that third-party evaluators have
a different perspective and the results may be believed to be more credible by some customers."6
Along with the study and its conclusions, the Commission directed the Company to provide
sufficient data o'so others have insight as to how the results were derived.'7 lcLcommissioned
Crossborder Energy to provide such insights into the VODER study's ECR. Discrepancies
between IPC's analysis and the Crossborder critique represent good faith disagreement between
qualified professionals. We offer the following comments on the five required components of
ECR to illustrate the importance of methodological objectivity and to afford parties the benefit of
expert review.
a. Disruption to fossil fuel markets makes the study's inputs and estimates of avoided
costs outdated and insufficient to meaningfully inform the Commission.
The VODER study estimates avoided energy costs with dated price assumptions made
irrelevant by disruption to energy markets caused by the Russian invasion of Ukraine. The
Commission directed IPC to base avoided cost calculations and on best available information,
including current energy price assumptions, the most recent IPR inputs, and market price index
assumptions.s While the VODER study applies these inputs, modeling used in the 2021 IPR
process and indexes based on past market performance do not account for considerable increases
a ICL Reply Comments at 4, PC-E-21-21 . Again,ICL does not impute the competency or professionalism of IPC.
The Company continues to exempliff transparency, cooperation, and communication amongst interested parties.
5 Order No. 35284 at l0-l l. ICEA and Kluckhohn requested a third-party study. ISON requested third-party review
Staff noted environmental and other benefits were reviewable by third-party.
6 Id. atll.
7 Id.
8 Id. at 16-17.
Ioeso Pusrtc Urllntrs Corrtulssror.r, Case No. IPC-E-22-22
Idaho Conservation League, Initial Intervenor Comment
Page 4
in energy prices and volatility in the spring and summer of 2022. Without accounting for this
lasting shift in energy markets, the VODER study fails to present an accurate or meaningful
estimate of avoided energy costs.
Crossborder Energy recalculated avoided energy costs using data and energy price
forecasts that reflect post Ukrainian invasion energy markets.e The review was completed in late
August of 2022 and uses Energy Imbalance Market ("ElM") prices for the full year ending July
31,2022 to better represent current market conditions. With updated data and forecasts,
Crossborder estimates the avoided energy costs of distributed generation at $47.30 per MWh,
well above IPC's estimates based on the 2021 IRP forecast, ICE Mid-C, or ELAP prices.l0 The
VODER study relies on older data sets for its IRP market forecast that do not account for recent
disruptions and a three-year rolling averages of historic ELAP and ICE Mid-C prices estimate
avoided costs.rl While longer period averages are useful to mitigate short-term variability, they
sacrifice sensitivity to lasting paradigm shifts as occurred this year. IPC must update its
methodologies and data inputs with sensitivity to shifting energy markets to meaningfully inforrr
the Commission and the public of avoided energy costs.
b. The study's avoided cost of generation capacity analysis assumes marginal capacity
will be lilled by gas facilities that are not planed and inconsistent with the 2021 IRP.
Estimates of avoided costs of generation capacity in the study rely on unsupported and
unplanned substitution of DERs with thennal generation and needlessly complex methodology
that produces volatile results. The VODER study intoduces gas-fired turbines as the modeled
replacement resource for DERs.l2 This is done without explanation, analysis, or context. Gas-
e Crossborder review at 2.
ro VODER Study at 41.tt Id. at36-38.
t2 Id. at 50, Table 4.4.
Ipeno PusLIc Uru.lues CouutsstoN, Case No. IPC-E-22-22
Idaho Conservation League, Initial Intervenor Comment
Page 5
fired turbine generation is not planned forl3, inconsistent with the 2021 IRP, and contrary to the
Company's commitment to carbon neutality by 2045.lnstead, the Company's 2021 IRP
identifies battery storage as its preferred dispatchable marginal resource. An appropriate study
should incorporate either planned, or most likely suitable altematives to DERs that provide
equivalent capacity to DERs.
Additionally, the Crossborder review disputes the usefulness of IPC's preferred
methodology for calculating avoided generation capacity. The effective load carrying capacity
("ELCC") figure used in the VODER study is substantially lower than the ELCC of existing
solar resources and recent projects. The study's ELCC also does not reflect solar development in
Idaho, and is more consistently a higher solar penetration, higher peak energy system. Finally,
the VODER study's annual ELCC figures show significant year-to-year variability in capacity
contribution attributable to the method's complexity and volatility. Crossborder Energy offers
the much simpler peak capacity allocation factor ("PCAF") calculation as an alternative method
to cure these defects.la Crossborder's capacity contribution figure is 27 .|Yo to the VODER
study's 7.6yo.ts The PCAF method is recommended as simpler, more stable, and more
transparent than the ELCC approach.
The Crossborder review substitutes IPC's assumed marginal resource of thermal
generation with battery storage and applies the PCAF method for capacity contribution to arrive
at a cost of avoided generation of $35.00 per MWh.16 Again, different methodologies and
13 The conversion of Bridger Units I & 2 from coal to gas replaces existing capacity and does not add to marginal
dispatchability.
la Crossborder review at 4r5Id.; VODER Study at 51.
t6 Crossborder review at 4. Calculation presented in Table l.
Ioaso Pueltc Uru-rrrcs CouvrssroN, Case No. IPC-E-22-22 Page 6
Idaho Conservation League, Initial lntervenor Comment
assumptions account for the discrepancy between values in the critique and those offered by tPC
in the VODER study.
c. The study minimizes transmissions and distribution deferral by using a bottom up
method where a system wide approach is more reliable.
The VODER study finds very low avoided T&D costs by assuming an average
distributed generation system across all instances, thereby failing to capture the greatest avoided
need for additional T&D resources. The VODER study spreads distributed generation evenly
across its whole system. This flattens peak system loads avoided by DERS across wide service
areas, obscuring needed T&D investments for the most sfessed areas of the system.lT
Additionally, the study fails to consider other distributed energy technologies beyond generation
that reduce long-term system demand.18
Regression models can account for marginal T&D costs and the value of infrastructure
avoided by reducing peak loads. The NERA regression model used by Crossborder fits
incremental T&D investments to historic peak load growth, allowing projection of future costs
and those avoided by peak load reduction.le Regression analysis benefits from reliance on
historic system data; real increases in peak load are matched to real increases in T&D costs.
Using peak load contributions estimated with the previously discussed PCAF analysis, the
Crossborder review calculates IPC's T&D costs deferred by DER development at $49.00 per
MWh.20
17 Crossborder review at 5.
t8 Id.
te Id.
20 Id.
IpeHo PueLrc Urrr,rrms Couulsstou, Case No. IPC-E-22-22
Idaho Conservation League, Initial Intervenor Comment
PageT
d. Avoided line loss estimates fail to account for top marginal increases in load and
rely on a decade old study that does not anticipate projected growth.
The VODER study does not apply a marginal analysis appropriate to DER development
in estimating avoided line losses. Resistance and line loss are exponential functions of load,
making marginal analysis at peak demand critical to accurate modeling. Again, IPC applies
system-wide average losses where behind the meter demand reduction by DERs reduce loads on
localized connections.2l Moreover, IPC average system loads come from a decade-old lineloss
study that fails to account for rapid projected growth across the Company's system.22 Resistive
losses are likely much higher, and behind-the-meter marginal demand reduction can more
accurately model avoided line 1osses.23 Crossborder conservatively estimates the value of
avoided line losses at $9.50 per MWh.
e. The VODER study's estimate of integration costs does not account the resource mix
or battery storage planned for by the Company.
IPC's integration costs for DERs again relies on a dated study that does not reflect
current Company planning. Integration costs for distributed solar resources in the VODER study
comefrom a2020 studycompletedbeforethemostrecent 2021IF.P.24 TheIRP,25 andcurrent
Company requests before the Commission,26 plan for significant growth and installment of
dispatchable battery resources. Dispatchable battery storage reduces system variability and
balancing needs, lowering integration costs of variable resources such as distributed solar. The
2r VODER Study at 59.
22 Id.
23 Crossborder review at 8.
24 VODER Srudy at 63.
25 2021IRP at 4, Table l.l
26 Case No. DC-E-22-13. Application for Public Convenience, at 6.
Ioetro Punuc Uru.ruEs CouurssroN, Case No. IPC-E-22-22
Idaho Conservation League, Initial Intervenor Comment
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Company's plans mostly reflect a use case in its integration study that assesses DER integration
costs of $0.64 per MWh.27 The Crossborder review agrees with this result.
2. The Commission directed IPC to analyze avoided fuel price risks that meaningfully
contribute to the value of distributed energy resources.
While the five components of the ECR account for much of the value solar exports, fuel
hedglng benefits directly impact rates and should be fully considered as a component value of
DERs. The Commission directed IPC to study avoided risks of fuel price volatility with the
"expectation that the ECR be updated regularly to mitigate risks."28 The VODER study fails to
fully assess fuel hedging benefits. The only mention of fuel hedging in the VODER study comes
in trro discussions of pricing methodology.2e PC notes with no elaboration that ELAP and ICE
Mid-C market prices capture some fuel hedging value. The discussion here is cursory does not
explain interactions between fuel pricing and DERs, and is inadequate to address the
Commission's direction or parties' comments to the study framework. The VODER study is
incomplete without substantive discussion of fuel hedging benefits from DER development.
Distributed solar resources have measurable fuel hedging value. This value is realized
when renewable resources offset generation by price-volatile resources, primarily gas and coal,
but also annually variable resources such as hydro generation. Benefits also accrue during market
disruptions or times of grid-wide low generation. While an ECR tied to the price of alternative
fuels captures some of this value, it is important to note that that energy generated by DERs used
behind the meter also reduces reliance on variable price resources.
27 Crossborder review at 8.
28 OrderNo. 35284 at22.
2e voDER study at 38, 39.
loano PusI-rc UttlrrIEs CouutssIoN, CaseNo. IPC-E-22-22
Idaho Conservation League, Initial lntervenor Comment
Page9
The Crossborder review calculates benefits from fuel hedging. The methodology used
estimates the cost of fixing fuel prices at25 years, a time span that matches the expected life of
distributed solar systems.3o This timespan more closely models the benefits of typical DERs than
the l8-month forecast and contract period used by IPC to secure fuel prices. Accounting for the
fraction of benefits already incorporated into an ECR tied to fuel prices, Crossborder offers a fuel
hedging value of $7.70 per MWh.
3. Eliminated carbon emissions affect rates and should be considered in the value of
distributed generation.
Carbon emissions and thefu effect on climate warming have definitive impact on
economic activities and energy rates and must be considered in the value of all energy resources.
The Commission ordered the VODER study to "include an evaluation of all benefits and costs
that are quantifiable, measurable, and avoided costs that affect rates."3l Elsewhere, the
Commission notes that its legislative mandate is to conduct economic analysis to determine rates,
and that it would exceed its authority to monetize many environmental attributes.32 ICL takes
notice of the Commission's mandate and its limitations. Still, the commission observes, "there
are many environmental considerations that are quantifiable and will be included in an ultimate
determination of fair, just and reasonable terms."33 Carbon emissions and the economic impacts
of climate change are such considerations.
The economic costs of carbon emissions are manifest and knowable. The Company
recognizes this, and its commitment to carbon neutrality by 2045 is a critical step towards
30 Crossborder review at ll, see Maine Public Utilities Commission, Maine Distributed Solar Valuation Study
(March 1,2015).
3r Order No. 35284 ar27.
32 Id. at 12.
33 Id.
loauo PusLrc Urrlnns CouurssroN, Case No. IPC-E-22-22
Idaho Conservation League, Initial lntervenor Comment
Page 10
environmental and economic security.34 Still, pricing carbon emissions is difficult and
contentious. Crossborder offers a valuation using the Environmental Protection Agency's
AVERT35 tool for avoided emissions and the 2021 IPR's planning case to arrive at an avoided
cost of carbon of $19.20 MWh. Under any reasonable methodology the cost of avoided carbon is
non-zero. The commission directed IPC to analyze all measurable considerations that effect
rates. If this direction is to be meaningful, the cost of carbon must be included. ICL urges the
Company to revise the VODER study, and offer an assessment of avoided costs of carbon
eilussrons.
4. The VODER Study's assessment of avoided environmental costs is deficient because
costs are known, measurable, and effect rates.
Multiple known and measurable environmental and societal benefits that are reasonably
considered in the public interest determination of fair, just and reasonable rates are not
considered in the VODER study. Specifically, the social cost of carbon emissions, health benefits
of reduced air pollution, land use costs, local economic benefits, reliability and resiliency, and
customer choice are all quantifiable, yet not offered or analyzed. ICL urges the Commission to
include these quantifiable factors in its public interest analysis of what constitutes a fair, just and
reasonable rate.
a. Social cost ofcarbon
The social cost of carbon is the measure of the seriousness of climate change.36 It is
quantified by subtracting the planning and procurement costs of new, clean power generation
34 2021IRP at 27.
35 ENvn.oNtvrrurRr PnorncrloN AcENCv, Avoided Emissions and Generation Tool. Available at
https://www.ep a.gov / averl.
36 Crossborder review at 14, referencing Anthoff, D. and Toll, R.S.J. 2013, The uncertainty about the social cost of
carbon: a decomposition analysis using FUND. Climactic Change 117: 515-530.
IoeHo PueI-rc Uru-trres CouulssloN, Case No. IPC-E-22-22 Page l1
Idaho Conservation League, Initial Interenor Comment
from the costs of carbon pollution imposed on society.3T [PC's 2021 tRP applies a commonly
used, yet outdated, calculation for valuing the social cost of carbon,38 resulting in a $52lton
value.3e A more recent estimate finds the social cost of carbon to be $4l7lton, far higher than the
outdated estimate.ao Even still, Crossborder used IPC's values and calculated a25-year levelized
difference for the societal benefit of reducing carbon emissions of $30.40 per MWh.ar The
VODER study should include the social cost of carbon in its cost and benefit analysis.
b. Human health criteria
At a base level, increased renewable energy leads to fewer carbon emissions which leads
to improved human health. Unfortunately, much of IPC's territory falls into one of several state
and federally designated Priority Areas where air quality is of particular concern.42 However, a
quantifiable health benefit of the increased DERs at issue here is reduced carbon emissions. The
AVERT model discussed above is instructive in quantifying this health benefit. Crossborder used
the AVERT tool to analyze the avoided emissions of SOz, NO* and PM 2.5, primary air
pollutants contributing to human health problems.a3 Its analysis finds a societal benefit of
avoided SOz emissions at $7.40 per MWh, avoided NO* emissions at $2.70 per MWh, and
avoided PM 2.5 emissions at $2.60 per MWh, all on a2l-year levelized basis. These quantifiable
benefits are integral and should be factored into the VODER rate analysis.
37 Id.s Crossborder review at 14, citing the Interagency Working Group on Social Cost of Carbon, Technical Update of
the Social Cost of Carbonfor Regulatory Impact Analysis Under Executive Order 12866 (May 2013, revised July
2015)https://www.epa.eov/sites/default/files/2016-12/documents/sc_co2_tsd_aueust 20l6.pdf.Lastcheckedon
September 21,2022.
3e Id. at14.
a0 Id. citing Ricke et al., "Countq/-level social cost of carbon ," Nature Climate Change (October 201 8). Available at
https://www.nature.com/articles/s41558-018-0282--y.epdf. Last checked September 21,2022.
