HomeMy WebLinkAbout2016-10-05 Utilities Advisory Commission Agenda Packet
NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I. ROLL CALL
II. ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A
reasonable time restriction may be imposed at the discretion of the Chair. State law generally
precludes the UAC from discussing or acting upon any topic initially presented during oral
communication.
III. APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Special Meeting held on August 31, 2016
IV. AGENDA REVIEW AND REVISIONS
V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI. DIRECTOR OF UTILITIES REPORT
VII. COMMISSIONER COMMENTS
VIII. UNFINISHED BUSINESS
1. Selection of Potential Topics for the Joint Study Session with Council Action
IX. NEW BUSINESS
1. Recommendation that the Utilities Advisory Commission Recommend that Council Action
Adopt a Net Energy Metering (NEM) Transition Policy
2. Staff Recommendation that the Utilities Advisory Commission Recommend that the Action
City Council Approve Design Guidelines for the 2017 Gas Cost of Service Analysis
3. Discussion of Energy Storage and Microgrid Applications in Palo Alto Discussion
4. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: November 2, 2016
ADDITIONAL INFORMATION
The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt.
Code Section 54954.2(a)(2)).
INFORMATIONAL REPORTS - None.
Public Letter(s) to the UAC
UTILITIES ADVISORY COMMISSION
WEDNESDAY, OCTOBER 5, 2016 – 7:00 P.M.
COUNCIL CHAMBERS
Palo Alto City Hall – 250 Hamilton Avenue
Chairman: James F. Cook Vice Chair: Michael Danaher: Commissioners: Arne Ballantine, Lisa Forssell, A. C. Johnston, Judith Schwartz and Terry Trumbull Council Liaison: Gregory Scharff
Utilities Advisory Commission Minutes Approved on: Page 1 of 11
UTILITIES ADVISORY COMMISSION MEETING - SPECIAL MEETING
MINUTES OF AUGUST 31, 2016
CALL TO ORDER
Chair Cook called to order at 7:00 p.m. the meeting of the Utilities Advisory Commission (UAC).
Present: Chair Cook, Vice Chair Danaher, Commissioners Ballantine, Forssell, Johnston,
Schwartz, and Trumbull (Vice Chair Danaher arrived at 7:08 p.m. during the Utilities Director
Report)
Absent: Council Liaison Scharff
ORAL COMMUNICATIONS
David Carnahan, Deputy City Clerk, encouraged community members to volunteer for Boards
and Commissions. Currently there are recruitments going on for 3 positions on the Historic
Resources Board, 4 positions on the Parks and Recreation Commission, 3 positions on the
Planning and Transportation Commission, and 2 positions Storm Drain Oversight Committee.
APPROVAL OF THE MINUTES
Commissioner Trumbull moved to approve the minutes from the June 1, 2016 UAC meeting and
Commissioner Ballantine seconded the motion. The motion carried unanimously (6-0) with
Chair Cook, and Commissioners Danaher, Forssell, Johnston, Schwartz, and Trumbull voting yes
and Vice Chair Danaher absent.
AGENDA REVIEW AND REVISIONS
Chair Cook announced that the New Business Item #2 would be heard before New Business
Item #1.
REPORTS FROM COMMISSION MEETINGS/EVENTS
Commissioner Schwartz gave an update on recent events she attended:
1. The U.S. Department of Energy convened six regional workshops across the country to
obtain stakeholder input on DOE’s grid related R&D Plan as well as a proposed demonstration
strategy that are both outlined in the Grid Modernization Multi-Year Program Plan. The sixth
workshop was held on the Stanford campus on June 7 and 8. Commissioner Schwartz served as
a facilitator to help DOE understand the challenges and opportun ities stakeholders in the
western region face as DOE works to make sure their research is aligned with ind ustry’s needs.
While she did make an effort to bring this event to the attention of our utility staff, Council and
UAC, she unfortunately was the only person from the UAC, the Council or the utility staff in
attendance.
2. On July 11-13, Commissioner Schwartz traveled to Washington DC for the National
Town Meeting on Demand Response and Smart Grid. This is the premier event in the US
focused on the business and policy aspects of demand response and its enabling technologies
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 11
and applications. It is now run by the Smart Electric Power Alliance, which is the organization
resulting from the merger of the Association for Demand Response and Smart Grid and the
Solar Electric Power Association of which our utility is a member.
3. The conference is unique in that it devotes an entire day to roundtable discussions
featuring experts in demand response and smart grid, who discuss with each other and with the
audience the latest trends, issues, and business developments. The National Town Meeting also
features panel discussions, case studies, and presentations of best practices. Another hallmark
is attendee engagement, whether through Q&A sessions with top business leaders and
policymakers, through formal electronic voting, or through the National Town Meeting’s
reception and other networking sessions. Commissioner Schwartz’s formal role was to organize
the breakout track on customer engagement which included five sessions on innovations in
communication, program design, responding to customer-driven technology adoption, use of
data analytics and commercial and industrial programs.
4. On July 24, Commissioner Schwartz addressed the staff subcommittee on Consumer
Affairs at the summer Meeting of NARUC (National Association of Regulatory Utilit y
Commissioners.) Commissioner Schwartz presented findings from a recent research project on
what other industries that target low Income consumers have to teach the utility industry and
its regulators. Another session Commissioner Schwartz attended featured CPUC Commissioner
Catherine Sandoval speaking about the impact the upcoming closing of the Aliso Canyon gas
field will have on transmission and availability of electricity across the state. It did sound like
this could be a factor in Palo Alto’s ability to obtain power from our renewable g eneration
resources down south when there are significant shortages and const raints in Southern
California. One of her other takeaways is how much effort, NARUC commissioners and their
staffs make to understand these complex issues. Commissioner Schwartz appreciate that as a
volunteer body it is not realistic to expect us to make similar investments of time, but as she
discussed with the Council members during her interview, we need to improve our methods for
educating ourselves on the issues in our purview.
UTILITIES DIRECTOR REPORT
1. Advocacy for Electrification: On August 30, California Energy Commissioner Hochschild
invited CPAU staff Shiva Swaminathan and Christine Tam to present on electrification
initiatives within Palo Alto to the CEC. The presentation covered four areas under
evaluation: customer programs to incentivize replacement of gas appliances with electric
alternatives, building code changes to require electric appliances for new construction and
renovation projects, changes to the utility rate structures, and support for electric vehicle
adoption. The presentation also discussed the role of electrification to meet the Governor’s
greenhouse gas reduction goal of 80% by 2050, and how policy makers, utilities, local
governments can coordinate their efforts to support electrification.
2. Western’s 2025 Power Marketing Plan: The Western Area Power Administration (Western)
has officially started the development of its 2025 Power Marketing Plan. The Plan sets
allocations and terms for marketing energy after 2024 when the current Western Base
Resource Contract expires. The proposed 2025 Marketing Plan would extend the current
Western Base Resource Contract 30 years through 2054 with allocations up to 98% of
current allocations. Palo Alto submitted comments on the plan to include certain
termination, allocation reduction and cost containment provisions. Western will publish the
Final 2025 Power Marketing Plan in June 2017. Staff will bring this item to the UAC and
Council for discussion along with a tentative schedule and decision points.
Utilities Advisory Commission Minutes Approved on: Page 3 of 11
3. Net Energy Metering (NEM) Successor Program: On August 22, City Council approved the
NEM Successor Program and directed staff to develop alternatives to the NEM transition
policy. Council also directed staff to use a modified method to calculate the NEM cap, which
will increase the cap from the prior cap of 9.5 MW. Staff will present the results of these
findings to the UAC at its October meeting. Staff is developing communication materials to
inform customer and industry affiliates about the transition to the NEM Successor Program
after the new cap has been reached.
4. Live Demo of Emergency Response to Utility Line Strikes: In June, CPAU and Office of
Emergency Services played a leading role in demonstrating emergency response to an
accidental gas and electric line “dig-in.” The event highlighted the importance of safety
prevention measures for excavation. Senator Jerry Hill provided a keynote address with
praise for Palo Alto’s safety practices.
5. The 2015 Consumer Confidence Report on water quality is available online in English,
Spanish and Mandarin at cityofpaloalto.org/waterquality. Customers may contact us to
request a printed version. The City also provides a copy of the 2016 Public Health Goals
Report at this water quality webpage.
6. Groundbreaking for San Francisquito Flood Control Project: On August 5, the City
celebrated groundbreaking on a major flood control improvement project for San
Francisquito Creek, along with partners of the Creek JPA, Santa Clara Valley Water District,
Cities of East Palo Alto, Menlo Park, San Mateo County Flood Control District, members of
the state Senate and Assembly, and US Fish and Wildlife Service.
7. Gas Safety Awareness: CPAU is required to maintain a public awareness outreach plan
about gas safety, which includes distributing an annual gas safety awareness brochure.
These brochures were mailed in August to all customers, non -customers living around a gas
pipeline, locators, excavators, contractors and plumbers working in and around Palo
Alto. This brochure is available online in English, Spanish and Mandarin at
cityofpaloalto.org/safeutility
8. Joint UAC/Council Meeting: The City Clerk’s office scheduled the Joint Study Session
between the Council and the UAC on October 17.
The September 7 UAC meeting has been cancelled. The next regularly scheduled UAC meeting
is October 5.
COMMISSIONER COMMENTS
None.
UNFINISHED BUSINESS
None.
Utilities Advisory Commission Minutes Approved on: Page 4 of 11
NEW BUSINESS
ITEM 1: ACTION: Selection of Potential Topics for the Joint Study Session with Council
Ed recommended that the UAC brainstorm some ideas and then Chair and Vice Chair meet with
the Mayor and Vice Mayor to determine an agenda for the October 17 joint meeting.
Chair Cook reminded the commission that the 5 topics that came out of the last joint meeting
were recycled water, second transmission line, electrification, fiber-to-the-premises (FTTP), and
undergrounding of electric distribution lines.
Commissioner Ballantine said that he supported discussing a second transmission line,
microgrids, and other grid resiliency issues.
Commissioner Schwartz suggested the topic of education of the commission and how to bring
information from outside sources and best practices to ensure that decision -makers have the
latest information. She said that the City of Palo Alto Utilities is not on the leading edge and not
the most informed and able to see the most important priorities.
Public comment
Jeff Hoel said that the most important thing is to get square with Council about what should be
done with respect to agenda control, verbatim minutes, UAC responsibility for FTTP, and a new
electric connection.
Commissioner Trumbull agreed that the UAC should determine the UAC’s respon sibility with
respect to fiber. He said that the capital budget could be adjusted such that when there are
dips in costs, CIP expenditures can be accelerated.
Interim Director Shikada said that there is one more UAC meeting before the October 17 joint
meeting so that topics could be discussed at the October 5 UAC meeting.
Commissioner Schwartz asked if there be a new Utilities Director by then since there could be a
difference in communication styles. In her interview with the Council, the idea of a report to
the Council from the UAC could be discussed.
ACTION:
None.
ITEM 2. ACTION: Recommendation that Council Approve a Carbon Neutral Natural Gas
Portfolio Plan to Achieve Maximum Carbon Neutrality Using a Combination Of Offsets and
Biogas in the Gas Supply Portfolio by Fiscal Year 2018 with No Greater than 10¢/Therm Rate
Impact; and Related Termination of the Palo Alto Green Gas Program
Senior Resource Planner Karla Dailey provided a presentation summarizing the written report.
Chief Sustainability Officer Gil Friend said that the Sustainability/Climate Action Plan (S/CAP)
includes a plan to get to a carbon neutral utility and an aspirational goal of a carbon neutral
city. He said that moving to an electrified city will be a long and complex process. He said the
proposed program is a bridge to using less natural gas and that a comprehensive approach
including offsets, biogas, efficiency and electrification will be necessary to achieve the city’s
Utilities Advisory Commission Minutes Approved on: Page 5 of 11
long-term goals. He pointed out that buying offsets provides capital for more projects in the
U.S. and potentially locally.
Public Comment
Sandra Slater said that proposal is an interim strategy to get to carbon neutrality as soon as
possible and offsets are a good tool to use for the time being. The price signal that the program
cost provides will encourage gas efficiency and electrification of gas appliances. She suggested
the money currently used to market the voluntary program could be redirected to efficiency
and fuel switching programs. Offsets are not a “pass” for consumers as evidenced by the fact
that Palo Altans continue to conserve electricity despite the carbon neutral electri c supplies.
Lisa van Dusen said that we must do everything and the beauty of this is that it can be done
now and shows an intention to reduce carbon emissions in the long term. We have policies in
place such as the 2009 proclamation to include environmental externalities and the S/CAP goal
to reduce greenhouse gas (GHG) emissions by 80% by 2030. It may be faulted as not enough or
too much, but it’s a good move in the right direction.
Vice Chair Danaher said that the UAC received a comment from a member of the public who
pointed out the proposed offset purchases do not cover fugitive methane losses from natural
gas production and transportation. Vice Chair Danaher added that methane is as bad as coal
due to the fugitive emissions. Commissioner Ballantine said that that position is not reflected in
any DOE report that he searched for. Commissioner Schwartz agreed that the coal and natural
gas are not considered to be equally bad by industry experts.
Vice Chair Danaher said the proposed program is a good starting point and asked about the
value of purchasing biogas. Dailey confirmed biogas is more expensive than offsets and it is
Council’s prerogative to decide whether biogas is worth including . Commissioner Danaher
asked where the methane comes from. Dailey explained the gas comes from landfills and
agriculture, mainly dairy farms.
Commissioner Ballantine said that if the source is dairy farms, then avoided methane emissions
need to be considered. Dailey explained that offsets are generated by preventing methane
from entering the atmosphere and the resulting biogas is a renewable fuel. A specific project
can produce both offsets and renewable biogas.
Commissioner Trumbull said that the request is fine, but he would like to get off gas as soon as
possible. He suggested that rather than buying biogas, extra funds be used for electrification.
Commissioner Johnston asked about the monthly bill impact of the 10 cent per therm rate
increase. Dailey answered that an average residential customer’s winter bill would increase by a
little more than $5 per month and pointed to a chart in the written report with the detail.
Commissioner Forssell clarified the proposed amount of carbon to be covered by offsets is only
that combusted in town and does not include methane leakage from the production fields or
leaks in the transportation system. Assistant Director Jane Ratchye said leakage in the
distribution system is covered. Commissioner Forssell asked about leakage data, and Ratchye
said we know the difference between purchases and sales, but that some of the difference is
Utilities Advisory Commission Minutes Approved on: Page 6 of 11
due to mechanical meters operating slowly and not measuring all the gas flow so that the
difference cannot all be attributed to leaks.
Commissioner Schwartz pointed out that the strategic plan says customers should be offered
choices for managing their environmental footprint, but this proposed program does not offer
consumers choices and asked if the strategic objective needs to be changed . Ratchye said that
the supply source is a Council decision similar to the decisions made regarding the composition
of the electric supply portfolio. Commissioner Schwartz disagreed. She said where the
electricity comes from is irrelevant, but if she is being told she can’t have an electric stove , that
is a problem. Ratchye explained again that the proposal is about the gas supply portfolio and
not about electrification.
Commissioner Forssell observed there may be confusion between electrification efforts versus
the proposed carbon neutral gas portfolio.
Commissioner Schwartz asked if we need to change the strategic plan. Interim Director Ed
Shikada said that the strategic plan will be updated.
Commissioner Schwartz said biomethane is not very hard to come by. She said Apple can’t find
biogas to serve its facilities. Dailey replied there is biogas available but very little in California.
She explained that the plan is to get gas elsewhere and displace it in accordance with the
federal renewable fuels rules. She said she has talked to all of the City’s regular gas suppliers
and there is biogas available. She explained the some biogas producers are interested selling a
portion of their production for at a longer term at a fixed price discounted to t he spot price in
order to diversifying their sales portfolios.
Commissioner Schwartz said if we are pushing everyone to electrify, we should talk about that
in the future.
Commissioner Ballantine said he likes the flexibility of the proposal that allows more biogas to
be included as it becomes available. Natural gas infrastructure is more resilient than electric
infrastructure. He said that, if and electric outage occurs, it would be a dark day in Palo Alto if
all is electric. He said the proposal is good because it includes biogas at a modest rate increase
while we start to work on initiatives to improve the resilience of the electric grid. He added that
this action helps to support a biogas marketplace and level the playing field for other ways to
get heat, including solar thermal heating. He also noted that energy efficiency and the incentive
to reduce local leaked gas is valued more.
Vice Chair Danaher said he likes the flexibility of the proposal to maximize biogas.
Chair Cook said he likes the staff proposal and appreciates the public comment. He pointed out
Carbon Free Palo Alto’s caution that it will be a distraction from the real goal of electrification
to reduce GHG emissions and might discourage fuel switching. He noted the differences
between the carbon neutral electric portfolio and the proposed carbon neutral gas portfolio
but suggested we test the hypothesis by determining whether the carbon free electricity
dampened the penetration of rooftop solar. He said helping to build a biogas market may lead
to lower prices as has happened with renewable electricity, and this program signals a move
away from the GHG emissions associated with natural gas usage.
Utilities Advisory Commission Minutes Approved on: Page 7 of 11
Commissioner Schwartz asked if staff has done an analysis of where the electricity comes from
with electric used for heating, positing that additional electric load may cause the use of more
gas to power electric generation. Dailey answered that this proposal has nothing to do with
electric generation or increased electric usage.
Commissioner Ballantine asked if we electrify, would we increase our GHG footprint without
realizing it. Ratchye said that a discussion about electrification will happen at a later date.