41 Id. at15.
a2 See Priority Areas at https://www.deq.idaho.eov/air-quality/improvins-air-quality/priority-areas/. Last checked
September 21,2022.
a3 Crossborder review at 16 citing Regulatory Impact Analysis for the Final Clean Power Plan. Available at
https://www3.epa.eov/ttr/ecas/docs/rialutilities_ria_final-clean-power-plan-existins-units_2015-08.pdf. Last
checked on September 21,2022.
Ioeso Punlrc Uulrrrns CouurssroN, Case No. IPC-E-22-22 Page 12
Idaho Conservation League, Initial lntervenor Comment
c. Local economic benefits
Numerous studies have found local economic benefits when solar DERs are installed in
communities. This is because DERs involve costs spent locally on installation and maintenance
labor, permitting and affiliated permitting fees, and marketing to customers.aa ldaho's National
Renewable Energy Laboratory and the Lawrence Berkeley National Laboratory found that up to
22o/o of the money spent by customers and installers in establishing DERs is spent in the local
communities in which the DERs are built.as The VODER study should analyze and value this
local economic benefit.
d. Retiability and resiliency
Societal benefits flow from the reliability and resiliency built into renewable distributed
energy systems. Since they are comprised of hundreds, or thousands, of small, widely distributed
systems, they are unlikely to experience widespread weather induced or other transmission
outages at the same time, making them a reliable source of power for customers while also
alleviating pressure on IPC to meet widespread customer need during outages. This quantifiable
benefit is not valued in the VODER study.
e. Customer choice
Personal autonomy and self-reliance are quintessential Idaho values, and they are relevant
here in the form of customer choice. Distributed energy projects allow customers to actively
invest in and participate in their energy choices, bringing monetary value to their residential and
commercial properties as well as allowing partial self-reliance. Additionally, IPC needs
4 Crossborder review at l7-18.
45 Id..
loeHo Pusr.rc Uru-tups CouursstoN, Case No. IPC-E-22-22
Idaho Conservation League, Initial lntervenor Comment
Page 13
increased usage of DG systems to meet its 100% Clean Energy by 2045 commitment. See further
discussion of this point in Crossborder's review.46
fn sum, human health, personal autonomy, local economies, transmission reliability and
resiliency, and the social cost of carbon are all quantifiable and should be included in the
Commission's ultimate determination of what constitutes fair, just and reasonable terms for the
Company' s on-site generation program.
Conclusion
ICL offers these comments as a starting point to discuss the importance of methodologic
objectivity and analytic perspective. The attached Crossborder review illustrates the impact of
professional judgment and discretion. Although ICL contests the Company's findings in the
VODER study, comments are offered in hopes of arriving at a maximally beneficial result.
Parties represent a variety of panicular and public interests; each considers an appropriate value
of distributed energy resources critical to economic and energy development in the State. ICL
requests the Commission, the Company, and parties take these comments and the attached study
into advisement.
DATED: September 21, 2022 /s/ Marie Callawav Kellner
Marie Callaway Kellner
Attorney for Idaho Conservation League
6 Crossborder review at l9-Zl.
Ioaso Pust-tc UttLrtrrs CouirarssroN, Case No. IPC-E-22-22
ldaho Conservation League, Initial lntervenor Comment
Page 14
CERTIFICATE OF SERVICE
I hereby certify that on this 21st day of September, 2022,I delivered true and correct
copies of the foregoing INITIAL COMMENT and attachments to the following persons via the
method of service noted:
/s/ Marie Callaway Kellner
Marie Callaway Kellner (ISB No. 8470)
Attomey for the Idaho Conservation League
Electronic Mail Onlv (See Order No. 35058)
Idaho Public Utilities Commission
Jan Noriyuki
RileyNewton
j an. noriyuki@puc. idaho. gov
riley.newton@puc. idaho. gov
secretary@puc. idaho. gov
Commission Staff
RileyNewton
Chris Burdin
riley. newton@puc. idaho. gov
chris.burdin@puc. idaho. gov
Idaho Power Company
Lisa Nordstrom
Megan Goicoechea Allen
Timothy E. Tatum
Connie G. Aschenbrenner
Grant Anderson
[e-mail]
[e-mail]
[e-mail]
caschenbrenner@idahopower. com
ganderson@idahopower. com
[e-mail]
Clean Energt Opportunities
Michael Heckler
Courtney White
Kelsey Jae
mike@cleanenergyopprotunites. com
courtney@cl eanenergyopprotunites. com
[e-mail]
IdaHydro
Tom Arkoosh
Amber Dresslar
tom. arkoosh@arkoosh. com
amber. dressler@arkoosh. com
erin. cecil@arkoosh. com
Idaho lrrigation Pumpers Association Inc.
Lance Kaufman
Eric L. Olsen
lance@bardwellconsulting. com
[e-mail]
IDAHo Puslrc UTILITIES CoruursstoN, Case No. IPC-E-22-22
Idaho Conservation League, Initial Comment Certificate of Service
Page I
Industrial Customers of ldaho Power
Peter J. Richardson
Don Reading
peter@richardsonadarns. com
dreading@mindspring. com
City of Boise
Mary Grant
Wil Gehl
mrgrant@cityof boise.org
[e-mail]
boi secityattorney@cityofboise. org
Richard E. Kluckhohn & Wesley A.
Klucl&ohn (Kluckhohns)
Richard E. Kluckhohn
Wesley A. Kluckhohn
[e-mail]
wkluck*[e-mail]
Micron Technologt Inc.
Jim Swier
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
[e-mail]
darueschhoff@hollandhart. com
tnel son@hollandhart. com
aclee@hollandhart. com
Idaho Solar Owners Network
Joshua Hill
solarownersnewtwork@ gmail. com
[e-mail]
ABC power Company, LLC
Ryan Bushland
Ryan. bushland@ abcpow er. co
[e-mail]
IDAHo Pusuc UTrLrrrES CoMMrssroN, Case No. PC-E-22-22
ldaho Conservation League, Initial Comment Certificate of Service
Page2
ATTACHMENT A
I PUC Case No. IPC-E-22-?2
IGL lnitialComments Crossborder Energl
Comprehensive Consultingfor the North Ameriean Energt trndustry
Independent Review
of the Idaho Power Company's
Value of Distributed Energt Resources Study
R. Thomas Beach
Pafrick G. McGuire
September 20,2021
Table of Contents
A. Benefits of Solar Quantified in the Idaho Power VODER Study ...............2
l. Avoided Energy Costs )
2. Avoided Generation Capacrty.... .....................3
3. T&D Deferra1...........
4. Avoided Line Losses
5. IntegrationCosts......
6. Summary..
7. Policy Implications of Crossborder's Analysis.... ..............9
Benefits of Distributed SolarNot Discussed or Quantified in the VODER Study............10
l. Fuel Hedging ............10
C.
2. Avoided Cost of Carbon 8missions................. ................11
Societal Benefits of Disfiibuted Solar Generation .......................13
l. Carbon Social Cost and Methane Leakage.... ..................14
2. Health Benefits of Reducing Criteria Air Pollutants................ ..........15
3. Water t7
...,.,.,,,......7
R
B.
4. Local Economic Benefits........................... 17
I
5.Land Use ........................1 8
6. Reliability and Resiliency ...........19
7. CustomerChoice.....................19
8. Summary of Societal Benefits )
Attachment l: Methane Leales from Natural Gas Infrastructure Serving Gas-fired Power Plants
I
Independent Review of the Idaho Power Company's
Value of Distributed Energt Resources Study
Idaho Power Company (IPC or Idaho Power) completed a Value of Distributed Energt
Resources Study (VODER Study or Study) in June 2022. This study responded to a series of
orders from the Idaho Public Utilities Commission Qdaho PUC), including OrderNo. 35284lrl,
Case No. IPC-E-21-21 which approved a framework for the study. The VODER Study presents
an analysis of the benefits and costs of on-site customer generation - principally rooftop solar
systems that customers install on their own premises - within Idaho Power's service area. The
study comments on several alternatives for valuing the power exported to the IPC grid from such
facilities, and quantifies five of the components of the value of solar distributed energy resources
(DERs):
o Avoided energy costso Avoided generation capacityo T&D deferralo Avoided line losseso Integfation costs
Crossborder Energy has reviewed the VODER Study, and presents this summary critique
of the study. For the reasons set forth below, we conclude that Idaho Power's choice of
assumptions and calculation methods significantly undervalue the five components that the
utility quantified. We present our own calculations of an ECR rate with these five elements, in
Table 3 below. In addition, the VODER Study fails to quanti$ important benefits of distributed
solar that the Commission directed the utility to aralyze in OrderNo.35284 - benefits that are
known and measurable, will impact rates, and will benefit Idaho rate,payers and citizens. These
include the benefits of a long-term physical hedge against volatile natural gas prices and of
avoiding the rate impacts of reducing carbon emissions.
Notwithstanding our differences, Crossborder appreciates Idaho Power's clear and
detailed explanation of the analysis that it conducted for the VODER Study, and for making
available a substantial amount of the data and workpapers for the study. The clarity of the study
is helpful in identiffing and highlighting the important policy and technical issues associated
with the work.
1
Critique of the IPC VODER Study
September 20,2022
Crossborder Energt
A. Benefits of Solar Quantified in the ldaho Power VODER Study
We first summarize our critique of the five components of the value of solar that IPC
quantified in the VODER Study.
1. Avoided Energy Costs
The Commission's Order recognizes that the calculation of avoided energy costs must
produce results that are up to date.r The VODER Study proposes three possible metrics for
avoided energy costs - one is the forecast of electric market prices from the modeling performed
in202l for the IPC 2021 Integrated Resource Plan (20211RP). The other two use historical
electric market prices from 2019-2021. Nl of these metrics are now outdated and inaccurate.
None of them reflect the significant increases over the past year in the market prices for
electricity and natural gas - price increases that have become particularly acute since the war in
Ukraine began at the end of February 2022. T\e price of natural gas n2022 to date (through
August) at the U.S. benchmark Henry Hub market has more than doubled (+130%) compared to
the three-year average price in 2019-2021, and recently has reached $8 to $9 per MMBtu.
We have updated [PC's avoided energy costs to reflect today's new reality of much
higher fossil fuel costs. We calculate that IPC's solar-weighted avoided energy costs using the
most recent year of Energy Imbalance Market (EIM) prices (August l, 2021 to July 3I, 2022) are
$47.30 per MWh, 68% above the$28.24 per MWh EIM price that IPC cites using the three-year
2019-2021 average.2 Today's natural gas forward market indicates that prices will remain at
very high levels for the remainder of 2022 and into 2023before declining to the $5 per MMBtu
range, still well above 2019-2021levels.
Avoided energy costs should reflect more timely and accurate data than the IRP forecast
or the three-year rolling averages used by IPC. For example, they could be based on EIM prices
from the prior 12 months, adjusted based on natural gas forward market prices for the next year.
With respect to the three possible sources for avoided energy costs discussed in the
VODER Study, we recorlmend the use of the western EIM prices. The EIM locational marginal
prices (LMPs) are the prices most specific to the IPC system. Mid-Columbia (Md-C) market
prices could be used, but raise complicated issues about whether dishibuted solar exports are
ee6"rrr::3 and how to adjust Mid-C prices to the IPC system that is located at a significant distance
from the Mid-C market. The IRP price forecast has a significant issue with accuracy and
' See Order, at p. 16: "The Commission recognizes the calculations and documentation for the
value ofexported energy should use current energy price assumptions...."
2 See VODER Study, atp.4l and Figure 4.2.
3 The issue of the "firmness" of distributed solar is a matter of the time scale - on an individual
day, the amount of solar generation from an individual distributed solar systern can be variable depending
on the weather. But the solar output becomes much more predictable as both the time scale and the
number of distributed systerns increases. On an annual basis for an entire solar fleet, the amount of solar
generation can be accurately predicted with a relatively small uncertainty - much less than the uncertainty
in hydro generation, for example.
-2-
Critique of the IPC VODER Study
September 20,2022
Crossborder Energt
timeliness, as shown by how inaccurate the IPC 2021 IRP forecast has proven to be.
2. Avoided Generation Capacity
Avoided generation capacity costs have two components: first, the contribution of
distributed solar to reducing the utility's need for generation capacrty and, second, the marginal
or avoided cost of generation capacity for the utility. We have identified significant issues with
how IPC has valued both of these components.
Capacity contribution. IPC maintains that the capacity contribution of distributed solar
is just 7.60/o of the solar nameplate capacity, based on what the utility claims to be an effective
load carrying capacity (ELCC) analysis of solar exports n2020 and202l.a This low ELCC is
surprising, given that the 2021 IRP shows that the ELCC of IPC's existing solar resources are
over 60Yo, and the new Jackpot solar project that IPC is adding in late 2022 or 2023 has an
ELCC of 34%o.s Yes, utility-scale solar facilities that use tracking arrays will have somewhat
higher ELCCs than fixed rooftop arrays, and the ELCC of solar generally will decline as more
solar is added to a utility's resource mix, but the difference between a34o/o ELCC for new
utility-scale solar and 7.60/o for new rooftop solar is excessive. IPC's proposed 7.6o/oELCC is
similar to the marginal "last-in" solar ELCC of 7 .8o/o for new resources on the CAISO grid in
Califomi46 which has very high solar penetration - over 25,000 MW of solar (both rooftop and
utility-scale) on a grid with a peak demand of 45,000 MW. Idaho is not California - in contrast,
Idaho Power has only 380 MW of solar (both rooftop and utility-scale) on a grrd with a peak
demand of 3,800 MW.7
IPC's ELCC analysis calculates the7.62%o ELCC capacity contribution by looking at the
capacity value of distibuted solar exports as a percentage of the total distributed solar capacrty
on the IPC system n2020 and202l. This approach makes the mistake of ignoring that only
about one-half of the distributed solar capacity is used to produce exports; the other half serves
the customers' loads behind the meter. The amount of real-time exports in2020-2021, as a
percentage of total output, indicates that about 52%o of the solar capacity is used for exports.
Thus, IPC's capacity contributions need to be increased by a factor of I divided by 0.52.
Correcting this error increases the capacity contribution to l4.7Yo using the ELCC method, and
to 19.8o/o under the NREL approach.
We are also concerned with the volatility of the results under the capacity contribution
methods used by IPC. For example, the IPC ELCC method produced acapacity contribution of
4.3o/o rn2020, but 10.9% tnz02l,i.e. 153%o higher in2o2l than202o. Instead of using ELCCs,
we prefer the use of the peak capacity allocation factor (PCAF) method. This is a widely-used
o See VODER Study, at p. 51 and Figore 4.7.
' S"" 2021 IRP, Appendix C,p.99.
6 Energy & Environmental Economics (E3) and Astrape Consulting, Incremental ELCC Studyfor
Mid-Term Reliability Procurement, updated version submitted to the California Public Utilities
Commission on October 22,2021, at Table ESl.
7 See 2021 IRP,pp.44-47.
3
Critique of the tPC VODER Study
September 20,2022
Crossborder Energt
approach to determining the capacity contribution of solar that is much more stable and
transparent than ELCCs. The PCAF method calculates the capacity contribution of solar exports
across all hours that have loads within 10% of the system peak hour. This method weights the
solar output in these high-load hours by how close the system load in that hour is to the annual
peak hour load. The hour with the annual peak load is weighted the most. We have derived
hourly PCAFs for IPC using system load data from 2016-2020. Using this PCAF method, the
capacity contribution of real-time solar exports is 28.6%o n 2020 and 25.3o/o in 2021 , for an
average of 27.0%. We recommend use of the PCAF method as simpler and more stable than the
ELCC approach.