ACTION:
Vice Chair Danaher made a motion that the UAC recommend that Council approve a Carbon
Neutral Gas Plan to achieve a carbon-neutral gas supply portfolio starting in Fiscal Year 2018
with a rate impact not to exceed ten cents per them; and terminate the PaloAltoGreen Gas
Program established by Resolution 9405. Commissioner Forssell seconded the motion. The
motion passed (6-1) with Chair Cook, Vice Chair Danaher and Commissioners Danaher, Forssell,
Johnston, and Trumbull voting yes and Commissioner Schwartz voting no.
ITEM 3. DISCUSSION: Discussion and Status Update Concerning City Initiatives on Fiber-to-the
Premises and Wireless Network Issues, Including Work Related to Potential Google fiber and
AT&T GigaPower Deployments and Co-Build Opportunities in Palo Alto
Chief information Officer Jonathan Reichental, Information Technology Senior Technologist
Todd Henderson and Utilities Senior Management Analyst Jim Fleming provided a presentation
summarizing the written report. The presentation included updates regarding the history of
the dark fiber optic backbone network, the history of previous fiber-to-the-premises initiatives,
wireless plans, the status of Google Fiber and AT&T GigaPower, and a progress report on the
various City Council Motions from the September 28, 2015 and November 30, 2015 Council
meetings related to various fiber and wireless initiatives.
Public Comment
Jeff Hoel said he previously provided comments to the Council and UAC in the writing after the
Council’s August 16, 2016 Policy and Services Committee meeting, which included an update
about the above-noted items and the staff presentation at that meeting. Commissioners can
refer to those comments. He added that Google Fiber’s current status is an example of why the
City should not depend on the private sector to do our fiber. It should be municipally done. He
said at the August 16 2016 Policy and Services Committee meeting, Jonathan Reichental stated
that a network should be “open access.” He does not disagree with open access in principle,
but Google Fiber never promised open access. He provided an example of a municipal fiber
network being built in Ammon, Idaho where residents will pay a significant amount of money
upfront for fiber service. The City of Ammon studied this model in 2012 , but it was considered
to be infeasible; however, they decided to go ahead with the project anyway. Ammon’s model
will allow any Internet Service Provider (ISP) who wants to provide services to connect with the
system for only the same amount of cost that the user would pay to connect to get the services.
This would be a good deal for the ISPs, who have traditionally been plagued by problems
providing services over open access networks and as a result did not show up.
Herb Borock referenced what Jeff Hoel spoke about regarding Google Fiber’s description of
what their fiber system would be. There were originally two messages from Google. The initial
Utilities Advisory Commission Minutes Approved on: Page 8 of 11
message was that any ISP could be on the system, but then the message was changed to an
approach where consumers could buy any services, but Google Fiber would be the only ISP
available on the system. He also referenced the discussion between Commissioner Forssell and
Jonathan Reichental about Google Fiber’s decision to pause their fiber build in Silicon Valley.
He stated that Google has already provided the City of San Jose with a building schedule. If
anyone is interested in how much time the build will take, in addition to the number of work
crews deployed and various build schedules, you can go to San Jose’s website and look at the
May 24, 2016 City Council agenda packet. The staff report stated that Google has contracted
with Ericsson to both design and build the fiber system.
Commissioner Ballantine recalled that former UAC Chair Jonathan Foster made a proposal
about a year ago to ask the Council to somehow put fiber to a vote. At a subsequent meeting, a
staff update stated that AT&T had reviewed their GigaPower construction plans for the cabinets
and the total was 10. He asked if that was wrong or was it actually just the two that have been
approved. Reichental recalled it was two. Commissioner Ballantine asked what happened to
the other 8. Reichental said that there will be another set of cabinets after the first two and
then another set after that. Commissioner Ballantine said that we’ve made progress, but less
than what we want and Jeff Hoel’s past comments are coming to pass and his general thoughts
are that we should talk to Council if this is something we need to do and let’s all vote as
opposed to waiting for it; it doesn’t appear it’s going to happen with Google and AT&T may
take a number of years.
Commissioner Schwartz asked if in staff’s conversations with Google Fiber whether there’s a
sense that the cost to build fiber-to-the-premises doesn’t make sense anymore and what
prompted this change to wireless. Reichental replied that from what has been written in the
newspapers, it can be summarized in three components: 1) fiber builds are more expensive
than anticipated, 2) building fiber is harder to do, and 3) its taking longer than expected.
Commissioner Schwartz asked if these components would be the case if we did it ourselves.
Fleming said that building FTTP is very expensive because it would be a competitive “overbuild”
market, but the City has an advantage, because it would have easier access to utility poles
which is a barrier for some private builders.
Vice Chair Danaher said he would welcome a chance for a creative discussion, which may
include creating incentives for AT&T to move faster. Fleming said that the public -private model
is also worth looking at because each party assumes some portion of the risk in building and
operating the network.
Commissioner Forssell asked what does “overbuild” mean. Fleming replied that an overbuild
occurs when a private fiber builder or a municipal builder constructs a new network that is built
next to the existing telco and cable TV networks.
Commissioner Forssell asked what the difference is between a co-build and a public-private
partnership. Fleming replied that a co-build model is a unique approach that the Council asked
staff to explore with Google Fiber and AT&T. A co-build could involve Google or AT&T and the
City cooperating and sharing costs to build two networks side by side. A public-private
partnership is a model where the City and a private firm would build one network under an
agreement. Commissioner Forssell asked if the third party would be inviting competition into
their own investment if a co-build occurred. Fleming said that interpretation hit the nail on the
Utilities Advisory Commission Minutes Approved on: Page 9 of 11
head. Commissioner Forssell also asked if a public-private partnership would involve the City
and the partner building and operating together and reaping the financial benefits? Fleming
replied yes.
Commissioner Forssell asked who regulates this industry. Fleming said it ’s regulated by the FCC
and the CPUC in terms of franchising for video services under the Digital Infrastructure and
Video Competition Act of 2006.
Commissioner Johnston says he understands that Google Fiber has paused, AT&T is moving
slowly and we’ve received responses to the RFI as a potential alternative. Commissioner
Johnston asked when the evaluation of the RFI responses will be completed. Fleming replied
that it should be done in the next 60 days, and added there were few responses. Fleming
added that a possible reason for the lack of responses may be due to the uncertainly about
whether Google Fiber will enter the Palo Alto market. Commissioner Johnston said he is in
agreement with Commissioner Ballantine that he would like the City to move forward even
though we’re stopped for now.
Vice Chair Danaher said there’s been speculation in the press that Google Fiber was not serious
and they just wanted to prompt the others to improve their existing networks. This is what Jeff
Hoel said at least a year ago and we should aggressively explore other options.
Commissioner Schwartz said she ran into the Ammon, Idaho fiber project manager at a
conference and discussed Palo Alto’s situation. The project manager said their plan will work in
Ammon because there are no incumbents and they’re underserved. The project manager said
he wouldn’t recommend doing it (i.e. FTTP) in Palo Alto because there are so many incumbents.
Commissioner Schwartz said that Palo Alto has access to broadband whether or not you like the
prices and the providers. Nobody is unserved. Applications that require access to fiber don’t
really exist yet except for some corporations developing customized apps and they can buy
access to fiber.
Commissioner Schwartz said that in addition to Vice Chair Danaher’s recommendation to
incentivize AT&T, the City should explore if there’s a way to use some of the fiber reserve to
support someone developing an application and bringing fiber to them. Perhaps set aside $2
million for a grant program.
Commissioners Ballantine and Schwartz discussed how video based apps get bogged down at
certain times of the day on the existing networks. Commissioner Ballantine said it’s not
necessarily the amount of bandwidth in his house or how fast his computer is, but the
bandwidth provided to his neighborhood may not be sufficient at certain points of the day such
as 7:00 pm. Commissioner Schwartz said she has experimented with using Apple TV rather
than her computer to solve the problem if the goal is to use entertainment apps so they don’t
get bogged down; a $70 million FTTP overbuild might be overkill to solve the problem.
Vice Chair Danaher said he agreed that the price estimate is very high. Jeff Hoel said it may
actually be lower or in practicality may be higher; it’s a deep concern. He thinks it will generate
a lot of new applications and new businesses. If you build it first and then things come, it’s
good public policy for the City. This is one case where staff was more on the trailing edge than
some people on the commission last year who were more on the leading edge; however,
Utilities Advisory Commission Minutes Approved on: Page 10 of 11
spending $70 million is a lot and we ought to look for ways, and one way to incent it may be to
tell AT&T we'll subsidize Palo Alto people who sign up to make sure they get enough takers in
the first year.
Chair Cook said we've had a good discussion. Thank you very much for the presentation. It's
just a discussion item.
ACTION
None.
ITEM 4. ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt a Resolution Amending Utility Gas Rate Schedules G-1, G-1-G, G-2,
G-2-G, G-3, G-3-G, G-10, and G-10-G to Include a Separate-Transportation Charge as a Discrete
Pass-Through Component
Rates Manager Eric Keniston summarized the written report. He said that Palo Alto pays Pacific
Gas and Electric (PG&E) to transport natural gas to Palo Alto, as stated in PG&E rate schedu le G-
WSL. Changes to that schedule are dictated by the California Public Utilities Commission (CPUC)
and their proceedings. Staff does not know when the schedule will change or what the final
change will be, and proceedings have been subject to substantial delays. Staff requested to
make the G-WSL charges a pass-through charge on customer bills. The initial charge would be
based on the August 2016 G-WSL rate and be subtracted from the existing distribution charge.