Marginal or avoided cost of generation capacity. The VODER Study assumes,
without explanation, that a gas-fired combustion turbine (CT) is IPC's marginal source of
generation capacity.8 However, the preferred resource plan in the 202l1RP includes no CT
capacity, and the only gas-fired capacity added is the conversion of an existing coal unit to burn
gas. The pure capacity resource that is included in IPC's preferred resource plan is battery
storage. Thus, the use of the costs of new battery storage as the marginal or avoided cost of
generation capacity is more consistent with the 2021 IRP and with IPC's commitment to move to
100% clean resources by 2045. Table I shows our recommended avoided generation capacity
costs for distributed solar, using the battery storage costs included in the 2021 IRP andthe 27%o
capacity contribution discussed above. Our recommendation for IPC's avoided generation
capacity cost is $35.00 per MWh.
Table lz Crossborder Recommendationfor IPC's Avoided Generation Capacity Costs
3. T&D Deferral
The VODER Study reports very low avoided costs for transmission and distribution
(T&D) capacity deferrals on IPC's grid. Our first concern with IPC's approach is that it is a
"bottom up" method which assumes that the relatively small amount of solar exports in202l is,
unrealistically, spread evenly across IPC's entire system, is not assumed to grow in future years,
and will only defer T&D capacity in the near future.e This results in very small reductions to the
peak loads on the IPC T&D system, and just a few short project deferrals.
8 voDER Study, at p. 51, Table 4.5.
e This even 'opeanut-buttering" of distributed solar capacity across the entire system is almost
certainly unrealistic, as we expect that most of the existing distributed solar capacity on the IPC system is
clustered in a few urban and suburban locations in the Treasure Valley.
4
line Component Value Sources / Notes
a Battery storage cost of capacity Sl92lkW-year 2021 IRP, Appendix C,p.47
b Reserve marqin 15.5%2O21IRP
c Avoided cost of seneration capacitv $222lkW-vear ax(1 +b)
d Distributed solar capacity contribution 27.0%PCAF method
e Solar avoided generation capacity cost $60 / kW-year dxe
f Solar output kWh per kW 1.710 kwh / kw PWVATTS output for Borse
s Solar avoided generation capacity cost $3s.00 / Nrwh e/f
Critique of the IPC VODER Study
September 20,2022
Crossborder Energt
The problem with the utility's approach can be seen by considering a single 7 kW
residential solar system. The utility's analysis would conclude that such a system, by itself, will
never avoid any T&D costs, even though it will lower loads on the grid. IPC's analysis shows
that even the existing 65 MW of distributed solar will produce few savings when that capacity is
assumed to be spread thinly across the entire IPC system. But this is a Value of Distributed
Energt Resources study, and DERs include a broad range of demand-side resources, including
energy efficiency, demand response, and on-site storage as well as behind-the-meter (BTM)
solar. Collectively, these resources can have a much larger impact to reduce IPC's need for
T&D upgrades over time - by being a much larger amount of capacity, by concentrating load
reductions in certain locations, and by moving the utility to a much lower long-term demand
trajectory. If considered collectively and over their economic lifetimes, DERs will produce a far
larger T&D deferral value per kW of demand reduction than if each type of DER is analyzed in
isolation for just a few years into the future. [n short, the long-run avoided costs of T&D
capacity should be calculated for any long-run kW reduction in IPC's peak loads, regardless of
which type of DERproduces that saved kW.
To capture the long-run marginal or avoided costs of T&D capacity from a kW reduction
in demand from any type of DER, we use a "top down" approach that U.S. utilities have long
used to calculate marginal T&D capacity costs for ratemaking. This is the National Economic
Research Associates (NERA) regression method, which calculates marginal T&D capacity costs
by analyzing long-term data on how the utility's investments in transmission or distribution
change with changes in peak demand. This "top-down" calculation captures the fact that peak
loads impact T&D additions in many ways. Most directly, T&D ffiastructure must be expanded
as load grows, to serve peak demands. Load growth can also be an indirect factor in other tlpes
of T&D expansions and upgrades. For example, an upgrade may be required for reliability
reasons to address contingencies that arise under highJoad conditions, or to access new
generation resources needed to serve growing peak demands. Even replacement projects are
demand-related in that they are necessary to keep the grid's capacity frsrn dsslining. Although
peak demand may not be the primary driver of all of these projects, it has a significant overall
influence on the need to invest in T&D ffiastructure.
The NERA regression model determines avoided T or D costs by fitting incremental T or
D investment costs to peak load growth. The slope of the resulting regression line provides an
estimate of the marginal cost of T or D investnents associated with changes in peak demand.
The NERA methodology typically uses as many years as possible of historical expenditures on
T&D investnents and historical data on peak tansmission system loads, as reported in FERC
Form 1, and, if available, the forecast of future expenditures and expected load growth.
We have used a NERA regression based on IPC's FERC Form I data on its historical
fansmission expenditures as a function of its peak load growth over a 30-year period from 1996
to 2025. Figure 2 shows the regression fit of cumulative transmission capital additions as a
function of incremental demand growth on the IPC system.
5
Critique of the IPC VODER Study
September 20,2022
Crossborder Energt
Figure 2: Regression of Cumulative IPC Transmission Additions vs. Peak Demand
NERA Regression of IPC's Avoided Transmission Costs
s1,800,000,000
a o
O
a o
ooaa
a o oa
2,000 2,200 2,400 2,600 2,800 3,000 3,200
Peak toad (MW)
s1,600,000,000
s1,400,000,000
s1,200,000,000
s1,000,000,000
s800,000,000
s600,000,000
s400,000,000
s200,000,000
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oco
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o
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t
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oo
oo
o
s-3,400 3,600 3,800 4,000
The regression slope resulting from this analysis is $ 1 ,3 I 5 per kW. We add 6.20/o to thrs
amount to account for the overhead costs of IPC's general plant, convert the total to an
annualized marginal transmission cost using a real economic carrying charge (RECC) of 7.lo/o,to
and include $9.09 per kW-year for transmission O&M costs.ll The resulting avoided cost for
transmission capacity is $ I 07.50 per kW-year. A similar NERA regression for [PC's distribution
investrnents produces an avoided cost for distribution capacity of $160.30 per kW-year.
The final step is to consider the capacity contributions of distributed solar to avoiding
investrnents in marginal T&D capacity. Distributed solar can avoid T&D investments by
reducing peak loads on the IPC grid. For transmission, we used a PCAF analysis of IPC's hourly
system loads over the2016-2020 period (from FERC Form 714) to determine the capacity
contribution of solar PV to reducing peak transmission system loads.l2 The result of this PCAF
analysis is a capacity contribution of 29.4%o of the solar nameplate. For distribution, we
performed a PCAF analysis on IPC distribution substation loads in 2020, resulting in a33.4%
capacity contribution. Table 2 shows our final calculation of IPC's T&D deferral costs, which
l0
ll
t2
Based on IPC's currently-authorized capital structure and cost of capital.
Our estimates of general plant and transmission O&M costs are from IPC's FERC Form I data.
We would prefer to use a PCAF analysis of IPC's distribution substation loads to determine the
capacity contribution of solar to avoiding distribution costs, but IPC has yet to respond to our request for
that detailed substation load data.
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Critique of the tPC VODER Study
September 20,2022
Crossborder Energt
total $49.80 per MWh.
Table 2: Crossborder Recommendationfor IPC's TE D Deferral Costs
4. Avoided Line Losses
The avoided energy and generation capacity costs discussed above are at the generation
level, and need to be increased to reflect the mareinal line losses on both the transmission and
distribution systems that are avoided by customer-sited solar. Solar reduces losses due to its
location behind the customeros meter at the point of end use. As discussed in the last section, the
impact of customer-sited solar, including the impact of the power exported to the local
distribution system, is to reduce loads on the upstream portions of the utility's T&D system.
With lower loads, less power is lost in T&D circuits and other equipment.
It is important to recognize the physical fact that resistive line losses are a function of the
square of loads;I3 as a result, marginal resistive losses are roughly double average losses. This
means that the marginal impact on losses of reducing a kW of load on the T&D system is
significantly greater than the average losses at that moment. In addition, the marginal losses
associated with behind-the-meter solar resources are higher than system average losses because
much of the solar output occurs in the afternoon hours when loads and losses are higher.la
The VODER Study understates IPC's avoided line losses substantially, for several
reasons. First, IPC relies on a line loss study that is a decade old.ls Loads have increased
modestly on the IPC system since 2012, and are expected to grow even more rapidly over the
next 20 years.16 Further, the utility proposes to use system average losses, not marginal losses.
This is surprising, as IPC itself recommended that the VODER Study distinguish marginal
13 Per the formula that the power P dissipated in a circuit equals the square of the current I times the
circuit's resistance R: P : RI2. R is essentially constant, while I varies with the load placed on the
circuit. The marginal losses are obtained by taking the derivative of this formula with respect to I, which
yields the relationship that marginal losses are double average losses.
t4 The line loss impacts of DERs are explained in detail in the Regulatory Assistance Project's
paper, Valuing the Contribution of Energy EfJiciency to Avoided Marginal Line Losses and Reserve
Requiremenls (August 20I I). See hllU//www.raponlin
eeandlinelosses-20 1 I -08- I 7.pdf.
15 I/)DER Study, at pp. 58-61.
16 See 2021 IRP,at Figure 8-1.
-7 -
line Parameter Transmission Distribution Notes
a Avoided Capacity Cost 107.50 / kW-year 160.30 / kW-year NERA regressions
b Solar Capacity Contribution 29.4o/o 33.4o/o PCAF analysis
c Solar Output 1,710 kwh / kw 1,710 kwh / kw PVIilATTs - Boise
d Solar Avoided T&D Costs $18.50 / IvIWh $31.30 / MWh axb/c
Critique of the IPC VODER Study
September 20,2022
Crossborder Energt
losses,lT and the utility recognizes that losses increase with system loads.l8
IPC's system average resistive losses from2012, as shown in Table 4.9 of the Study, are
about 5.8%. In the absence of an up-to-date study of marginal line losses, it is reasonable to
double IPC's system average resistive line losses from20l2,to ll.6%o, to capture the higher
marginal losses avoided by new DER resources. The resulting loss factors are still
conservatively low, in that they may not reflect the higher marginal losses experienced during
the peak demand hours in summer afternoons when solar output is high. We have calculated the
total avoided line losses by applying an ll.60/o loss factor to both the avoided energy and
generation capacity costs discussed above. Avoided losses total $9.50 per MWh.
5. Integration Costs
lntegration costs are the costs of the additional ancillary services needed to accommodate
the increased variability that wind and solar output add to the utility system. The VODER Study
includes a solar integration cost of $2.93 per MWh taken from the base result case of a 2020
wind and solar integration cost study that the E3 consultants performed for IPC (E3 Study). The
base case in the E3 Study included only existing resources, and the study was completed before
the 2021lRP. The study did include a variety of scenarios with different mixes of future
resources. The scenario whose resource mix most closely resembles the subsequent 2021 IRP's
preferred plan is Case 9 - the High Solar with 200 MW Storage case,re This scenario shows
much lower integration costs of $0.64 per MWh.20 Battery storage provides a signiflsanl,
flexible, and fast-responding source of ancillary services, reducing integration costs significantly.
Given that IPC is now planning to add significant storage resources, this lower integration cost of
$0.64 per NIWh should be used instead of the $2.93 per MWh used in the VODER Study.
t7 See Order, atp.20.
18 VODER Study, at p. 58: "Line losses are proportionate to the amount of enerry flow. In other
words, the higher the energy flow, the higher the line losses."
re T"lrc 20211ftP preferred plan adds 420 MW of solar, 700 MW of wind, and 225 MW of storage
from2023-2025. See Table 1.1.
20 E3 Study, at Table ESl.
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Critique of the IPC VODER Study
September 20,2022
Crossborder Energt
6. Summary
Table 3 summarizes our recommended adjustments to IPC's proposed ECR.
Table 3: ECR Recommendations ($ per Mll/h)
7. Policy Implications of Crossborder's Analysis
Our recommended flat ECR exceeds IPC's current volumetric rates for residential and
small commercial customers.2l Today, net metering customers are compensated at the
retail volumetric rate for their exports. Our results indicate that net metering at the retail
rate remains cost-effective today on Idaho Power's system, and there is no cost shift to
other customers from the current net metering tariffs.
o
If the Commission were to move to a net billing construct, compensation to solar
customers should be increased as indicated by our recommended ECR rate.
Other states with far higher penetrations of distributed solar, such as Aizona, California,
and Hawaii, have moved to the use of time-of-use (TOU) rates for net metering
customers as a first step prior to or at the same time as adopting net billing. TOU rates
price electricity more accurately across the seasons and the hours of the day, and thus can
help to avoid the development of any adverse cost shift as solar penetration increases.
The use of TOU rates for net metering customers is also important given that DER
technology is not standing still, and IPC should expect solar systems paired with on-site
storage to become the industry standard in the coming years. This trend is driven in
significant part by customers' desire for an assured backup supply of clean energy to
improve their energy resiliency in the face of climate disruptions and more frequent grid
outages. IPC's analytic framework in the VODER Study is limited because it is based
entirely on export profiles from the existing fleet of solar-only customers. The profiles of
the coming solar-plus-storage installations will be substantially different - and more
valuable to the IPC system - than those that IPC has modeled in the VODER Study.
This includes the rates for the upper usage tiers of IPC's residential and small commercial rates.
o
a
Component IPC VODER Study Crossborder
Avoided Energy 28.24 47.30
Avoided Generation Capacity 10.60 35.00
T&D Deferral 0.26 49.80
Avoided Line Losses t.64 9.s0
Integration Costs (2.e3)(0.64)
Total 37.81 r40.96
2t
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Critique of the IPC VODER Study
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Crossborder Energt
B. Benefits of Distributed Solar Not Discussed or Quantified in the VODER Study
Our review of the Commission's Order and the VODER Study indicates that there are
several benefits of DERs that the Order directed the utility to analyze, but that the VODER Study
failed to address. We quantiff these benefits below. As we explain, these benefits are known,
measurable, and have a direct impact on IPC's rates and ratepayers.
1. Fuel Hedging
The Order finds, at page 22, that "[i]t is reasonable to evaluate fuel price risks. It is the
Commission's expectation that the ECR be updated regularly to mitigate risks." Renewable
generation, including distributed solar, permanently reduces a utility's use of natural gas, and
thus decreases the exposure of ratepayers to the volatility in natural gas prices. That volatility
has been exemplified by the sharp increases in natural gas prices over the past year. Similar
spikes have occurred regularly over the last several decades, as shown in the plot of the
benchmark Henry Hub gas prices since January 2000, in Figure 3 below.22
Figure 3
Henry Hub Natural Gas Market Prices
(Ianuary 2000 to August 2022)
Renewable generation also hedges against market dislocations or generation scarcity such
as was experienced throughout the West during the California energy crisis of 2000-2001 or as
has occurred periodically during drought conditions in the U.S. that reduce hydroelectric output
and curtail generation due to the lack of water for cooling.23
Source for Figure 3: Energy Inforrnation Administration data.
For example , rn 2014, the rapidly increasing output of solar projects in Califomia made up for
- 10-
16.00
14.00
12.00
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8.00
6.00
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ttEgEsttsttEEtg99rrr9=:pp9rt:2FFFEAI}I A}IAiAAi'A}AAiAAIAATAATAAIAAl&rrI!rIrrirE:!Ei!rirairr:srlrrlrti!
22
23
Critique of the tPC VODER Study
September 20,2022
Crossborder Energt
We note that this benefit will be reduced to the extent that the ECR is linked directly to
electric market prices that are driven by natural gas prices, In that case, the ECR payments
recovered from ratepayers will be impacted by volatile fossil fuel prices. However, the 50% of
distributed solar output that is not exported will reduce permanently the utility's use of natural
gas, providing a long-term physical hedge. It is critical to note that this benefit will accrue for
the25- or 30-year life of the distributed solar system, and thus is far more valuable than the
limited l8-month benefit provided by IPC's existing fuel hedging activities.
To calculate this benefit, we follow the methodology used in the Maine Distributed Solar
Valuation Study (Maine Study), a2015 study commissioned by the Maine Public Utilities
Commissionand authored by Clean Power Research.2a This approach calculates the financial
cost of fixing the cost of natural gas for 25 years, thus eliminating all fuel price risk. It
recognizes that one could contract for future natural gas supplies today, and then set aside in
risk-free invesfrnents the money needed to buy that gas in the future. This would eliminate the
uncertainty in future gas costs. The additional cost of this approach" compared to purchasing gas
on an "as you go" basis (and using the money saved for alternative invesfinents), is the benefit
that distributed solar provides for IPC ratepayers by reducing the uncertainty and volatility in
IPC's costs for natural gas.
We have performed this calculation for IPC, using an up-to-date natural gas forecast that
combines near-term forward market prices with, in the out years, the Energy Information
Administration's 2022 Annual Energt Outlook forecast for Henry Hub prices. We also have
used U.S. Treasuries (at current yields) as the risk-free investnents and a marginal heat rate of
7,500 Btu per kWh. The result is a value of $23.40 per MWh as the 25-year levelized benefit of
reducing fuel price uncertainty. We then reduce this value by 50% given that the ECR for the
portion of solar output that is exported may be linked to near-term electric and gas market prices,
and thus may not provide a hedging benefit. The resulting fuel hedge benefit is $11.70 per
MWh.
2. Avoided Costs of Carbon Emissions
With respect to the evaluation of the quantifiable environmental benefits of DERs, the
Order states, atpage?T,that "[t]he Commission finds it reasonable that the Study include an
evaluation of all benefits and costs that are quantifiable, measurable, and avoided costs that
affect rates."
83% of the reduction in hydroelecffic output due to the multi-year drought in that state. Based on Energy
Information Administration data for 2014, as reported in Stephen Lacey, As California Loses Hydro
Resources to Drought, Large-Scale Solar Fills in the Gap: New solar generation made upforfour-Jifths
of California's lost hydro production in 2014 (Greentech Media, March 31,2015). Available at
http://www.greentechmedia.com/articles/read/solar-becomes-the-second-biggest-renewable-enerey-
provider-in-cali forn ia.
24 See Maine Public Utilities Commission, Maine Distributed Solar Valuation Study (March 1,
2015). Availableathttps://www.maine.eov/tools/whatsnew/attach.php?id:639056&an:1.
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Critique of the IPC VODER Study
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Like other renewables, distributed solar will avoid carbon emissions from traditional
fossil-fueled power plants, and help to mitigate the impacts of climate change. tdaho Power has
committed to eliminating its carbon emissions by 2045,2s and recognizes that carbon emissions
must be reduced in order to mitigate the adverse impacts of climate change.26 The 2021 IRP also
makes clear that the impacts of climate change in Idaho are likely to impose significant risks,
with associated cost impacts, on the utility and its Idaho ratepayers for both mitigation and
adaptation.2T IPC also has assumed carbon emission costs in its IRP planning, which results in
actionable resource plans that have significant cost consequences for Idaho ratepayers.2s We
conclude that avoided carbon emission costs are quantifiable and measurable avoided costs that
will aflect IPC's rates
Figure 4 shows the range of carbon emission costs (in $ per short ton) from the 2021
IW.2e As noted above, IPC's assumed carbon costs in the Planning Case are taken from
forecasts of carbon cap & trade costs in California. The figure includes, as the high case, the
U.S. Environmental Protection Agency's (EPA) social cost of carbon (SCC), which is a measure
of carbon costs based on the societal damages from unmitigated climate change. The SCC can
be used to value the societal benefits from reduced carbon emissions.
Figure 4z Carbon Cost Forecastsfrom 2021 IRP
l0ll ll, Crto. rrke ro(dt
0a
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25 2o2l IRP, atp.27.
26 Id.: "Limiting the impact of climate change requires reducing GHG emissions, primarily CO2."
2'7 Id., atpp.27-34.
28 Id., atp.34: "similarly, federal climate legislation has not been passed by Congress. However,
the company believes that climate- and emissions-related policies will emerge in future years. To account
for this expected future, the company models multiple scenarios with varying prices on carbon."
2e Id., atFigxe 9.3.
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Our analysis of avoided carbon costs uses the Environmental Protection Agency's
("EPA") "AVoided Emissions and geneRation Tool" (AVERT) to calculate the avoided carbon
emissions due to distributed solar installations in Idaho. AVERT calculates hourly avoided
emissions based on a given hourly profile for energy efficiency savings or renewable energy
production. Our model uses a PV profile for I MW of distributed solar sited in Boise, and the
Northwest AVERT regional data file, to calculate the avoided carbon emissions in Idaho. The
avoided carbon emissions are 1.53 lbs per kWh of solar output.
Based on the carbon planning costs in Figure 4 and the modeled avoided carbon
emissions of I .53 lbs per kWh, and assuming a 7 .l2o/o discount rate and 0.5% annual solar output
degradation, we have calculated Zl-year levelized avoided costs for carbon emissions. This
calculation results in avoided carbon emission costs of $30.30 per MWh of solar output.
Table 4 summarizes these additional rate-related benefits, combined with the five ECR
components from Table 3.
Table 4z Total Recommended Rate-related Value of Solar DERs ($ per MWh)
Component Recommended Value
Five Components from Table 3 141.00
Fuel Hedeing Benefit r1.70
Avoided Carbon Emission Costs 30.30
Total 183.00
C. Societal Benefits of Distributed Solar Generation
Renewable distributed generation (DG) has benefits to society that do not directly impact
utility rates, but impact IPC ratepayers as citizens of Idaho. These benefits are well-known, and,
in many cases, are measurable and quantifiable. The Order did not direct IPC to study these
benefits, and such benefits may not be appropriate for inclusion in the ECR. However, the Order
recognizes that, even if the Commission is not able to monetize these benefits for inclusion in the
ECR, they can be part of the overall public interest determination that the Commission will make
of a just and reasonable net metering or net billing program for IPC:
... This Commission was granted authority by the Idaho legislature to conduct
economic analyses to determine rates that are fair, just and reasonable. We have
not been granted the legislative or executive authority to monetize many of the
environmental attributes addressed by Parties and customers. That said, there are
environmental considerations that are quantifiable and will be included in an
ultimate determination of fair, just and reasonable terms for the Company's on-
site generation program.3o
30 Order, at p. 12.
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When renewable generation takes the place of conventional fossil fuel generation, all
members of society benefit from reductions in air pollutants that harm human health and
exacerbate climate change. Demands on existing water supplies are reduced, avoiding the
potential need to acquire new sources of supply. Distributed generation uses already-built sites,
preserving land for other uses or as natural habitat. Distributed generation makes the power
system more reliable and resilient, and stimulates the local economy. Many of these benefits can
be quantified, as discussed below. We use a lower, societal discount rate of 5Yo (3o/o real) in
calculating these benefits, rather than the 7.12% IPC discount rate used for the direct benefits.
1. Carbon Social Cost and Methane Leakage
The social cost of carbon (SCC) is "a measure of the seriousness of climate change."3l It
is a way of quantiffing the value of actions to reduce greenhouse gas emissions, by estimating
the potential damages if carbon emissions are not reduced. The carbon costs which we have
included in the direct benefits of solar DG above are limited to the anticipated costs to plan for
and procure enough new, clean generation to meet IPC's goal of l00o/o clean energy by 2045.
These planning and procurement costs are assumed to be lower than the tue costs that carbon
pollution imposes on society, which are the damages estimated by the SCC. As a result, the
additional costs in the SCC, above the planning costs of mitigating carbon emissions, represent
the societal benefits of avoided carbon emissions.
An early source for estimates of the social cost of carbon was the federal government's
Interagency Working Group on the Social Cost of Carbon.32 These values were vetted by
numerous government agencies, research instifutes, and other stakeholders, and are presented in
Figure 9.3 of the 2021 IRP. The cost values were derived by combining results from the three
most prominent integrated assessment models, each run under five different reference
scenarios.33 However, the Interagency working group forecast is more than 10 years old, and is
in the process of being updated. A recent academic estimate of the SCC for the U.S. is the
median estimate of $417 per metric tonne from a review of the range of SCC values published in
October 2018 nNature Climate Change.3a This more recent SCC is far higher than the
Interagency SCC values. IPC's 2021 IRP uses an SCC forecast that starts at $52 per ton, as
shown in Figure 9.3. This appears to be an effort to escalate the older Interagency SCC values to
today. We have used the IPC SCC values recognizing that they are likely to be a conservatively
low value.
3r Anthoff, D. and Toll, R.S.J. 2013. The uncertainty about the social cost of carbon: a decomposition
analysis using FUND. Climactic Change I I 7: 5 I 5-530.
32 Interagency Working Group on Social Cost of Greenhouse Gases, Technical Update of the Social Cost of
Carbonfor Regulatory Impact Analysis Under Executive Order 12866 (May 2013, Revised August 2016).
Available at: https://www.epa.eov/sites/default/files/2016-12/documents/sc co2 tsd aueusl 20l6.pdf.
33 Id. The three models are the Dynamic Integrated Climate-Economy (DICE) model, the Climate Framework
for Uncertainty, Negotiation and Distribution (FLJND) model, and the Policy Analysis of the Greenhouse Effect
(PAGE) model.
34 See Ricke et al., "Countrylevel social cost of carbon ," Nature Climate Change (October 2018).
Available at: https://www.nature.com/articles/s4 I 558-01 8-0282-y.epdf.
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We calculate the societal benefits of reducing carbon emissions in the years 2023 - 2047
as (1) the SCC values used in the 202lIRP less (2) the planning case for carbon emission costs
used in our direct benefits, discussed above. The 25-year levelized difference is $30.40 per
MWh.
Reduced methane leakage. In addition, we also determine the total greenhouse gas
emissions that will result from methane leakage in the natural gas infrastructure that serves
marginal gas-fired power plants. We attach to this report as Attachment I a white paper
summarizing recent studies on the additional greenhouse gas emissions associated with methane
leaked in providing the fuel to gas-flrred power plants. This issue has received significant
attention as a result of the major methane leak in 2015 from the Aliso Canyon gas storage field in
southern California and new technologies for the remote sensing of methane leakage. The
bottom line is that the COz emission factors of gas-fired power plants should be increased by
more than 60Yo to account for these directly-related methane emissions from the production and
pipeline infrasffucture that serves gas-fired electric generation. This additional societal benefit
amounts to $11.60 per MWh.
2. Health Benefits of Reducing Criteria Air Pollutants
Reductions in criteria pollutant emissions improve human health. Exposure to particulate
matter (PM) causes asthma and other respiratory illnesses, cancer, and premature death.35
Nitrous oxides (NOx) react with volatile organic compounds in the atmosphere to form ozone,
which causes similar health problems.36
We use AVERT to calculate the avoided emissions of SOz, NO*, and fine particulate
matter (PMz.s), assuming I MW of distributed solar development. The avoided emissions of
these criteria pollutants are shown in Table 5.
Table 5: Avoided Emissions of Criteria Pollutants
Pollutant Avoided Emissions
lbs/IVIWh
SOz 0.71
NOx l.l I
PMz.s 0.079
The value of these avoided emissions is calculated as follows:
l. Determine the amount of avoided emissions using AVERT as described above.
3s EPA, Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants
and Emission Standards for Modified and Reconstructed Power Plants (June 2014), p.4- I 7 C'CPP Technical
Analysis"). Available at httus://wu'w.epa.gor/sites/default/files/2014-06/documents/20140602ria-clean-power-
plan.pdf.
36 lbid.
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2. Calculate the social cost of the avoided ernissions and subtract the compliance cost or
emissions market value of those emissions.
For quantiffing the health benefits, we recommend using the health co-benefits from reductions
in criteria pollutants that EPA developed in conjunction with the Clean Power Plan. These
benefit estimates were developed in 2014 as part of the technical analysis for the proposed rule.
SOz. The total social cost of SOz emissions is taken from the EPA's Regulatory Impact
Analysis for the Final Clean Power Plan (CPP Impact Analysis).31 The EPA calculated social
cost values for 2020,2025, and 2030. This analysis uses the values given for these three years
assuming a 3% discount rate. Values for intermediate years are interpolated between the five-
year values. The market value of SOz is taken from the EPA's 2016 SOz allowance auctions.
However, the final clearing price of the latest spot auction was just $0.06 per ton.38 This is low
enough compared to the social cost that it is negligible for our calculations. The societal benefit
of avoided SOz emissions is $7.40 per MWh.
NOx. Heath damages from exposure to nitrous oxides come from the compound's role in
creating secondary pollutants: nitrous oxides react with volatile organic compounds to form
ozone, and are also precursors to the formation of particulate matter.3e The social cost ofNOx is
taken from the EPA's CPP Impact Analysis.a0 We use a2017 NO' market price of $750 per ton
for compliance with the Cross State Pollution Rule as the compliance cost forNOx.al The
benefit of avoiding NOx emissions is $2.70 per MVyh.
Fine Particulates 6fMz.s). We use the emissions factor and damage costs for PI\{2.s,
because PIUz.s are the small particulates with the most adverse impacts on health. The EPA
health co-benefit figures distinguish between types of PM, and calculate two separate benefit-
per-ton estimates for PM: for PM emitted as elemental and organic carbon, and for PM emitted
as crustal particulate matter.42 The EPA estimates that approximately 70% of pimary PIMz.s
emitted in Wyoming and Nevada (where the coal plants serving IPC are located) is crustal
material, with the bulk of the remainder being elemental or organic carbon.a3 The emissions
factor of 0.0077 lbs per MMBtu for total primary PI\{z.s does not differentiate among particle
types.e As a result, we weigh the mid-point of each of the trvo benefit-per-ton estimates
37 Regulatory Impact Analysis for the Final Clean Power Plan. Found at:
https://www.epa.eov/sites/production/files/2015-08/documents/cpp-final-rule-ria.pdf.
38 EPA 2016 SO2 Allowance Auction. Found at: https://www.epa.gov/airmarkets/2016-so2-allowance-
auction.
3e CPP Technical Analysis, p.4-14.
4 CPP Impact Analysis, atTable 4-7.
4t See the EPA Cross State Air Pollution Rule. Found at: https://www.epa.sov/csapr. NOx emission
allowance prices can be found at http://www.evomarkets.com/content/news/reports_23_report_file.pdf.
42 CPP Technical Analysis, p.4-26,Table 4-7.
43 lbid.,p.4A-8, Figure 4A-5.