The effect would be revenue neutral for all but the City’s CNG facility (G-10), which would see a
small initial increase estimated at $2400 per year.
The UAC did not have any questions related to this item.
ACTION:
Vice Chair Danaher made a motion that the UAC recommend that Council adopt a resolution to
amend Utility Gas Rate Schedules G-1, G-1-G, G-2, G-2-G, G-3, G-3-G, G-10, and G-10-G, as
proposed, to separately identify as a pass-through rate component, a Transportation Charge.
Commissioner Ballantine seconded the motion. The motion passed unanimously (7-0) with
Chair Cook, Vice Chair Danaher and Commissioners Danaher, Forssell, Johnston, Schwartz and
Trumbull voting yes.
ITEM 5. DISCUSSION: Update and Discussion on Impacts of Statewide Drought on Water and
Hydroelectric Supplies
Chair Cook indicated that these monthly updates can be discontinued, but that any relevant
updates can be provided in the Utilities Director’s Report or in the quarterly reports.
Assistant Director Jane Ratchye indicated that there is not much new information since the last
meeting on the water supply situation. She said that there has been no new precipitation at
Hetch Hetchy since late May and that the water year will end up with above average
precipitation. Water storage has also recovered to a healthy level as we await the winter rainy
season. The Pacific Institute drought monitor for the end of July showed that it was much drier
in the south of California than in the central or northern sections. Ratchye also indicated that
FY 2017 is expected to be a dry year for hydroelectric supplies, but not a critically dry year so
that increased costs due to the drought are moderated somewhat.
Utilities Advisory Commission Minutes Approved on: Page 11 of 11
ITEM 6. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting
Cook: UAC subcommittees for relevant topics could be discussed in the next meeting
Commissioner Trumbull indicated that he wanted to discuss things that Council has already
taken up such as electrification, which should be more thoroughly discussed.
Chair Cook noted that resiliency discussions have some overlap with a second transmission
connection.
Commissioner Ballantine indicated that the microgrids topic that is scheduled for the next UAC
meeting is a good time to discuss the general topic of resiliency.
Commissioner Schwartz asked about the adoption of electric vehicles (EVs) and whether that
could be discussed when storage is discussed. She also said that, due to her husband’s work on
storage, whether she might have a conflict when that topic is discussed.
Senior Deputy City Attorney Jessica Mullan said that conflicts are driven by an individual’s
positions and the way in which items are agendized and it is best for commissioners with any
potentials conflicts to discuss these items with the City Attorney’s Office.
Interim Director Ed Shikada indicated that the Sustainability Implementation Plans also have a
resiliency aspect.
ACTION:
None.
Meeting adjourned at 9:20 p.m.
Respectfully submitted,
Marites Ward
City of Palo Alto Utilities
Page 1 of 6
1
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: October 5, 2016
SUBJECT: Recommendation that the Utilities Advisory Commission Recommend that
Council Adopt a Net Energy Metering (NEM) Transition Policy
______________________________________________________________________________
Recommendation
Staff requests that the Utilities Advisory Commission (UAC) recommend that Council adopt
the following NEM Transition Policy for eligible NEM customers:
1. Establish a 20-year transition period from the time of system interconnection through
which NEM customers will remain eligible for net metering and related terms and
conditions described in California Public Utilities Code Section 2827, and
2. Allow NEM customers to expand their systems by any amount, and adjust the
transition period by a ratio of the expanded and original system sizes, according to
the following formula: New Remaining NEM Term = Original system’s remaining NEM
term X (Original system size in kW / New system size in kW).
Executive Summary
Net energy metering (NEM) is a billing mechanism designed to promote the installation of
renewable distributed generation by allowing customers to be compensated at the full retail
rate for electricity generated by their on-site systems, such as solar photovoltaic (solar PV)
systems. State law requires all electric utilities to offer NEM to customers with eligible
renewable distributed generation up to a maximum cap, or “NEM cap”. Council adopted a
NEM Successor Program to be implemented when the NEM cap is reached, but requested
that staff evaluate options and a recommendation for the NEM Transition Policy and change
the method for calculating the NEM cap.
The proposed NEM Transition Policy provides a fair way for customers under NEM to expand
their systems and remain under NEM for a reasonable period of time before transitioning to
the NEM Successor Program. Staff recalculated the NEM cap using the Council-approved
method and revised the NEM cap to 10.8 MW, a 13.3% increase from the prior NEM cap of
9.5 MW.
Page 2 of 6
Background
Council Action on NEM Successor Program
The UAC reviewed, and recommended that Council approve, the proposed NEM Successor
Program and NEM Transition Policy at its April 2016 meeting. The Finance Committee acted
likewise at its May 17, 2016 meeting. Council reviewed the proposal at its August 22, 2016
meeting (Staff Report 7150). The Council voted unanimously (8-0 with Council Member Filseth
absent) to:
1. Adopt a resolution:
a. Adopting a Net Energy Metering (NEM) Successor Rate, E -EEC-1 (“Export
Electricity Compensation”); and
b. Amending Utilities Rule and Regulation 2 (“Definitions and Abbreviations”) and
29 (“Net Energy Metering and Interconnection”); and
2. Direct staff to:
a. Return to Council within four months with options and a recommendatio n for
the NEM Transition Policy
b. Return to Council within one year of reaching the cap from the expiring NEM
program with a report describing other NEM programs in California , with a
comparison to the Palo Alto program including the effectiveness of Palo Alto’s
program in spurring local residential solar options; and
c. Change the method for calculating the NEM cap to five percent of the customer
class non-coincident peak.
NEM Cap
The California Public Utilities Code requires all electric utilities to offer NEM to eligible
customers with renewable distributed generation, up to a cap . Currently, the California Public
Utilities Code affords publicly-owned utilities (POUs), like Palo Alto, with flexibility to define the
City’s 5% NEM cap. Section 2827(c)(4)(A) of the California Public Utilities Code specifies that
POUs must offer NEM until “combined total peak demand” of NEM customers exceeds 5% of
“aggregate customer peak demand” of the electric utility. The statute is silent as to how to
define “aggregate customer peak demand” for POUs, leaving matters such as the best method
for calculating aggregate customer peak demand, or what reference year to use to the City to
decide.1
In October 2015 Council formally adopted a resolution setting a NEM cap calculation
methodology which resulted in a 9.5 MW cap for Palo Alto (Staff Report 6139), which is equal
to 5% of the City’s 2006 system peak demand for electricity of 190 MW. The reference year
(2006) was utilized since California Senate Bill 1 (SB1) took effect on January 1, 2007, which set
1 By contrast, the statute and the CPUC afford Investor Owned Utilities (IOUs) with no discretion for how to
calculate “aggregate customer peak demand.” The CPUC approved a decision requiring the large IOUs to define
aggregate customer peak demand as the sum of individual customers’ peak demands, or so -called non-coincident
peak demands. The Public Utilities Code was later modified to further clarify this definition for the IOUs (Cal. Public
Utilities Code, §2827 (c)(4)(B)).
Page 3 of 6
a statewide goal of deploying 3,000 MW of new solar PV systems by 2017 and concurrently
modified the California Public Utilities Code to raise the NEM cap from 0.5% to 2.5%.2
On August 22, 2016, Council directed staff to change the methodology to determine the City’s
NEM cap to be 5% of the customer class non-coincident peak. The sum of the customer class
non-coincident peaks is estimated to be about 215 MW, so the new methodology will revise the
City’s new NEM cap to 10.8 MW, or 5% of 215.6 MW, as shown below.
Rate: Customer Class Non-Coincident Peak in 2006 (MW)
E-1: Residential 36.8
E-2: Small Non-residential 18.5
E-4: Medium Non-residential 89.2
E-7: Large Non-residential 66.2
E-18: City Accounts 3.8
Street/Traffic Lights 1.1
Total 215.6
Discussion
Proposed NEM Transition Policy
Transition Period
In March 2014, the CPUC ruled that the investor-owned utilities’ (IOU’s) existing NEM
customers (and all those who install eligible systems within each IOU’s respective NEM cap) can
remain in NEM through a 20-year transition period from the date of interconnection. The
length of the transition period was determined in part based on an assessment of ex pected
useful life, as indicated by module warranties, power purchase agreements, and third -party
financing agreements. The Sacramento Municipal Utility District (SMUD), the San Francisco
Public Utilities Commission (SFPUC) and the Modesto Irrigation District (MID) have also
proposed that NEM customers remain eligible for NEM for 20 years from the date of initial
system interconnection.
To help promote regulatory certainty and transparency for existing NEM customers who have
invested in solar PV systems and for solar developers operating in Palo Alto, staff proposes that
existing NEM customers and all eligible customers within the NEM cap in CPAU service territory
remain eligible for NEM through a 20-year transition period.
System Expansions
Some customers who install systems within the NEM cap may wish to expand their systems
after the NEM cap has been reached. Allowing system expansion up to a given threshold is
broadly in-line with system expansion policies established in the California IOU service
territories and Turlock Irrigation District, as shown in the table below. Adopting a system
2 The NEM cap was later raised from 2.5% to the current 5% in 2010 by Assembly Bill 510.
Page 4 of 6
expansion policy would allow a customer to expand their system or to replace panels that failed
prematurely with higher efficiency panels while still remaining eligible for NEM.
Policies of California utilities for system expansions aft er the NEM cap has been reached
Utility Description of System Expansion Policy
IOUs:
PG&E,
SDG&E, So
Cal Edison
Customers may increase the system size up to 10% of the original system size and
remain eligible for NEM. Customers who wish to expand their systems more may
either 1) meter the added capacity separately under the NEM successor tariff, or
2) elect for the entire system to take service under the NEM successor tariff.
Turlock
Irrigation
District
Residential customers whose original system size is less than 10 kW may increase
their system up to 11 kW total. Residential customers with an original system size
of 10 kW or greater and non-residential customers may increase their system by
a maximum of 10%. For expansions beyond these thresholds, the customer must
transition the entire system capacity to the NEM successor rate.
Imperial
Irrigation
District
No existing policy for system expansions.
Modesto
Irrigation
District
Proposal: PV systems operating under NEM that want to add panels must reapply
under the NEM successor for the total system.
City of
Lompoc
No existing policy for system expansions.
Staff originally proposed that if the existing NEM system is modified or repaired after the NEM
cap is reached, the customer will remain eligible for NEM as long as the system does not
increase by more than 10% of the original system size. If the system mo dification or expansion
results in an increase of over 10% of the original system size, the customer would be required
to transition to the NEM successor program for the entire system capacity.
A community stakeholder, Carbon Free Palo Alto, proposed a formula for system expansions
that would allow customers to expand their systems and remain under NEM for a term that is
proportional to the original and expanded system sizes. The formula for the modified transition
period (“Remaining NEM term”) for an expanded system is as follows:
New remaining NEM Term = Original system’s remaining NEM term x (Original
system size in kW/ New system size in kW).
For example, if a 4 KW system, which was interconnected for 5 years (thus, had 15 years
remaining under NEM), was expanded by 2 KW to 6 KW, the new NEM transition period would
be 10 years for the entire expanded 6 KW system using the formula as follows:
New remaining NEM term = 15 years X (4 KW/6 KW) = 15 years X 2/3 = 10 years
Page 5 of 6
This formula results in the same amount of NEM-eligible “capacity-years” before and after the
expansion.3
Carbon Free Palo Alto argues that limiting the NEM transition period for expansions to only 10%
is not reasonable as customers are unlikely to make such small system additions. Instead, they
may seek to upsize their systems by at least 25% due to additional electricity needs due to the
addition of an electric vehicle or electrification of a gas-using appliance.
Options for system expansion policies are described in the table below.
Alternative policies for system expansions after the NEM cap has been reached
Alternative System Expansion Policy Discussion
Original
Staff
Proposal
Customers remain eligible for NEM
for system expansions within 10% of
the original system size using the
original system interconnection date
for the transition period. Larger
system expansions require the entire
system capacity to be transitioned to
the NEM successor rate.
This policy accommodates small
expansions that are driven by
replacement of damaged panels or those
that failed prematurely. Since newer
panels may be larger, or more efficient, a
simple panel-for-panel replacement will
likely increase system size.
Carbon
Free Palo
Alto
Proposal
Additions of any size are acceptable,
but the expanded system transition
period is shortened pro-rata by the
ratio of the original system size and
the expanded system size.
This policy allows all system expansions
to remain eligible for NEM, but shortens
the transition period by the fraction that
the system is expanded. This would
accommodate system expansions that
are sought to meet increased electric
usage.
Allow
expansions
of up to
25%
Customers remain eligible for NEM
for system expansions within 25% of
the original system size. Larger
system expansions require the entire
system capacity to be transitioned to
the NEM successor rate.
This policy is similar to the original staff
proposal above, but allows larger
expansions. This policy is not
recommended since it could allow
significant additions to remain NEM-
eligible, pushing the installed NEM
capacity far over the NEM cap.
3 Before the expansion, the 4 KW system had 15 years left in NEM, or 60 kW-years. After the expansion, the 6 kW
system has 10 years left in NEM, or (again) 60 kW-years.
Alternative System Expansion Policy Discussion
No For any system expansions, the This policy does not allow expansions of
Expansion customer must transition the entire any kind to remain under NEM so that all
system capacity to the NEM expanded systems would be transitioned
successor rate. to the NEM successor. This policy is not
recommended as repairing failed panels
or even minor system expansions would
not be accommodated.
Expansion System expansion capacity would be This policy is not recommended as it
only under under the NEM Successor while the would be a large metering and
NEM original system capacity would administrative burden to accommodate
Successor remain under NEM for the transition both NEM and the NEM successor
period (20 years from the date of program and rates for the combined
interconnection). system.
Staff Recommendation
Staff considered the options for how to treat solar PV system expansion in the City's NEM
Transition Policy. Staff's original proposal was targeted at small additions that were likely
prompted by the need to replace defective panels and, thus, limited the chance that significant
additional solar capacity would be added to the NEM program after the NEM cap was reached.
The proposal from Carbon Free Palo Alto is a creative and fair way to allow system expansions
prompted by customers who desire to add more solar PV capacity to their systems while
keeping the overall capacity under the NEM cap. Thus, staff recommends the Carbon Free Palo
Alto proposal to pro-rate the transition period for an expanded system according the formula:
New remaining NEM Term = Original system's remaining NEM term x (Original
system size in kW I New system size in kW).
RESOURCE IMPACT
The proposed NEM Transition Policy and expansion of the NEM cap support Strategy #2 of the
Local Solar Plan, to "develop proper policies, incentives, price signals and rates to encourage
solar installation".
ENVIRONMENTAL IMPACT
The UAC's review of the proposed NEM Transition Policy does not meet the California
Environmental Quality Act's (CEQA) definition of "project" under California Public Resources
Code Sec. 21065, thus no environmental review is required.
PREPARED BY: ~chy ~sistan~ Director, Resource Management
DEPARTMENT HEAD: ~
Ed Shikada, Interim Director of Utilities
Page 6of6
Page 1 of 5
2
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: October 5, 2016
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Approve Design Guidelines for the 2017 Gas Cost of
Service Analysis
REQUEST
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council
approve the Design Guidelines for the 2017 Gas Cost of Service Analysis (Attachment A).
EXECUTIVE SUMMARY
Gas rates were last adjusted when an 8% rate increase went into effect on July 1, 2016. Staff
intends to complete a gas rate cost of service analysis (COSA) in FY 2017 in advance of a rate
adjustment on July 1, 2017. The primary goal of the COSA will be to review the allocation of
costs to customer classes and the gas rate design to ensure customers are charged according to
the cost to serve them. This report discusses the existing rate design, gives an overview of the
issues to be addressed in the COSA analysis, and presents the proposed COSA design guidelines
to guide staff and the consultant in completing the Gas COSA.
BACKGROUND
Traditionally, utilities use a COSA to allocate costs among customer classes and to design rates.
COSAs gained a more important role for California publicly-owned utilities after the passage of
Proposition 26 (2010). Proposition 26 added provisions to the State Constitution essentially
defining every local government fee or charge as a tax, requiring voter approval, unless one of
seven exceptions applies. Municipal gas rates that do not exceed the reasonable costs to the
local government of providing gas service are one exception from the constitutional definition
of a tax, and its voter approval requirements.
The FY 2017 Gas Utility Financial Plan (Staff Report 6858) projected the need for a 9% rate
increase on July 1, 2017. The current rates, which were last changed on July 1, 2016, are based
on a COSA performed in 2012. Current rates include a fixed monthly service charge for each
customer group and volumetric (per therm) rates for all customers. The volumetric component
Page 2 of 5
of residential gas rates (Gas Rate Schedule G-1) consists of two tiers of inclining block rates
(rates that increase with consumption).
DISCUSSION
The following sections provide a review of the current rate structure, a discussion of rate design
issues affecting the utility, and the proposed set of rate design guidelines to guide the COSA.
Summary of Existing Rate Structure
On July 1, 2012 CPAU restructured its gas rates so that the commodity component varied
monthly to match changes in gas market prices. In addition, monthly service charges were
increased to recover the cost of providing gas service to customers. In January 2015, the
Council adopted a new rate component to collect the costs of purchasing allowances to comply
with the State’s cap-and-trade program. This component will change depending on the cost of
allowances and gas demand. Table 1, below, summarizes the current rates for all customer
classes.