44 AP 4z,Table 1.4-2, Footnote (c).
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according to EPA's assumptions. The health benefits of reducing PMz.s emissions are $2.60 per
MWh ona25-year levelized basis.
3. Water
Thermal generation consumes water, principally for cooling. Reducing water use in the
electric sector through the use of renewable generation lowers the vulnerability of the electricity
supply to the availability of water, and reduces the possibility that new water supplies will have
to be developed to meet growing demand. However, water consumption by efficient gas-fired
generation is relatively low, and the cost of incremental water supplies varies widely depending
on the local abundance of water resotrces. As a result, the value of avoided water use is
relatively modest. We have used $1.20 per MWh for the value of avoided water use, based on
several sources.4s
4. Local Economic Benefits
The development of solar DG will benefit the economy of the community in which it is
installed. Although solar DG has higher costs per kW than utility-scale solar generation, a
portion of the higher costs - principally for installation labor, permitting, permit fees, and
customer acquisition (marketing) - are spent in the local economy, and thus provide a local
economic benefit in close proximity to where the DG is located. These local costs are an
appreciable portion of the "soft" costs of DG. Central station power plants have significantly
lower soft costs, per kW installed, and often are not located in the local area where the power is
consumed.
There have been a number of studies of the soft costs of solar DG, as the industry has
focused on reducing these costs, which are significantly higher in the U.S. than in other major
international markets for solar PV. The following Table 6 presents data on the soft costs for
residential PV systems that are likely to be spent in the local area where the DG customer
resides, from detailed surveys of solar installers that were conducted by two national labs (LBNL
andNREL) in20l3.
45 This figure is based on the American Wind Energy Association's estimate that, in 2016, operating wind
projects produced 226 million MWh and avoided the consumption of 87 billion gallons of water, with a cost of new
water resources of about $ I ,000 per acre-foot. This is similar to the mid-point of cost estimates for the cost of water
savings at gas-fired power plants by implementing dry cooling technologies. See Maulbetsch, J.S.; DiFilippo, M.N.
Cost and Value of Water Use at Combined-Cycle Power Planrs. CEC-500-2006-034. Sacramento: Califomia Energy
Commission, PIER Energy-Related Environmental Research, 2006, available at
http ://www.enerev.ca. eov/2006publicati onsiCEC-500-2006-034/.
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Table 6z Residential Local Costs
Based on these studies, we assume that22%o of residential solar PV costs are spent in the
local economy where the systems are located. These economic benefits occur in the year when
the solar capacity is initially built, which for the purpose of this study is 2023. We have
converted these benefits into a $ per kWh benefit over the expected DG lifetime that has the
same net present value in 2023 dollars. We also use more clurent DG capital costs than the
system costs used in the LBNL and NREL studies. The result is a societal benefit of $30.20 per
MWh of DG output for residential systems.
5. Land Use
Distributed generation makes use of the built environment in the load center - typically
roofs and parking Iots - without disturbing the existing use for the property. In contrast, central
station fossil or renewable plants require large single parcels of land, and tend to be more
remotely located where the land has agricultural or habitat uses. Unless the site is already being
used for power generation, the land must be removed from its prior use when it becomes a solar
farm or a fossil power plant. Although fossil natural gas plants have small footprints per MWh
produced, one must also consider that upstream natural gas wells, processing plants, and
pipelines have substantial land use impacts in the basins where gas is produced. Central-station
solar photovoltaic plants with fixed anays or single-axis tracking typically require 7.5 to 9.0
acres per MW-AC, or 3.3 to 4.4 acres per GWh per year. The lost value of the land can vary
over a wide range, depending on the alternative use to which it could be put. As an example of
the magnitude of land use impacts, we calculate that, based on the 2022U.5. Department of
Agricultural rental value for irrigated croplands in Idaho ($262 per acre),a8 and the alternative of
a utility-scale solar plant (4 acres per GWh), the land use value avoided by DG is about $1.10
per MWh. This value will be lower if the land has an alternative use of lower value than
4 J. Seel, G. Barbose, and R. Wiser, Why Are Residential PY Prices So Much Lower in Germany than in the
U.S.: A Scoping Analysis (Lawrenece Berkeley National Lab, February 2013), at pp.26 and37.
47 B. Friedman et al., Benchmarking Non-Hardware Balance-of-System (Soft) Costs for LI.S. Photovoltaic
Systems, Using a Bottom-Up Approach and Installer Survey Second Edition (National Renewable Energy Lab,
October 1 3, 2013), at Table 2.
48 See USDA, National Agricultural Statistics Service, Survey of 2017 Cash Rents, available at
https://ctuickstats.nass.usda.gov/results/58B27A06-F574-3 l5B-A854-9BF568F17652#7878272B-A9F3-3BC2-
960D-5F03B7DF4826.
LBNL -J. Seet et al.a6 NREL-8. Friedman e/
al.frLocal Costs
$/watt $/watt oo/"
Total System Cost 6.19 t00%5.22 100o/o
Local Soft Costs
Customer acquisition 0.s8 0.48 9o/o9%
lnstallation labor 0.59 t0%0.55 Ir%
Permittine & interconnection 0.15 2%0.10 2%
Permit fees 0.09 t%0.09 2o/o
Total local soft costs t.4t 220 1.22 23Vo
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irrigated land for farming.
6. Reliability and Resiliency
Renewable distributed generation resources are installed as thousands of small, widely
distributed systems and thus are highly unlikely to experience unexpected, forced outages at the
same time. Furthermore, the impact of any individual outage at a DG unit will be far less
consequential than an outage at a major cental station power plant. [n addition, the DG
customer, not the ratepayers, will pay for the repairs.
Most electric system intemrptions do not result from high demand on the system, but
from weather-related transmission and distribution system outages. In these more frequent
events, renewable DG paired with on-site storage can provide customers with an assured back-up
supply of electricity for critical applications should the grid suffer an outage of any kind. This
benefit of enhanced reliability and resiliency has broad societal benefits as a result of the
increased ability to maintain government, institutional, and economic functions related to safety
and human welfare during grid outages. These benefits could be considered to be ratepayer
benefits given that customers need to prepare and pay for their energy needs both with and
without the availability of grid power.
Both DG and storage are essential in order to provide the reliability enhancements that
are needed to eliminate or substantially reduce weather-related intemrptions in electric service.
The DG unit ensures that the storage is fulI or can be re-filled promptly in the absence of grid
power, and the storage provides the alternative source of power when the grid goes down. DG
also can supply some or all of the on-site generation necessary to develop a micro-grid that can
operate independently of the broader electric system. Solar DG is a foundational element
necessary to realize this benefit - in much the same way that smart meters are necessary
infrastructure to realize the benefits of time-of-use rates, dynamic pricing, and demand response
programs that will be developed in the future - and thus the reliability and resiliency benefits of
wider solar DG deployment should be recoenized as a broad societal benefit.
7. Customer Choice
There are important public policy reasons to ensure that the customers who invest in DG
are treated equitably in assessments of the merits of net metering and renewable DG, so that
consumers continue to have the freedom to exercise a competitive choice, to become more
engaged and self-reliant in providing for their energy needs, and to encotrage others to invest
private capital in ldaho's energy infrastructure.
There are many dimensions to the customer choice benefits of DG technologies:
New Capital. Customer-owned or customer-sited generation brings new sources
of capital for clean energy infrastructure. Given the magnitude and urgency of the
task of moving to clean sources of energy, expanding the pool of capital devoted
to this task is essential.
o
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New Competition. Rooftop solar provides a competitive altemative to the
utility's delivered retail power. This competition can spur the utility to cut costs,
to innovate in its product offerings, and to offer more accurate, cost- and time-
based rates. With the widespread availability of rooftop solar, energy efficient
appliances, and load management technologies, plus - in the near future -
customer-sited storage, this competition will only intensi&. In the now-
foreseeable future, the combination of solar, storage, and load management
technologies may offer an on-site electric supply whose quality and reliability is
comparable to utility service.
High-tech Synergies. Rooftop solar appeals to those who embrace the latest in
technology. Solar has been described as the "gateway drug" to a host of other
energy-saving and clean energy technologies. Studies have shown that solar
customers adopt more energy efficiency measures than other utility customers,
which is logical given that it makes the most economic sense to add solar only
after making other lower-cost energy efficiency improvements to your premises.ae
Further, with net metering, customers retain the same incentives to save energy
that they had before installing solar. These synergies will only grow as the need
to make deep cuts in carbon pollution drives the increasing electrification of other
sectors of the economy, such as buildings and transportation.
a
a
Customer Engagement. Customers who have gone through the process to make
the long-term investnent to install solar leam much about their energy use, about
utility rate structures, and about producing their own energy. Given their long-
term investment, they will remain engaged going forward. There is a long-term
benefit to the utility and to society from a more informed and engaged customer
base, but only if these customers remain connected to the grid. As we saw in
Nevada lm2015-2016, when the Nevada commission unexpectedly slashed the
compensation for existing net-metered solar customers, this positive customer
engagement can tum to customer "enragement" if the utility and regulators do not
accord the same respect and equitable treatment to customers' long-term
investnents in clean energy ffiastnrcture that is provided to the utility's
investments and contracts. Emerging storage technologies may allow customers
in the future to "cut the cord" with their electric utility in the same way that
consumers have moved away from the use of older ffiastructure for landline
telephones and cable TV. Given the important long-term benefits that renewable
DG can provide to the grid if customer-generators remain connected and engaged,
4e See the 2009 Impact Evaluation Final Report on the California Solar Initiative,preparedby Itron and
KEMA and submitted in June 2010 to Southem Califomia Edison and the Energy Division of the Califomia Public
Utilities Commission. See pages ES-22 to ES-32 and Chapter 10. Also available at the following link:
http://www.cpuc.ca.eov/workarea/downloadasset.aspx?id:7677. Also see Center for Sustainable Energy, Energt
Eficiency Motivations and Actions of Califurnia Solar Homeowners (August 2014), at p. 6, finding that more than
87% of solar customers responding to a survey had installed or upgraded one or more energy efficiency technologies
in their homes. Available at https://enereycenter.org/sites/default/files/docs/nav/policy/research-and-
reports/Enerey%20Efficiencv%20Motivations%20and%20Actions%2Oofllo20Califomia%20Solaro/o20Homeowners.
pdf.
a
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it is critical for regulators and utilities to avoid alienating their most engaged
customers.
Self-reliance. The idea of becoming independent and self-reliant in the
production of an essential commodity such as electricity, on your own property
using your own capital, has deep appeal to Americans, with roots in the
Jeffersonian ideal of the citizen (solar) farmer.
o
These benefits of customer choice are difficult to express in dollar terms; however, all are
important reasons for ensuring that Idaho's energy policies encourage new clean energy
infrastructure, including a robust market for rooftop solar and other DERs.
8. Summary of Societal Benefits
We have quantified many of the societal benefits discussed above, and they have
significant value. Table 7 below summarizes the societal benefits of solar DG. The societal
benefits total8.7 cents per kWh. Given their magnitude, these benefits should not be ignored
by policymakers, as ignoring them implicitly values them at zero.
Table 7: Societal Benefits of Distributed Solar in ldaho
Benefit Value
($ perMwh)Method Used
Carbon: avoid societal
damages from climate change 30.40 Use the difference between IPC's 202 I nP SCC
estimate and the assumed planning carbon costs.
Carbon: reduce methane leaks
from natural gas infrastructure 11.60 Assumes 2%oleakage, per 2015 National
Academy of Sciences report
Reduce SOz emissions 7.40 EPA AVERT model for avoided SO2 emissions.
EPA estimates of health benefits.
Reduce NO* emissions 2.70 EPA AVERT model for avoided NOx emissions.
EPA estimates of health benefits.
Reduce PI\42.s emissions 2.60 EPA Clean Power Plan technical appendices and
EPA AP 42 for emissions factors.
Avoid consumptive water use 1.20 Several estimates of avoided water use from
renewable generation.
Local economic benefit 30.20 22Yo of residential system cost is incremental
expenses in the local economy.
Land use l.10,
but varies
Highly variable based on altemative uses of land
at which large power plants are sited.
Reliability Significant and
positive
Significant reliability and resiliency benefits from
the pairing of solar DG and on-site storage.
Customer choice Significant and
positive
New capital for clean energy infrastructure, new
competition, greater customer engagement
Total 87.20 Use in the Societal Test
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Methane Leaks from Natural Gas lnfrastructure Serving Gas-fired Power Plants
Andrew B. Peterson
R. Thomas Beach
Crossborder Energy
February 19,2016
1. Summary
Naturalgas has been commonly depicted as a "bridge" fuel between coal and renewable
energy for the generation of electricity. Natural gas is considered more environmentally friendly
because buming natural gas produces less COz than coal on a per unit of energy basis. Most
analyses of the greenhouse gas (GHG) emissions associated with buming natural gas to
produce electricity use an emission factor of 117 lbs of COz per MMBtu of natural gas bumed.
However, this number does not include methane leaked to the atmosphere during the
production, processing, and transmission of natural gas from the wellhead to the power plant.
Methane is both the primary constituent of natural gas and a potent greenhouse gas (GHG), so
quantifying the methane leakage is important in assessing the impact of natural gas systems on
globalwarming.
Methane is emitted to the atmosphere from naturalgas systems in both normal
operating conditions and in low frequency, high emitting incidents. The Environmental
Protection Agency's (EPA) "lnventory of U.S. Greenhouse Gas Emissions and Sinks" attempts
to calculate methane emissions from natural gas systems using a "Bottom Up" accounting
method, which essentially adds up methane emissions from production, processing,
transmission, storage, and distribution. This method sets a reasonable baseline for methane
emissions during normal operating conditions, but does not account for low frequency high
emitting situations.
Low frequency high emitting situations happen when some part of the production,
processing, or transmission systems fail, leaking large amounts of methane into the
atmosphere. The recent Aliso Canyon leak from a major Southem California Gas storage field in
Parker Ranch, California is probably the best-known example of a low frequency high emitting
event. The Aliso Canyon leak has emitted 2.4 MMT CO2-eq., or roughly 1.5o/o of totalyearly
methane emissions from all U.S. natural gas lnfrastructure, in a single event. Several studies
have shown that low frequency high emitting events like Aliso Canyon contribute significantly to
methane emissions from natural gas systems.
The following analysis and discussion lays out an argument for increasing the carbon
emission factor for burning natural gas in power plants to include the carbon equivalent of the
methane emitted in the production, processing, transmission, and storage of natural gas,
A-1
leaving out the losses in local distribution that are downstream from power plants on the gas
system. A conservative starting point for the leakage from wellhead to power plant is that 2o/o ot
natural gas produced is lost to leakage in the form of methane. This estimate is based the IPCC
Fifth Assessment Report, the EPA's "lnventory of U.S. Greenhouse Gas Emissions and Sinks,"
adjusted based on several studies quantiffing how the EPA's method underestimates actual
emissions.
Using the conservative estimates of 2o/o of total production emitted, and a global
warming potential (GWP) of 25 (the low end of methane's GWP) increases the COz emitted by
burning methane to 175.5 lbs of COz-eq. per MMBtu of natural gas burned (a factor of 1.5).
Using a GWP of 34 (high end) yields 196.6 lbs of COz per MMBtu of natural gas burned (a
factor of 1.68).
2. Measuring Natura! Gas Leakage (Methods)
Determining methane leaks from natural gas systems is relatively new field of study.