Table 1: Current Gas Rates
Rate Component Units
G-1
(Residential)
G-2 (Small
Commercial)
G-3 (Large
Commercial)
G-10
(CNG)
Last
Changed
Service Charge $/month 10.32 78.23 377.43 52.93 7/1/2016
Distribution (Tier 1) $/therm 0.5021 0.6855 0.6775 0.0963 7/1/2016
Distribution (Tier 2) $/therm 1.0407 N/A N/A N/A 7/1/2016
Commodity $/therm 0.3433
(Sept. 2016)
0.3433
(Sept. 2016)
0.3433
(Sept. 2016)
0.3433
(Sept. 2016)
(varies
monthly)1
Cap-and-Trade
Compliance $/therm 0.016
(Sept. 2016)
0.016
(Sept. 2016)
0.016
(Sept. 2016)
0.016
(Sept. 2016)
(varies with
actual costs)
Total Volumetric
Rate (Sept. 2016) $/therm Tier 1: 0.8614
Tier 2: 1.4000 1.0448 1.0368 0.4556
Tier 1 amount (for G-1, residential customers):
Winter Therms/day 2 N/A N/A N/A 7/1/2012
Summer Therms/day 0.667 N/A N/A N/A 7/1/2012
On October 17, 2016, Council will consider amending gas rates adding a separate and revenue-
neutral transportation charge that will pass through the costs PG&E charges CPAU for gas
transportation 2. If approved, the initial Transportation Charge will be $0.1088/therm with the
Distribution Charges being reduced a like amount.
Rate Design Issues
The Gas Utility’s rates are evaluated and implemented based on the utility’s cost to serve its
customers. The Gas Utility’s current rates are based on the methodology from the April 2012
1 For historic commodity rates, see: http://www.cityofpaloalto.org/civicax/filebank/documents/30399
2 The UAC supported this proposal at its August 31, 2016 meeting. See:
https://www.cityofpaloalto.org/civicax/filebank/documents/53652
Page 3 of 5
Gas Utility Cost of Service Study completed by Utility Financial Solutions 3. Staff has identified
rate design issues to address including:
The need to update the City’s Gas COSA. The current COSA was completed over 4 years
ago and best practice is to prepare a new COSA about every five years, or when there
are significant changes in the utility’s costs, customer base, or other factors.
Carbon reduction goals. The City’s Carbon Neutral electric supply portfolio has led some
customers to consider electrifying the space and water heating systems in their homes,
or replacing gas-using appliances with electric ones. The gas rate structure has an
impact on these decisions.
Rate Design Guidelines
In the past, the UAC and Council have expressed concern about having limited ability to make
changes to proposed rate structures once a COSA is completed. Therefore, staff has committed
to having policy discussions with the UAC and Council prior to embarking on a COSA. Staff is
proposing a set of rate design guidelines (Attachment A) to guide the development of the next
Gas COSA. The proposed guidelines are described below:
Guideline 1. Rates must be based on the cost of service.
Guideline 2. Maximize the volumetric rate and minimize the fixed charges, if feasible.
Guideline 3. All existing rates should be reviewed for applicability in the COSA.
Guideline 4. The COSA should consider the impact of rate designs on electrification.
Guideline 5. The effect of proposed rate design changes on low income customers should be
considered.
Guideline 1: Rates to be based on the cost of service
The goal of a COSA is to identify the costs associated with serving each customer class and the
rates required to recover those costs. Historically, gas utilities have been able to make some
adjustments to COSA-recommended rates to achieve environmental or social objectives. After
Prop. 26, such rates cannot be structured solely to achieve policy objectives unless they are also
cost-based, absent voter approval. The COSA has become an important tool for demonstrating
that utility rates are based on the cost of service. As a result, this guideline must be the
overriding one for the COSA.
Guideline 2: Maximize the volumetric rate and minimize the fixed charges, if feasible
Staff anticipates retaining the existing rate structure—consisting of a volumetric component
and a fixed monthly charge. To encourage efficient use of resources and to maximize the
incentive to convert gas-using appliances to electric-using appliances, the volumetric
component should be maximized to the extent feasible while still complying with the cost of
service requirement of Proposition 26 (See Guideline 1).
3 Staff Report 2812: http://www.cityofpaloalto.org/civicax/filebank/documents/41839
Page 4 of 5
Guideline 3: Evaluation of all existing rate schedules for continuation, consolidation, or
redefinition
Staff recommends evaluating all existing rate schedules to determine whether they should be
continued or redefined. The main focus of this review will be the customer class definitions for
non-residential customers. The consultant will evaluate whether the boundaries between small
commercial and master-metered residential customers (G-2) and large commercial customers
(G-3) should be redefined to more accurately reflect the customer profiles of each group.
Guideline 4: Impact on electrification
To achieve the City’s carbon reduction goals, electrification is required. Some customers are
considering greater use of electricity in their homes by replacing natural gas fueled water and
space heaters with efficient heat pump water and space heaters. These customers are likely to
have significantly different gas load profiles from the average residential customer. Staff
recommends evaluating whether the cost to serve these customers differs from other
residential customers. If so, adjusting the pricing structure applicable to these customers may
be appropriate.
Guideline 5: Impact on low income customers
Changes in rate design can have different impacts on customers who use different amounts of
energy. Low-income customers have lower gas usage than other customers, on average. Staff
intends to evaluate the impact of any recommended rate design changes on low-income
consumers and may recommend mitigation of those impacts if necessary.
NEXT STEPS
After receiving the UAC’s recommendation, staff will take the COSA design guidelines to the
Finance Committee, followed by consideration by the City Council. The COSA is expected to be
completed by the spring of 2017 so that updated rates can be adopted as part of the FY 2018
budget process to be effective on July 1, 2017.
RESOURCE IMPACT
The work associated with this project will be absorbed using existing staff and contract budgets.
The new rates adopted as a result will be designed to generate adequate sales revenue to fund
the gas utility’s operations in FY 2017. For FY 2017, the utility is projected to need roughly 9%
more sales revenue ($3.8 million) than is generated by current rates. Expenses exceed revenues
currently, and reserves are being used to moderate customer impacts as rates are brought to
parity. Costs in general are projected to increase due to inflation, and continued work on cross-
bore inspections requires additional short-term funding. For more detail on these projections
see the proposed FY 2017 Gas Utility Financial Plan (Staff Report 6858).
POLICY IMPLICATIONS
The process of adopting these design guidelines provides the UAC and Council an opportunity
to provide policy guidance to staff before work begins on the COSA. Once a COSA is complete, it
can be difficult to modify the resulting rate design without reviewing and possibly amending
the analysis.
ENVIRONMENTAL REVIEW
Adoption of the Design Guidelines for the 2017 Gas Cost of Service Analysis does not meet the
definition of a project, under Public Resources Code Section 21065 and CEOA Guidelines
Section 15378(b)(S), because it is an administrative governmental activity which will not cause a
direct or indirect physical change in the environment, thus no environmental review is required.
ATTACHMENT
A. Proposed Design Guidelines for the 2017 Gas Cost of Service Analysis
ERIC KENISTON, Senior Resource Planner C:t;;. -?L._ ~c~t Director, Resource Management
PREPARED BY:
REVIEWED BY:
APPROVED BY:
EDSHIKADA
Interim Director of Utilities
Page 5 of 5
Attachment A
Design Guidelines for the Gas Utility Cost of Service Analysis
1. Rates must be based on the cost to serve customers. This is the overriding principle for the
cost of service analysis (COSA); all other rate design considerations are subsidiary to this
basic premise.
2. For this cost of service study, and to the extent feasible, the revenue from volumetric
energy charges should be maximized and the revenue from the fixed charge should be
minimized to provide the maximum incentive for efficiency and electrification, the
conversion of gas-using appliances to electricity-using appliances.
3. The COSA should involve a review of all existing rate schedules for applicability in the COSA.
4. The COSA should evaluate the impact of rate designs on the economics of electrification.
5. The impact of any proposed changes on low income customers should be evaluated
1
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: OCTOBER 5, 2016
SUBJECT: Discussion of Energy Storage and Microgrid Applications in Palo Alto
This report is provided for background to elicit input from the Commission on staff’s
preliminary findings to not set energy storage goals and to explore pilot scale storage programs.
A final recommendation on whether to establish a goal for storage will be brought back to the
Commission in early 2017. No action is required at this time.
EXECUTIVE SUMMARY
Currently, storage systems are most commonly installed by customers either seeking a higher
level of electricity supply reliability or those interested in storing their generated solar
electricity onsite. Energy storage systems coupled with solar photovoltaic (PV) systems are
becoming increasingly viable technologically and economically. These integrated PV and battery
systems sometimes have the capability to maintain electric supply at customer homes or
businesses in the event of a power outage,1 or increasing the self-consumption of solar
generated onsite. Combined PV and storage systems that can island from the electric grid and
function alone are sometimes called microgrids2 or nanogrids3. Storage systems alone, without
PV, can also be configured to reduce customer electric utility bills by storing electricity when
prices are low and using stored electricity when prices are high. In addition to the small
customer-sited storage systems, large utility-scale storage systems are also becoming more
prevalent in California as a result of regulatory mandates and market changes.
1 PV systems that are not appropriately coupled with energy storage systems cannot produce energy in the event
of an electric grid outage, except in very limited circumstances. Hence such systems cannot enhance customers’
electric reliability.
2 A microgrid is defined as, “a group of interconnected electrical (customer) loads and distributed energy resources
within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. A
microgrid can connect and disconnect from the grid to enable it to operate in both grid-connected or island-
mode.”
3 A microgrid which can island from the electrical grid and operates at an individual building or individual customer
level is commonly called a “nanogrid”. Because of its simplicity, a nanogrid can be developed without the need for
active facilitation by an electric utility.
2
While battery systems and solar PV costs have declined considerably the past three years, cost-
effective storage systems are still some years away, particularly in Palo Alto. The primary
challenges to cost effectiveness in Palo Alto are the relatively low electric retail rates, the small
retail rate differential between on-peak and off-peak periods, and a robust distribution grid
providing highly reliable electricity service. Transmission grid-level storage applications are also
not currently cost effective for the City of Palo Alto Utilities (CPAU). However, CPAU has
incorporated the option into the City’s recent purchase power agreements to site storage
systems at the PV project sites in case the economics for storage at the transmission grid level
become favorable in the future.
In accordance with State law, the City must evaluate storage options and determine whether or
not to establish a goal for energy storage every three years. When last evaluated in 2014, the
City declined to establish such a goal since there were no cost-effective opportunities. There
still appears to be no cost-effective storage options, but staff is evaluating a pilot-scale utility
rebate program for energy storage systems installed at customer premises4. A small storage
pilot program would enable CPAU to gain first-hand experience with storage technologies and
to position itself for widespread adoption if and when they become economically favorable in
the future.
Staff will return to the UAC and Council in early 2017 with a recommendation on whether to
establish a goal for energy storage and whether to undertake any pilot programs related to
storage. This report is meant to provide a background for discussion prior to staff’s
development of these recommendations.
BACKGROUND
In February 2014, after examining a detailed analysis from staff, the City Council found a lack of
cost-effective energy storage applications in Palo Alto (Staff Report 4384). This analysis and
determination was prompted by State law under AB 2514 that required the governing board of
each publicly-owned utility (POU) such as CPAU to “determine appropriate targets, if any, for
the utility to procure viable and cost-effective energy storage systems.” The law also required
“reevaluation of energy storage target determinations not less than every three years.”
The findings and recommendations from the 2014 analysis by Palo Alto were:
A. Do not establish an energy storage systems procurement target for Palo Alto.
This recommendation was made because storage systems were not cost effective from a
societal and utility perspective in Palo Alto.
4 A pilot program with a total budget approx. $250,000 is being evaluated. This will enable CPAU to fund a 50% cost
matching rebate of up to $500/kWh for storage cited at customer premises, and made available to the CPAU to
dispatch during ‘Demand Response’ periods. Staff believes that this is a reasonable investment to support the
integration of this nascent technology in the Palo Alto community. Design of such a pilot program, including legal
and regulatory review, will be undertaken by staff in the coming months before bringing a recommendation to the
UAC.
3
B. Utility incentives for energy storage not recommended.
The analysis found that Thermal Energy Storage (TES) and Battery Energy Storage (BES)
systems were the most relevant for applications in Palo Alto. However, customer incentives
were not recommended since at the time neither of these systems was found to be cost
effective from a societal perspective.
C. Encourage commercial customers to consider energy storage where cost effective.
The analysis found that TES and BES could make load shifting strategies cost effective for
Palo Alto commercial electric ratepayers, and recommended that CPAU encourage its
customers to evaluate installing such systems at their premises.
Energy Storage Systems: Definition and Need
The fundamental purpose of energy storage systems is to absorb energy, store it for a period of
time with minimal losses, and then release it. When deployed in the electric power system,
energy storage provides flexibility that facilitates the real-time balance between electricity
supply and demand. Maintaining this balance on an instantaneous basis becomes more
challenging as the share of electricity coming from intermittent renewable energy sources
grows.
Typically this supply-demand balance is achieved by keeping some generating capacity in
reserve (to ensure sufficient supply at all times) and by adjusting the output of fast-responding
resources like hydropower. As the need for fast-responding energy supplies increases, energy
storage systems are expected to play a greater role. Rechargeable batteries are perhaps the
most familiar energy storage technology. Large battery systems can be connected to the
transmission grid to take up excess wind or solar power when demand for electricity is low, and
release it when demand is high. Such transmission grid-tied battery installations also provide
valuable frequency regulation more effectively than a typical thermal electricity generation
facility.
At the other end of the electric grid, customer-sited energy storage can reduce customer costs
and increase system reliability while also benefiting the utility by reducing peak demands on
the distribution system. Both BES and TES systems can reduce peak demands on the electricity
distribution system. TES systems are typically used to shift electricity use of commercial space
cooling units from peak to off-peak periods of the day. Alternatively, a common household
example of a TES storage device is a networked dispatchable electric hot water heater.
Clearly a variety of technologies can be used for energy storage in a wide range of applications
throughout the electric grid. The type, performance and location of an energy storage system
determine the benefits it can provide.
Storage Systems in California
In 2014, among the 37 POUs in California, 7 POUs set storage goals under the AB 2514
requirement. The remaining 30, including Palo Alto, declined to set goals, finding storage to not
be cost effective for their systems at the time. The storage systems planned by POUs were
4
primarily pumped hydro storage, thermal energy storage, and battery energy storage systems
designed for grid service and customer load management service applications. Table 1 lists
these goals and highlights that several of the smaller POUs have set very small goals.
Table 1. Publicly-Owned Utility Energy Storage Goals Set in 2014
Source: CEC, IEPR 2015
While the goals set for POUs were relatively small (~30MW in 2016 and 160 MW in 2020), the
California Public Utilities Commission (CPUC) set a 2,485 MW goal for the investor owned
utilities (IOUs), with procurement commitments to be made by 2020 and systems operational
by 2024. The large volume of storage procurement by IOUs in 2014-15 and current and future
plans for procurements have spurred the storage industry to bring several innovative storage
products to the marketplace, including better product warranties and long-term financing
options.
Microgrid and Nanogrid Applications in Palo Alto
A microgrid is defined as, “a group of interconnected electrical (customer) loads and distributed
energy resources within clearly defined electrical boundaries that acts as a single controllable
entity with respect to the grid. A microgrid can connect and disconnect from the grid to enable
it to operate in both grid-connected or island-mode.”5 A nanogrid is very similar to a microgrid,
except it operates at an individual building or individual customer level. Because of its simplicity
a nanogrid can be developed without the need for active facilitation by an electric utility like
CPAU.
5 https://building-microgrid.lbl.gov/microgrid-definitions
5
There are no microgrid applications in Palo Alto currently nor anticipated in the near future6.
Nanogrids, on the other hand, are common at buildings that are required to have back-up
diesel generation for public health and safety reasons. Examples of nanogrids include hospitals,
emergency operations centers such as police and fire stations, and data centers. As PV and
energy storage costs decline rapidly, integrated PV and battery systems could provide higher
reliability nanogrid services for an expanded group of customers, including residential
applications7.
DISCUSSION
Since 2014, the cost of BES systems has declined and there are a greater number of
commercially available storage products in the market place. While small scale TES systems
have improved, the application of TES in a mild climate like Palo Alto remains limited. The
report analyzes new developments since the 2014 storage assessment and outlines elements of
a distributed energy resource plan, including storage systems, for Palo Alto through 2020. This
analysis reviews these market changes and outlines a course for storage at CPAU within the
broader context of optimizing the value of all distributed energy resources in Palo Alto.
There are a wide variety of energy storage technologies available in the marketplace, and a
number of these are discussed in Attachment A. Among these technologies BES is the most
applicable for Palo Alto and is also the most commercialized with multiple established vendors.
TES systems have only few commercial vendors and such systems have relatively low value in
Palo Alto due to our mild climate (Attachment D).
Application of Energy Storage Systems
Figure 1 illustrates that storage systems can serve 13 applications and benefit three broad
stakeholder groups: Customers, Utilities, and Transmission operators (Independent System
Operators, or ISOs)8. Any of these three stakeholder groups could fund and or derive value
from energy storage systems. The concentric circles in the figure also illustrate that storage can
provide the broadest range of services if located behind the customer meter and the least
number of services if located more centrally on the transmission grid. It is important to keep in
mind for CPAU that the different available value streams depend on the physical location of the
storage system.
6 Microgrids are most common in military bases in the U.S, where the entire base must often have the capability to
function independent of the larger electrical grid. Microgrid applications are also common in large educational
campuses that have onsite generation. In early 2000’s Palo Alto considered siting a 50MW natural gas fueled
electric generator within Palo Alto. Part of the rationale was to explore the feasibility that that such a large scale
generator may enable the City to operate as a microgrid, at a 25% load level, in the event of a natural disaster. The
initiative was discontinued due to the lack of available site, cost/complexity, and the pursuit of the carbon neutral
electric supply strategy by the community.