Until 2011 methane leaks were calculated almost exclusively using a Bottom Up accounting
method based on data published in the EPA's "lnventory of U.S. Greenhouse Gas Emissions
and Sinks". Several issues with this method, including outdated Emission Factors and low
frequency high emitting events, have led researchers to use "Top Down" aerial measurements
of methane leakage.
Bottom Up. Bottom Up (BU) methods attempt to identify all sources of methane
emissions in a typical production chain and assign an Emission Factor (EF) to each source. The
total emissions are determined by adding up all of the EFs through the life cycle of natural gas.
BU measurements are useful because they avoid measuring methane from biogenic sources
(landfills, swamps, etc), anthropogenic sources in geographic proximity to natural gas systems
(coal plants, oil wells, etc), and only require an engineering inventory of equipment and activity.
However, BU measurements often rely on decades-old EFs. The EFs used in the EPA's
"lnventory of U.S. Greenhouse Gas Emissions and Sinks" are based on a report published in
1996, which in turn is based on data collected in 1992. The EPA has developed a series of
correction factors based on technological improvements and new regulations.
BU studies have been shown to underestimate methane emissions from natural gas
systems.[1]-[5] \Mile outdated EFs can cause both under and overestimation of emissions,
low frequency high emission events are responsible for consistent underestimation of emissions
by BU calculations.[1], [5]-[7] A recent study in the Barnett Shale region of Texas found that
2o/o of facilities were responsible for 50% of the emissions and 10% were responsible for 90% of
the emissions.[5] BU measurements do not accurately take into account these low frequency
high emitters. First, most BU measurements either sample only a few facilities or rely on facility
and equipment inventories rather than local measurements. Secondly, most BU data is self-
reported. Finally, several studies have found that the low frequency high emitters were both
spatially and temporally dynamic, with the high emission rates resulting from equipment
breakdowns and failures, and not from design flaws in a few facilities.
A-2
Top Down. Top Down (TD) methane measurements have used aerialflyovers to
measure the atmospheric methane content, then use mass balance and atmospheric transport
models to determine methane emissions from a geographical region. A signature compound
such as ethane is used to distinguish fossil methane from biogenic methane. Unlike BU
measurements, TD measurements account for low frequency high emitter situations. TD studies
consistently measure higher levels of methane emissions than do BU studies. Only recently
have measurements TB and BU studies converged, and this convergence was only after
additional low frequency high emission situations were characterized in BU studies.[S]
3. Methane Leak Calculations
The EPA divides methane emissions from natural gas systems into four categories: Field
Production, Processing, Transmission and Storage, and Distribution. This analysis focuses on
only the first three categories, leaving out local distribution networks. Detailed descriptions of
these categories can be found in the EPA'S "lnventory of U.S. Greenhouse Gas Emissions and
Sinks."
US Natural Gas Production 2005 -2013
Expressed as BCF Natural Gas
Source 2005 2009 2010 2011 2012 2013
Withdrawals from Gas Wells
from Shale Shale Wells
16,247
0
14,414
3,958
13,247
5,817
12,291
8,501
12,504
10,533
10,760
11,933
Total Withdrawals from Natural Gas
Systems 16,247 18,373 19,065 20,792 23,037 22,692
Emissions from US Natural Gas Systems 2005 -2013
Expressed as % of Total Production
Staqe 2005 2009 2010 201'.t 2012 2013
Field Production
Processing
Transmission and Storaqe
0.91
0.20
0.59
0.66
0.20
0.56
0.58
0.18
0.53
0.48
0.20
0.51
0.42
0.19
0.M
0.41
0.20
0.47
Total 1.70 1.43 1 .30 1 .19 1 .05 '.t .07
Using the EPA's "lnventory of U.S. Greenhouse Gas Emissions and Sinks," methane
emissions from natural gas infrastructure from the wellhead to a gas-fired power plant
(excluding local distribution) are cunently estimated to be 1 .1% of production.[8] Given that EPA
uses a BU method for calculating emissions, it is reasonable to assume that 1.1% is an
underestimation. A 2015 study that combined seven different datasets from both TD and BU
and included the most aerial measurements to date concluded that methane emissions were 1.9
A-3
(1.5 - 2.4) times the number reported in the EPA's "lnventory of U.S. Greenhouse Gas
Emissions and Sinks."[5] lf the EPA's estimate is multiplied by 1.9 the result is 2.09%.
The !PCC Fifth Annual Report agrees, stating that 'Central emission estimates
of recent analyses are 2o/o - 3o/o (+1- 1%) of the gas produced, where the emissions from
conventional and unconventional gas are comparable." [9]
4. GlobalWarming Potential of Natural Gas
Global warming potentials (GWP) provide a method of comparing different GHGs. A
GWP is: "a relative measure of how much heat a greenhouse gas traps in the atmosphere. lt
compares the amount of heat trapped by a certain mass of the gas in question to the amount of
heat trapped by a similar mass of carbon dioxide." The lntergovernmental Panel on Climate
Change (IPCC) regularly publishes updated GWPs based on the most current scientific
knowledge. The most current value for methane (based on the 2013 IPCC ARS) is 34 for the
1O0-year GWP of methane.[9] The previous value (based on the 2007 IPCC AR4) is 25.
Because methane's heat-trapping impacts are greatest in the first years after it enters the
atmosphere, methane's 20-year GWP is about 85.[10]
5. Conclusion
This report recommends the use of a2Yo emissions rate for methane leakage from
natural gas systems when calculating the GHG emissions associated with natural gas-fired
electric generation. Current analyses use 117 lbs of CO2 per MMBtu as the emissions factor
from burning naturalgas, which essentially asSumes zero leakage. Adopting a 2% emission rate
would increase this number to 190 lbs of CO2 per MMBtu of natural gas burned, assuming a 20-
year GWP of 85.
6. Citations
D. R. Caulton, P. B. Shepson, R. L. Santoro, J. P. Sparks, R. W. Howarth, A. R. lngraffea, M. O. L.
Cambaliza, C. Sweeney, A. Karion, K. J. Davis, B. H. Stirm, S. a Montzka, and B. R. Miller,
'Toward a befter understanding and quantification of methane emissions from shale gas
developmenl.," Proc. Natl. Acad. Sci. U. S. A., vol. 111, no. 17, pp.623742,20'|.4.
R. A. Alvarez, S. W. Pacala, J. J. Winebrake, W. L. Chameides, and S. P. Hamburg, 'Greater
focus needed on methane leakage from natural gas infrastructure.,' Proc. Natl. Acad. Sci. U. S. A.,
vol. 109, no.17, pp.6435-40,2012.
J. Wilcox, a M. Gopstein, D. Arent, S. Wofsy, N. J. Brown, R. Bradley, and G. D. Stucky,
"Methane Leaks from North American Natural Gas Systems,' Science (80-. )., vol. 343, no.6172,
pp. 733-735,2014.
D. R. Lyon, D.Zavala-Araiza, R. A. Alvarez, R. Haniss, V. Palacios, X. Lan, R. Talbot, T. Lavoie,
P. Shepson, T. l. Yacovitch, S. C. Herndon, A. J. Marchese, D. Zimmerle, A. L. Robinson, and S.
P. Hamburg, "Constructing a Spatially Resolved Methane Emission lnventory for the Barnett Shale
Region,' Environ. Sci. Technol., vol.49, no. 13, pp. 8147-8157,2015.
D. Zavala-Araiza, D. R. Lyon, R. A. Alvarez, K. J. Davis, R. Haniss, S. C. Hemdon, A. Karion, E.
A. Kort, B. K. Lamb, X. Lan, A. J. Marchese, S. W. Pacala, A. L. Robinson, P. B. Shepson, C.
Sweeney, R. Talbot, A. Townsend-Small, T. L Yacovitch, D. J. Zimmerle, and S. P. Hamburg,
t11
l2l
t3l
t4I
l5I
A-4
t6I
171
'Reconciling divergent estimates of oil and gas methane emissions,' Proc. Natl. Acad. Sci., vol.
112, no. 51, pp. 1 5597-15602, 2015.
A. L. Mitchell, D. S. Tkacik, J. R. Roscioli, S. C. Hemdon, T. l. Yacovitch, D. M. Martinez, T. L.
Vaughn, L. L. Williams, M. R. Sullivan, C. Floerchinger, M. Omara, R. Subramanian, D. Zimmerle,
A. J. Marchese, and A. L. Robinson, 'Measurements of Methane Emissions from Natural Gas
Gathering Facilities and Processing Plants: Measurement Results," Environ. Sci. Technol., vol. 49,
no.5, pp. 321*3227, Mar.2015.
R. Subramanian, L. L. Williams, T. L. Vaughn, D. Zimmerle, J. R. Roscioli, S. C. Hemdon, T. l.
Yacovitch, C. Floerchinger, D. S. Tkacik, A. L. Mitchell, M. R. Sullivan, T. R. Dallmann, and A. L.
Robinson, "Methane Emissions from Natural Gas Compressor Stations in the Transmission and
Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting
Program Protocol," Environ. Sci. Technol., vol.49, no. 5, pp. 3252-3261, Mar. 2015.
EPA, 'lnventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013,' US Envhon. Prot.
Agency, pp. ES1-ES26, 2014.
IPCC, 'IPCC Fifth Assessment Report (ARs),' [PCC,2013.
EPA, "Understanding Global Warming Potentials," EPA Website, 2016. [Online]. Available:
http://www3.epa.gov/climatechange/ghgemissions/gwps.html.
t8l
teI
[10]
A-5
ATTACHMENT B
IPCU Case No. IPC-E-22-22
ICL !nitial Comments
R. Tnopns Bnacn
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 concerning the natural gas and electric industries. The firm is based in Berkeley,
California, and its practice focuses on the energy markets in California, the U.S., and Canada.
Since 1989, Mr. Beach has had an active consulting practice on policy, economic, and
ratemaking issues concerning renewable energy development, the restructuring of the gas and
electric industries, the addition of new natural gas pipeline and storage capacity, and a wide
range ofissues concerning independent power generation. From l98l 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 California, and worked extensively on the state's implementation of the
Public Utilities Regulatory Policies Act of 1978.
Ann.ls oF EXPERTISE
Renewable Energt Issues: extensive experience assisting clients with issues concerning
Renewable Portfolio Standard programs, including program structure and rate impacts.
He has also worked for the solar industry on rate design and net energy metering issues,
on the creation of the California Solar Initiative, as well as on a wide range of solar issues
in many 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 Westem U.S. He is one of the leading
experts in California on the calculation of avoided cost prices. Other QF issues on
which he has worked include complex QF contract restructurings, standby rates,
greenhouse gas emission regulations, and nafural 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. TnoNr.q.s Bnlcn
Principal Consultant Pase 2
Eouclrrox
Mr. Beach holds a B.A. in English and physics from Dartmouth College, and an M.E. in
mechanical engineering from the University of California at Berkeley.
Ac.Lunurrc Houons
Graduated from Dartmouth with high honors in physics and honors in English
Chevron Fellowship, U.C. Berkeley, 197 8-79
PnornssroNAl AccRrDrrarroN
Registered professional engineer in the state of California.
Exprnr Wlrurss TusrruonY BEFoRE TIIE CALIFoRNIA Punuc UTILITIES CoMMISSION
Prepared Direct Testimony on Behalf of Pacific Gas & Electric Company/Pacific Gas
Transmission (I. 88-12-027 -July 15, 1989)
o Competitive and environmental benefits of new natural gas pipeltne 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)
o Natural gas procurement policy; gas costforecasting.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (R. 88-08-018
- December 7, 1989)
Brolrering of interstate pipeline capacity.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029
-November l, 1990)
o Natural gas procurement policy; gas costforecasting; brokeragefees.
Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing Commission
and the Canadian Producer Group (I. 86-06-005 - December 21,1990)
o Firm and interruptible rates for noncore natural gas users
J
4.
5
o
Crossborder Energt
R. Tnouls Br.r,cn
Principal Consultant Paee 3
6. a.Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - January 25, l99l)
Prepared Responsive Testimony on Behalf of the Alberta Petroleum Marketing
Commission @. 88-08-018 -March 29,1991)
Brokering of interstate pipeline capacity; intrastate transportation policies.
o Natural gas parity ratesfor cogenerators and solar thermal power plants.
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, 1991)
o Avoided cost pricing; use ofpublished natural gas price indices to set avoided
c o st price s for qual ifuin g fac ilit ie s.
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 - Novemb er 26,1991)
o Natural gas pipeline rate design; cost/benefit analysis of rolled-in rates.
Prepared Direct Testimony on Behalf of the Independent Petroleum Association of
Canada (A. 9l-04-003 - January 17,1992)
o Natural gas procurement policy; prudence ofpost gas purchases.
a. Prepared Direct Testimony on Behalf of the California Cogeneration Council
(I.86-06-005/Phase 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.
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.92-
10-017 - February 19, 1993)
. Perlbrmance-basedratemakingforelectricutilities.
b.
7 Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-
029/Phase II -April 17,l99l)
o Natural gas brokerage and transportfees.
8 Prepared Direct Testimony on Behalf of LllZ Partnership Management (A. 9l-01-027
-July 15, l99l)
9
l0
ll.
t2
13
Crossborder Energt
R. Tnopr,q.s Bu.q,cH
Principal Consultant Page 4
14.
t5
16.
17.
l8
19.
20
21.
a
a.
b.
Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-02-0141A.93-03-053
-May 21,1993)
Natur al gas tr dnsportat ion serttice for w hole sale customers.
Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A.92-12-0431A.93-03-038 - June 28, 1993)
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.
Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-05-023 -November 10, 1993)
Prepared Rebuttal Testimony on Behalf of the SEGS Projects (C. 93-05-023 -January 10,1994)
Utility overcharges for natural gas service; cogeneration parity issues.
Prepared Direct Testimony on Behalf of the City of Vernon (A. 93-09-006/A. 93-08-
0221A.93-09-048 - June 17,1994)
o Natural gas rate designfor wholesale customers; retail competition issues.
Prepared Direct Testimony of R. Thomas Beach on Behalf of the SEGS Projects (4.94-
01-021 -August 5,1994)
o Natural gas rote design issues; rate parityfor solar thermal power plonts.
Prepared Direct Testimony on Transition Cost Issues on Behalf of Watson Cogeneration
Company (R. 94-04-0311L 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
Cogeneration Council (A. 93- I 2-025 il. 94-02-002 - February 14, 1995)
Recovery ofabove-market nuclear plant costs under electric restructuring.
Prepared Direct Testimony on Behalf of the Sacramento Municipal Utility District (A.
94-l l-015 - June 16, 1995)
o Natural gas rate design; unbundled mainline transportation rates.
a
a.
b.
a
a
Crossborder Energt
R. Tnour,q.s Brlcu
Principal Consultant Page 5
22.
23
24.
a
26. a
Prepared Direct Testimony on Behalf of Watson Cogeneration Company (A. 95-05-049
- September 11, 1995)
o Incremental Energ,, Rates; air quolity compliance costs.
a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A. 92-12-043 I A. 93 -03-03 8/A. 9 4-0 5 -03 5 I A. 9 4-06-03 4 I A. 9 4-09 -
0561A.94-06-044 - January 30, 1996)b. Prepared Rebuttal Testimony on Behalf of the Canadian Association of
Petroleum Producers (A. 92-12-043 I A. 93 -03-03 8/A. 94-05 -03 5 I A. 94-06-
0341 A. 94-09 -0561 A. 94-06-044 - February 28, 1996)
o Natural gos market dynamics; gas pipeline rate design.
Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 96-03-031 - July 12, 1996)
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 gos and electric
morkets.
a
b.
Prepared Direct Testimony on Behalf of the Electricity Generation Coalition
(A.97-03-002- December 18, 1997)
Prepared Rebuttal Testimony on Behalf of the Electricity Generation Coalition
(A. 97-03-002 -January 9, 1998)
Natural gas rate designfor gas-fired electric generators.a
27.Prepared Direct Testimony on Behalf of the City of Vernon (A. 97-03-015 - January
16, 1998)
o Natural gas service to Baja, California, Mexico.
Crossborder Energt
R. Tnonaas Bolcu
Principal Consultant Page 6
28. a.
b.
c.
a
29. a.
b.
c.
d.
e.
o
30. a.
b.
a
31. a.
b.
a
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. 98-10-0121A.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 I l, 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
of the 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).
Marlret-based, avoided cost pricingfor the electric output of ga*fired
cogenerationfacilities 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 Southem California 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 0. 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 qtstem. 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 Councit (A. 00-04-002 - September l, 2000).
Prepared Direct Testimony on behalf of Southern Energy California (A. 00-04-
002 - September l, 2000).
Natural gas cost allocotion and rate designfor gas-fired electric generators.
Crossborder Energt
R. Tnotvrls Brlcn
Principal Consultant Page 7
32.
33
a. Prepared Direct Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - September 18,2000).b. 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 Energy Group &
Calpine Corporation (I. 00- I I -002-April 25, 200 I ).b. Prepared Rebuttal Testimony on behalf of PG&E National Energy Group &
Calpine Corporation (I. 00-l l-002-May 15,2001).
o Terms and conditions of natural gas service to electric generators; gas
curtailment policies.
a. Prepared Direct Testimony on behalf of the California Cogeneration Council
s.. 99-1 l-022-May 7, 2001).b. Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
(R. 99-l l-022-May 30, 2001).
o Avoided cost pricingfor alternative energt producers in California.
a. Prepared Direct Testimony of R. Thomas Beach in Support of the Application of
Wild Goose Storage Inc. (A.01-06-029-June 18,2001).b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Wild Goose
Storage (A. 0 l -06-029-November 2, 200 I )
o Consumer benefitsfrom expanded natural gas storage capacity in California.
Prepared Direct Testimony on behalf of the County of San Bernardino (I. 0l-06-047-
December 14,2001)
o Reasonableness review of a natural gas utility's procurement practices and
storage operations.
a. Prepared Direct Testimony on behalf of the California Cogeneration Council
(R. 0 1 - I 0-024-May 31, 2002)b. Prepared Supplemental Testimony on behalf of the California Cogeneration
Council (R. 0l-10-02FMay 31,2002)
Electric procurement policies for California's electric utilities in the aftermath of
the California energt crisis.
34.
35.
36.
37.
o
Crossborder Energt
R. Tnouls Bnlcu
Principal Consultant Paee 8
38
39
40
43
Prepared Direct Testimony on behalf of the California Manufacturers & Technology
Association (R. 02-01-0 I l-June 6, 2002)
o "Exit fees" for direct access customers in Califurnia.
Prepared Direct Testimony on behalf of the County of San Bernardino (A.02-02-012
-August 5,2002)
General rate case issues for a natural gas utility; reasonableness review of a
natural gas utility's procurement proctices.
a
a
41. a.
b.
a
42. a.
b.
Prepared Direct Testimony on behalf of the California Manufacturers and Technology
Association (A. 98-07-003 -February 7,2003)
Recovery of past utility procurement costsfrom direct occess customers.
Prepared Direct Testimony on behalf of the California Cogeneration Council,
the California Manufacturers & Technology Association, Calpine
Corporation, and Mirant Americas, Inc. (A 01-10-01I - February 28,2003)
Prepared Rebuttal Testimony on behalf of the California Cogeneration Council,
the California Manufacturers & Technology Association, Calpine
Corporation, and Mirant Americas,Inc. (A 0l-10-01I -March 24,2003)
Rate design issuesfor Pactfic Gas & Electric's gas transmission system (Gas
Accord II).
Prepared Direct Testimony on behalf of the California Manufacturers &
Technology Association; Calpine Corporation; Duke Energy North America;
Mirant Americasr lnc.; Watson Cogeneration Company; and West Coast
Power, Inc. (R. 02-06-041 - March 21, 2003)
Prepared Rebuttal Testimony on behalf of the California Manufacturers &
Technology Association; Calpine Corporation; Duke Energy North America;
Mirant Americasr lnc.; Watson Cogeneration Company; and West Coast
Power, Inc. (R. 02-06-041 - April 4, 2003)
o Cost allocation of above-market interstate pipeltne costsfor the California
natural gas utilities.
Prepared
Californ
Direct Testimony of R. Thomas Beach and Nancy Rader on behalf of the
ia Wind Energy Association (R. 0l-10-024 - April l, 2003)
Design and implementotion of a Renewable Portfulio Standard in Califurnia.a
Crossborder Energt
R. Tnovns Bu^LcH
Principal Consultant Page 9
44. a.
45
46.
47.
b.
Prepared Direct Testimony on behalf of the California Cogeneration Council
(R. 0l-10-024 - June 23, 2003)
Prepared Supplemental Testimony on behalf of the California Cogeneration
Council (R. 0l-10-024 - June 29,2003)
o Power procurement policiesfor electric utilities in Califurnia.
Prepared Direct Testimony on behalf of the Indicated Commercial Parties (02-05-004
- August 29,2003)
o Electric revenue allocation and rate design for commerciol customers in southern
Califurnia.
a. Prepared Direct Testimony on behalf of Calpine Corporation and the
California Cogeneration Council (A. 04-03-021- July 16, 2004)b. Prepared Rebuttal Testimony on behalf of Calpine Corporation and the
. California Cogeneration Council (A. 04-03-021 - July 26,2004)
. PoliW and rate design issuesfor Pocific Gas & Electric's gas transmission
system (Gas Accord III).
Prepared Direct Testimony on behalf of the California Cogeneration Council (A. 04-
04-003 - August 6,2004)
Policy and contract issues concerning cogeneration QFs in Califurnia.
Prepared Direct Testimony on behalf of the California Cogeneration Council
and the California Manufacturers and Technology Association (4.04-07-044
- January I 1,2005)
Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
and the California Manufacturers and Technology Association (A.04-07-044
-January 28,2005)
Natural gas cost allocation and rate designfor large transportation customers in
northern Califurnia.
Prepared Direct Testimony on behalf of the California Manufacturers and
Technology Association and the Indicated Commercial Parties (A.04-06-024
- March 7,2005)
Prepared Rebuttal Testimony on behalf of the California Manufacturers and
Technology Association and the Indicated Commercial Parties (4.04-06-024
-April 26,2005)
Electric marginal costs, revenue allocation, and rate designfor commercial and
industrial electric customers in northern Califurnia.
48.
49. a.
a
a.
b.
a
b.
Crossborder Energ,t
R. Tnolr^q.s BB.lcH
Principal Consultant Page l0
50.
51.
52. a.
53.
54. a.
55.
56.
a
a
Prepared Direct Testimony on behalf of the California Solar Energy Industries
Association (R. 04-03-017 - April 28,2005)
Cost-effectiveness of the Million Solar Roofs Program.
Prepared Direct Testimony on behalf of Watson Cogeneration Company, the
Indicated Producers, and the California Manufacturing and Technology Association
(A. 04-12-004 - July 29,2005)
o Natural gas rate design policy; integration of gas utility systems.
Prepared Direct Testimony on behalf of the California Cogeneration Council
(R. 04-04-003/R. 04-04-025 - August 31,2005)
Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
(R. 04-04-003/R. 04-04-025 - October 28, 2005)
Avoided cost rates and controcting policiesfor QFs in California
Prepared Direct Testimony on behalf of the California Manufacturers and
Technology Association and the Indicated Commercial Parties (A. 05-05-023
-January 20,2006)
Prepared Rebuttal Testimony on behalf of the California Manufacturers and
Technology Association and the Indicated Commercial Parties (A. 05-05-023
-February 24,2006)
Electric marginal costs, revenue allocation, and rate designfor commercial ond
industrial electric customers in southern Caltfornia.
b.
O
a.
b.
a
Prepared Direct Testimony on behalf of the California Producers
018 - January 30, 2006)
Prepared Rebuttal Testimony on behalf of the California Producers
08-018 - February 21,2006)
( R. 04-08-
( R. 04-b.
o Transportation and balancing issues concerning Califurnia gas production.
Prepared Direct Testimony on behalf of the California Manufacturers and Technology
Association and the Indicated Commercial Parties (A. 06-03-005 - October 27,
2006)
o Electric morginal costs, revenue allocation, and rate designfor commercial and
industrial electric customers in northern Califurnia.
Prepared Direct Testimony on behalf of the California Cogeneration Council (A. 05-
12-030 - March 29,2006)
Review and approval of a new contract with a gas-fired cogeneration project
Crossborder Energt
R. Tsorrl.s Bnlcu
Principal Consultant Page ll
57. a.
58
59. a.
60. a.
61. a.
b.
Prepared Direct Testimony on behalf of Watson Cogenerationr lndicated
Producers, the California Cogeneration Council, and the California
Manufacturers and Technology Association (A. 04-12-004 - July 14, 2006)
Prepared Rebuttal Testimony on behalf of Watson Cogeneration,Indicated
Producers, the California Cogeneration Council, and the California
Manufacturers and Technology Association (A. 04- l 2-0 04 - July 3 I , 2006)
o Restructuring of the natural gas system in southern Califurnia to includefirm
capacity rights; unbundling of natural gas services; risHreward issuesfor natural
gas utilities.
Prepared Direct Testimony on behalf of the California Cogeneration Council (R. 06-
02-013 -March 2,2007)
. Utility procurement policies concerning gas-fired cogenerationfacilities.
Prepared Direct Testimony on behalf of the Solar Alliance (A. 07-01-047 -August 10,2007)
Prepared Rebuttal Testimony on behalf of the Solar Alliance (A. 07-01-047 -September 24,2007)
Electric rate design issues thot impact customers installing solar photovoltaic
systems.
Prepared Direct Testimony on Behalf of Gas Transmission Northwest
Corporation (A. 07-12-021 - May 15, 2008)
Prepared Rebuttal Testimony on Behalf of Gas Transmission Northwest
Corporation (A.07-12-021 - June 13, 2008)
Utility substiption to new natural gas pipeline capacity serving California.
Prepared Direct Testimony on behalf of the Solar Alliance (A. 08-03-015 -September 12,2008)
Prepared Rebuttal Testimony 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-owned solar photovoltaic systems.
b.
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Principal Consultant Page 12
62.Prepared Direct Testimony on behalf of the Solar Alliance (A. 08-03-002 - October 3 l,
2008)
Electric rate design issues that impact customers installing solar photovoltaic
systems.
Phase II Direct Testimony on behalf of Indicated Producers, the California
Cogeneration Council, California Manufacturers and Technology
Association, and Watson Cogeneration Company (A. 08-02-001 - December
23,2008)
Phase II Rebuttal Testimony on behalf of Indicated Producers, the California
Cogeneration Council, California Manufacturers and Technology
Association, and Watson Cogeneration Company (A. 08-02-001 - January
27,2009)
a
63. a.
64
65.
66
67
b
Naturol gas cost allocation and rate design issues for large customers.
Prepared Direct Testimony 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.
Prepared Direct Testimony on behalf of Indicated Producers and Watson
Cogeneration Company (A. 10-03-028 - October 5, 2010)
Prepared Rebuttal Testimony on behalf of Indicated Producers and Watson
Cogeneration Company (A. 10-03-028 - October 26,2010)
o Revisions to a program offirm backbone capacity rights on natural gas pipelines
Prepared Direct Testimony on behalf of the Solar Alliance (A. 10-03-014 - October 6,
2010)
o Electric rate design issues that impact customers installing solar photovoltaic
systems.
Prepared Rebuttal Testimony on behalf of the Indicated Settling Parties (A. 09-09-013
- October 11, 2010)
o Testimony on proposed modifications to a broad-based settlement of rate-reloted
issues on the Pacific Gas & Electric natural gas pipeline system.
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Principal Consultant Page 13
Supplemental Prepared Direct Testimony on behalf of Sacramento Natural Gas
Storage, LLC (A. 07-04-013 - December 6, 2010)
Supplemental Prepared Rebuttal Testimony on behalf of Sacramento Natural
Gas Storage, LLC (A. 07-04-013 - December 13,2010)
Supplemental Prepared Reply Testimony on behalf of Sacramento Natural Gas
Storage, LLC (A. 07-04-013 - December 20,2010)
Local reliability benefits of a new natural gas storogefacility.
69 Prepared Direct Testimony on behalf of The Vote Solar Initiative (A. l0-11-01S-June
l, 201 l)
Distributed generation policie s ; utility distribution planning.
68. a.
a
70.
71.
72. a.
74.
b,
c.
a
b.
Prepared Reply Testimony on behalf of the Solar Alliance (A. l0-03-014-August 5,
20tt)
Electric rate destgnfor commercial & industrial solar customers.
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
I 1 -06-007-February 6, 2012)
Electric rate designfor solar customers; marginal costs
Prepared Direct Testimony on behalf of the Northern California Indicated
Producers (R. I l -02-0 l9-January 31, 2012)
Prepared Rebuttal Testimony on behalf of the Northern California Indicated
Producers (R. I l-02-019-February 28,2012)
a Natural gas pipeline safety policies and costs
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A
I I - I 0-002-Jwe 12, 2012)
o Electrtc rate designfor solar customers; marginal costs.
Prepared Direct Testimony on behalf of the Southern California Indicated Producers
and Watson Cogeneration Company (A. 1l-l l-002-June 19, 2012)
o Natural gos pipeline safety policies and costs
73
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Princinal Consultant Paee 14
75. a.
76. a.
77
78.
79
b.
Testimony on behalf of the California Cogeneration Council (R. l2-03-014-
June 25, 2012)
Reply Testimony on behalf of the California Cogeneration Council (R. l2-03-
01,1-July 23,2012)
Ability of combined heat and power resources to serve local reliability needs in
southern California.
Prepared Testimony on behalf of the Southern California Indicated Producers
and Watson Cogeneration Company (A. I l-l l-002, Phase 2-November 16,
2012)
Prepared Rebuttal Testimony on behalf of the Southern California Indicated
Producers and Watson Cogeneration Company (A. I l-l l-002, Phase 2-
December 14,2012)
o Allocation and recovery of natural gas pipeline safety costs.
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
l2-12-002-May I 0, 2013)
o Electric rate design for commercial & industrial solar customers; marginal costs.
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
I 3-04-0l2-December I 3, 201 3)
o Electric rate design for commercial & industrial solar customers; marginal costs.
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
I 3-12-01 5-June 30, 2014)
Electric rate designfor commercial & industrial solar customers; residenttal
time-of-use rate design issues.
b.
a
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R. Tnorr^Ls Bu.c,cn
Principal Consultant Page 15
Prepared Direct Testimony on behalf of Calpine Corporation and the Indicated
Shippers (A. 1 3- I 2-0 I 2-August ll, 2014)
Prepared Direct Testimony on behalf of Calpine Corporation, the Canadian
Association of Petroleum Producers, Gas Transmission Northwest, and the
City of Palo Alto (A. l3-12-012-August1l,20l4)
Prepared Rebuttal Testimony on behalf of Calpine Corporation (A. l3-12-012-
September 15,2014)
Prepared Rebuttal Testimony on behalf of Calpine Corporation, the Canadian
Association of Petroleum Producers, Gas Transmission Northwest, and the
City of Palo AIto (A. l3-12-012-September 15, 2014)
o Rate design, cost allocation, and revenue requirement issues for the gas
transmission system of a major natural gas utility.
81. Prepared Direct Testimony on behalf of the Solar Energy Industries Association (R.
l2-06-013-September 15, 201 4)
. Comprehensive review of policies for rote design for residential electric
customers in California.
82. Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
l4-06-014-March 13, 2015)
o Electric rate designfor commercial & industrial solar customers; marginal costs.
83. a. Prepared Direct Testimony on behalf of the Solar Energy Industries Association
(A.14-l l-014-May l, 2015)b. Prepared Rebuttal Testimony on behalf of the Solar Energy Industries
Association (A. l4-l l-OI,{-May 26,2015)
o Time-of-use periodsfor residential TOU rates.
Prepared Rebuttal Testimony on behalf of the Joint Solar Parties (R. 14-07-002 -September 30, 2015)
80. a.
84
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85
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b.
c.
d.
Electric rate design issues concerning proposals for the net energl metering
succe s sor tor iff in C al ifornio.
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
I 5-04-012-July 5, 201 6)
Selection of Time-of-Use periods, ond rate design issues for solar customers.
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Principal Consultant Page 16
86
87
88
89
9l
92
93
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
l6-09-003 - April 28,2017)
Selection of Time-of-Use periods, and rate design issues for solar customers.
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
17-06-030 - March 23,2018)
Selection of Time-of-Use periods, and rate design issues for solar customers.
a
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Prepared Direct and Rebuttal Testimony on behalf of Calpine Corporation (A. l7-l l-
009 - July 20 and August 20,2018)
o Gas transportation ratesfor electric generators, gas storage and balancing issues
Prepared Direct Testimony on behalf of Gas Transmission Northwest LLC and the
City of Palo AIto (A. l7-l l-009 - July 20, 2018)
o Rate designfor intrastate backbone gas transportation rates
Prepared Direct Testimony on behalf of EVgo (A. l8-l l-003 - April 5, 2019)
o Electric rate designfor commercial electric vehicle charging
Prepared Direct and Rebuttal Testimony on behalf of Vote Solar and the Solar Energy
Industries Association (R. 14-10-003 - October 7 and2l,2019)
. Avoided cost issuesfor distributed energ/ resources
Prepared Direct and Rebuttal Testimony on behalf of EVgo (A. l9-07-006 - January I 3
and February 20,2020)
o Electric rate designfor commercial electric vehicle charging
Prepared Direct Testimony on behalf of the Solar Energy Industries Association (A.
I 9-03-002 - March 17, 2020)
Electric rate design issues for solar and storage customers
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R. Tnou^l,s Bnacn
Principal Consultant Pase 17
2
Exrsnr WtrnBss Tnsrruorw Bpronr rHE ARrzoxl Conpouuon CorrurssloN
Prepared Direct, Rebuttal, and Supplemental Testimony on behalf of The Alliance for
Solar Choice (TASC), (Docket No. E-00000J-14-0023, February 27, April T, and June
22,2016).
o Development of a benefit-cost methodologfor distributed, net metered solar
resources in Arizona.
Prepared Sunebuttal and Responsive Testimony on behalf of the Energy Freedom
Coalition of America @ocket No. E-01933A-15-0239 - March l0 and September 15,
2016).
. Critigue of a utility-owned solor program; comments on a/ixed rate credit to
replace net energt metering.
Direct Testimony on behalf of the Solar Enelgy Industries Association (Docket No. E-
0 I 345A-l 6-0036, February 3, 2017).
4. Direct and Surrebuttal Testimony on behalf of The Alliance for Solar Choice and the
Energr Freedom Coalition of America @ocketNos. E-01933A-15-0239 (TEP), E-
01933A-15-0322 (TEP), and E-04204A-15-0142 (LJNSE) - May 17 and September 29,
2017).
Expnnr WrrxBss Trsruuorw Bnronr rnE CoLoRADo PuBLrc Uru,rnps Comutsslox
Direct Testimony and Exhibits on behalf of the Colorado Solar Energy Industries
Association and the Solar Alliance, @ocketNo. 09AL-2998- October 2,2009).
https://www.dora.state.co.us/pls/efi/DDMS_Public.Display_Document?p_section:PUC&
p_source=EFI-PRIVATE&p-doc-id:3470 I 90&p-docjey:0CD8F7FCDB673F I 04392
8849D9D8CAB I &p-handle nolfound:Y
2.
o Electric rate design policies to encourage the use of distributed solar generation.
Direct Testimony and Exhibits on behalf of the Vote Solar Initiative and the Intenstate
Renewable Energy Council, (Docket No. I lA-418E - September 21,201 l).
o Development of a community solar programfor Xcel Energt.
Answer Testimony and Exhibits, plus Opening Testimony on Settlement, on behalf of the
Solar Energy Industries Association, (Docket No. I6AL-0048E [Phase II] - June 6 and
September 2,2016).
3
Rate design issues related to residential customers and solor distributed
generation in a Public Sertice of Colorado general rate case.
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Principal Consultant Page 18
Exprnr Wnxrss Trstrrrorw BEFoRETHB Groncra Punlrc Srnvrcs Couurssrox
l. Direct Testimony on behalf of Georgia Interfaith Power & Light and Southface
Energy Institute, Inc. (Docket No. 40161 - May 3,2016).
o Development of a cost-ffictiveness methodologtfor solar resources in Georgia.
Expnnr WITNESS Trsrrvroxy BEFoRE urp lplHo Punr.rc Urrr,rups Couurssrolv
I Direct Testimony on behalf of the ldaho Conservation League (Case No. IPC-E-12-
27-May 10,2013)
2.
Costs and benefits of net energ/ metering in ldaho.
Direct Testimony on behalf of the Idaho Conservation League and the Sierra
Club (Case Nos. IPC-E- I 5-0 I /AVU-4- I 5-0 I /PAC-E- I 5-03 - April 23, 201 5)
Rebuttal Testimony on behalf of the Idaho Conservation League and the Sierra
CIub (Case Nos. IPC-E- 1 5-0 I /AVU-4- I 5-0 I /PAC-E- I 5-03 - May 14, 201 5)
Issues concerning the term of PURPA contracts in ldaho.
2.Direct Testimony on behalf of the Sierra Club (Case No. IPC-E-17-13 -December 22,2017)
Rebuttal Testimony on behalf of the Sierra Club (Case No. IPC-E-17-13 -January 26,2018)
Exppnr WIrNrss TBsrrvrorw Bpronr rHr M,rss.q,cHUsETTs DnpLnrunNT oF Pusllc
Uur.rrrps
Direct and Rebuttal Testimony on behalf of Northeast Clean Energy Council,Inc.
@ocket D.P.U. l5-155, March l8 and April 28, 2016)
Residential rate design and accessfee proposols related to dtstributed generation
in a National Grid general rate case.
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Exprnr Wmxpss TusuvroNv Bnrone rnn MtcnrcAN PuBLrc SERvrcE ConnvrtssroN
Prepared Direct Testimony on behalf of Vote Solar (Case No. U-I8419-January 12,
2018)
Prepared Rebuttal Testimony on behalf of the Environmental Law and Policy Center,
the Ecology Center, the Solar energy Industries Association, Vote Solar, and the
Union of Concerned Scientists (Case No. U-I8419 - February 2,2018)
2.
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R. Tnopas Brlcu
Principal Consultant
I
Expnnr Wrrxpss TBsrruoxv Bnronr rno MnrNpsora Punr,rc UrrI,rrrus Couurssrox
Direct and Rebuttal Testimony on Behalf of Geronimo Energy, LLC. (In the Matter of
the Petition of Northern States Power Company to Initiate a Competitive Resource
Acquisition Process [OAH Docket No. 8-2500-30760, MPUC Docket No. E002/CN-12-
1240, September 27 and October 18, 20131)
Testimony in support of a competitive bidfrom a distributed solar project in an
all-source solicitation for generating capacity.
ExpnRr Wrnvoss TssrrMoxv Buronr rHE MoNTANA PuBLrc Sunvtcn Co*rurssron
Pre-filed Direct and Supplemental Testimony on Behalf of Vote Solar and the Montana
Environmental Information Center (Docket No. D2016.5.39, October 14 and
November 9,2016).
Avoided cost pricing issuesfor solar QFs in Montana.
Page 19
Market-bosed, avoided cost pricingfor the electric output of geothermal
generation fac tlitie s in Nevada.
Prepared Direct Testimony on behalf of The Alliance for Solar Choice (TASC),
(Docket Nos. I 5-0704 I and I 5-07 042 -October 27, 201 5).
Prepared Direct Testimony on Grandfathering Issues on behalf of TASC, (Docket
Nos. 15-07041 and l5-07042-February 1,2016).
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Exprnr WrrNnss Tnstruoxv BEFoRE THE PUBLIc Uru.rrms CouulssroN oF NEvADA
Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 97-2001-May 28,1997)
a Avoided cost pricingfor the electric output of geothermal generotionfacilities in
Nevada.
2.Pre-filed Direct Testimony on Behalf of Nevada Sun-Peak Limited Partnership
(Docket No. 97-6008-September 5, 1997)
. 8F pricing issues in Nevada.
Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 98-2002 - June 18, 1998)
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R. Tnorr.Ls Bn.l,cn
Principal Consultant Page 20
c. Prepared Rebuttal Testimony on Grandfathering lssues on behalf of TASC,
(Docket Nos. I 5-07041 and l5-07042-February 5, 2016).
o Net energ/ metering and rate design issues in Nevoda.
ExruRr Wmxpss Tnsrruoxv Brronr rHB NTwHAMpsHRE PrrBLrc Urrlmrns Coprulsstox
I Prepared Direct and Rebuttal Testimony on behalf of The Alliance for Solar Choice
(TASC), (Docket No. DE 16-576, October 24 and December 21,2016).
o Net energt metering and rate design issues in New Hampshire
Expnnr Wmxpss Trsuuoxv BsroRB THE NEw Msxrco Punuc RrcumuoN CoMMrssroN
Direct Testimony on Behalf of the Interstate Renewable Energy Council (Case No. l0-
00086-UT-February 28, 20 I l)
http://l 64.64.85. I 08/infodocs/201 I /3/PRS20l 568 I ODOC.PDF
c Testimony on proposed standby ratesfor new distributed generation projects;
cost-ffictiveness of DG in New Mexico.
Direct Testimony and Exhibits on behalf of the New Mexico Independent Power
Producers (Case No. I l-00265-UT, October 3,2011)
o Cost capfor the Renewable Portftlio Standard prog'om in New Mexico
ExpnRr Wrrxnss Tnstnvroxy Brronr rHE NoRTH Clnor,tNl Uru,mrns Covrurssrox
Direct, Response, and Rebuttal Testimony on Behalf of the North Carolina Sustainable
Energy Association. (In the Maffer of Biennial Determination of Avoided Cost Rates for
Electric Utility Purchases from Qualiffing Facilities - 2014; Docket E-100 Sub 140; April
25,May 30, and June 20, 2014)
Testimony on avoided cost issues related to solor ond renewable qualifuing
facilities in North Carolina.
April 25, 2014: http://starw I .ncuc.netArlCUC/ViewFile.aspx?ld:89Rb50f- I 7cb-421 8-87bd-
c743el238bcl
May 30, 2014: http://starw I .ncuc.netA.lCUC/ViewFile.aspx?ld= l9e0b58d-a7f6-4d0d-9f4a-
08260e561443
June 20,2104 : htto : l/starw I . nc uc. netA.{C UC/V iew F i I
fc6e0bd29a2
I
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e.aspx?ld:b d5497 55-d I b8-4c9b-b4a I -
R. Tnouls Bnlcs
Principal Consultant Paee 2l
2.Direct Testimony on Behalf of the North Carolina Sustainable Energy Association. (In the
Matter of Biennial Determination of Avoided Cost Rates for Electric Utility Purchases
from Qualiffing Facilities - 2018; Docket E-100 Sub 158; June 21, 2019)
a Testimony on avoided cost issues related to solar and renewoble qualifying
focilities in North Carolina.
ExpBnr Wrrxnss Tesrruoxv BBronrrHE PUBLIC Uru,mrrs CounussroN oF OREGoN
a. Direct Testimony of Behalf of Weyerhaeuser Company (UM I129 - August 3,
2004)b. Surrebuttal Testimony of Behalf of Weyerhaeuser Company (UM I129 -October 14,2004\
a. Direct Testimony of Behalf of Weyerhaeuser Company and the Industrial
Customers of Northwest Utilities (UM I129 lPhase II - February 27,2006)b. Rebuttal Testimony of Behalf of Weyerhaeuser Company and the Industrial
Customers of Northwest Utilities (UM I 129 / Phase II - April 7 , 2006)
2
I
Policies to promote the development of cogenerotion and other qualifying
facilities in Oregon.
J Direct Testimony on Behalf of the Oregon Solar Energy Industries Association (UM
l9l0,0l9l l, and l9l2 - March 16, 2018).
a Resource value ofsolar resources in Oregon
Exrpnr WrrxBss Tnsrruoxv Boronp rHE PUBLIC Snnvtcr CoumtssroN oF SoTITH
CnRolna
Direct Testimony and Exhibits on behalf of The Alliance for Solar Choice (Docket No.
201 4-246-E - December I l, 2014)
https://dms.psc.sc.sov/attachments lmatterlBTBACFTA- I 55D- l4 lF -2368C4377 49BEF85
Methodologtfor evaluating the cost-ffictiveness of net energl metering
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Principal Consultant Paee 22
Exrpnr Wrmrnss Tesrruorw Bnronn rnr Pusl,rc Urrlrrrns Copnvrrssrox or Tex.Ls
Direct Testimony on behalf of the Solar Energy Industries Association (SEIA) (Docket
No. 44941 - December I l, 2015)
a Rate design issues concerning net metering and renewable distributed generation
in an El Paso Electric general rate case.
ExpuRr WnNEss Trsruvroxy BsroRE THE PuBLrc Snnucs CouurssroN oF UrAH
Direct Testimony on behalf of the Sierra Club (Docket No. 15-035-53-September 15,
20ls)
o Issues concerning the term of PURPA contracts in ldaho.
Expnnr Wrrxpss Tnsrruorw BSpoRETHEVERMoNT Pr.rBLrc SERvrcE Bo.Lno
l. Pre-filed Testimony of R. Thomas Beach and Patrick McGuire on Behalf of Allco
Renewable Energy Limited @ocket No. 8010 - September 26,2014)
o Avoided cost pricing tssues in Vermont
Expnnr Wmrrss Tnsrruorw Bpronn rnn VrncnvrA CoRpoRATrox CorrutssroN
Direct Testimony and Exhibits on Behalf of the Maryland - District of Columbia - Virginia
Solar Energy Industries Association, (Case No. PUE-201l-00088, October I l, 201l)
http://www.scc.virginia.eov/docketsearch/DoC S/2gx%250 I !.PDF
Cost-effectiveness of and standby ratesfor, net-metered solar customers.
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R. Tnouas Bn^lcn
Principal Consultant Paee 23
Lmrclrtox Exprnnxcr
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 capacity contracts (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 the 2000-2001 Califomia energy crisis.
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