7New generation of PV system inverters are capable of providing very limited amount of back-up supply to isolated
home circuits in the event of a grid outage when PV system is producing energy. The electrical appliances for such
application should not need stable power supply (i.e. medical device) because of the inherent variability of solar
power. http://www.sma-america.com/products/solarinverters/sunny-boy-3000tl-us-3800tl-us-4000tl-us-5000tl-
us-6000tl-us-7000tl-us-7700tl-us.html#Downloads-137455
8 The Economics of Battery Energy Storage, Rocky Mountain Institute, October 2015
6
Figure 1. Value streams of Energy Storage Systems in Customer, Utility and Transmission
Services
Customer Service Applications
Historically providing backup power (e.g. uninterrupted power supply, or UPS, systems) – has
been the primary application of storage systems for customers. Storage could also assist
customers in reducing their utility bills as both electricity demand charges to customers
increase and the electricity price differential between day time and night time use increases.
In addition, as utility incentives for solar PV systems are phased out, there may be greater
incentives to store excess solar energy in batteries at customer sites for use during non-solar
production periods. Due to the relatively high cost of storage, the storage projects are currently
not cost effective with the benefit-cost ratio from 15% to 20%, i.e. not cost effective. Hence,
supply reliability is likely to be the main driving factor for home installations of storage systems.
For commercial customers, given CPAU electricity demand charges, electricity retail rates, and
the cost of storage systems, the annualized benefit-cost ratio for this application appears to be
in the range of 30% to 35%, well below the break-even point.
7
Storage systems located at customer sites to provide service to customers directly also have the
potential to provide utility distribution and transmission system services. The value streams
associated with such services to CPAU or to the California Independent System Operator
(CAISO) are relatively small, except under very specific conditions such as when distribution or
transmission systems constraints prevail. Distribution systems constraints are not common in
CPAU currently9. However, as the electricity load increases with greater electric vehicles (EV)
adoption and electrification of natural gas appliances, constraints may arise which may make
storage applications more valuable.
Utility Services to CPAU
As the operator of the electric distribution system, CPAU can utilize storage systems to reduce
distribution systems constraints or defer distribution system expansion investments. As
outlined above, the value stream associated with such applications in Palo Alto is currently low.
Siting of storage to meet CPAU’s resource adequacy requirements imposed by the CAISO, could
annually save CPAU approximately $5 to $10 per kWh of energy storage system installed and
dispatched during peak load hours10. However, the annualized cost of a storage system is
currently about $100 to $150/kWh.
The value of transmission congestion relief for Palo Alto load is currently small 11. The
congestion costs experienced by CPAU’s central solar resources are expected to increase in the
future; however, the value of alleviating congestion costs can only captured by siting storage
physically adjacent to the large utility scale solar projects (often located in the Central Valley).
This increased congestion cost scenario was contemplated and has been incorporated into
CPAU’s solar contracts by incorporating an option for CPAU to site storage onsite at the large
solar arrays in the future.
Transmission Grid Services to the CAISO
CAISO procures many ancillary services to operate the electric transmission grid. These include
frequency regulation, spinning and non-spinning reserves, and voltage support. Among these
services, regulation service is the highest value service and storage systems have the ‘fast-
9 Palo Alto has nine distribution system substations with a total of 28 substation transformers serving 68
distribution feeders. While overall the substation transformers and feeders have sufficient capacity to handle Palo
Alto’s loads (which are currently 10-20% below peak loading levels seen in year 2000), there may be areas of
significant load growth (e.g. area around Stanford Medical Center) that will require load transfers to adjacent
substations to maintain operating flexibility or increases in electric system capacity at certain substations. The role
storage systems could play in deferring such investments are evaluated when designing such projects. Currently
storage is not anticipated to be an economical solution in such projects.
10 CPAU’s cost of resource adequacy capacity procurement could be reduced by $20 to $40/year for every kW of
storage system that has the ability to discharge over a four-hour duration (i.e. a 4 kWh storage system is needed to
meet one kW of resource adequacy capacity requirement). Therefore, the annual value of storage systems is
estimated at $5 to $10/kWh.
11 Internal analysis of CY 2015 CAISO nodal and aggregation point prices shows that on-off peak congestion and
marginal loss differential to be 0.05 cents/kWh for loads and up to 0.5 cents/kWh for central resources.
8
acting’ capability to provide this service; however, the compensation for these services is
currently too low to justify storage systems. Alternatively, CPAU will be exploring the feasibility
of aggregating smaller customer sited systems to bid into the CAISO market to capture both
customer service and grid service value streams.
Taking advantage of potential transmission level energy price differences is another value
stream that storage systems can capture. This application is similar to time-of-use bill
management in the customer-sited storage application, but it should be noted that both of
these value streams cannot be harvested simultaneously.
Figure 2 below illustrates the annual value of each 13 storage value streams as a percentage of
its annualized cost. This means that over the life of the energy storage system, it will recoup
some percentage of its cost. Since all of the systems have value of less than 100% of their
annualized cost, the revenues generated are all well below the breakeven point. However, the
relative economics of each application are informative for the future as storage costs continue
to decline.
As shown in the figure customer-sited storage for demand charge reduction and backup power
for commercial customers have the greatest value. The next most valuable uses of storage are
for PV self-consumption, frequency regulation, and resource adequacy which all recoup 15% of
the current cost. Transmission congestion relief, spinning and non-spinning reserves, and
energy price differences currently provide relatively low values currently. It should be noted
that it is difficult to generalize the value of backup power and distribution deferral because
each application is very case specific and analyzed on a case-by-case basis by both the customer
and CPAU.
9
Figure 2: Illustration of the Relative Value of Energy Storage Applications (% of Annualized Cost)12
Energy Storage Systems Case Studies for Palo Alto
Staff analyzed the three storage applications most relevant to Palo Alto: residential customer-
sited storage with PV, commercial customer-sited storage, and transmission grid-tied storage. A
description and summary of results for these applications are outlined below. The first two
applications are potential nanogrid applications if the systems were designed with sensors and
controllers to operate independent of the electric grid. A detailed description of the full analysis
is provided in Attachment C.
I. Residential customer-sited storage with PV: The scenario analyzed storage installed with
solar PV panels with the intention of maximizing PV self-consumption and minimizing
exports to the electric grid under the net energy metering (NEM) successor program. These
systems are small—in the 5 to 10 kWh scale. With an energy cost differential of about 9.5
cents/kWh (difference between the tier 2 rate of 16.901 cents/kWh versus the NEM
successor buyback rate of 7.485 cents/kWh) the value of energy storage for this application
is about 15% of the annual cost of ownership 13. If the customer values the enhanced
12 While each application individually is not currently cost effective, a combination of applications may be cost
effective. For Palo Alto, such combinations of opportunities are also very limited at this time.
13 Assumed that PV directly feeds the storage system and the configuration enables the storage system to qualify
for the 30% investment tax credit. The annual cost of ownership, net of investment tax credits, was estimated at
$42/kWh-year.
Energy arbitrage
Spin/non-Spin reserve
Frequency regulation
Voltage support
Black start
Resource adequacy
Transmission congestion reliefTransmission deferral
Distribution deferral
TOU bill management
Demand charge reduction
Increased PV self
consumption
Backup power
20%
40%
60%
80%
100% CUSTOMER SERVICES
UTILITIES SERVICES
ISO SERVICES
10
reliability provided by such a combined system, this application will become viable solution
in the residential market segment.
Figure 3 below illustrates how excess solar PV energy could be used to charge the storage
system during the day and use the stored energy to meet the electricity needs of the home at
night, reducing energy purchases at the retail rate.
Figure 3. Illustration of Residential Customer Application: Storage + PV under NEM Successor
This configuration enables customer to store excess solar energy for use at night.
II. Commercial customer sited storage: This application is to use storage to lower the utility
demand charge for the commercial customers. At the current demand charge rate for
commercial customers in Palo Alto 14, the value of this application is estimated at about 40%
of annualized cost of ownership. If CPAU also can harness the storage system to meet CAISO
resource adequacy needs, the combined value stream has the potential to break even at
the current cost of storage system. If configured appropriately, this storage system in this
application can also provide the customer back-up power in the event of an electric grid
outage.
14 Medium and Large Commercial customers pay a demand charge in the range of $14 to $19.70/kW-month
depending on the season. Assumes these storage systems do not enjoy tax credits.
11
Figure 4 illustrates how medium and large commercial customers, who are subject to a utility
demand charge based on the peak load consumption for the month, could use energy storage
to lower their monthly utility peak demand.
Figure 4. Commercial Customer Application to Lower Utility Electricity Demand Charge
III. Transmission grid-tied storage: This scenario assumes storage to be located at one of Palo
Alto’s large PV projects in the Central Valley. Such large systems cannot be located within
Palo Alto. Storage at such sites could provide CAISO services such as frequency regulation
and flexible resource adequacy capacity; could benefit from CAISO energy price differentials
when feasible; and could charge the battery with PV output during times when the systems
would otherwise be curtailed.
The market value of such systems is estimated at about 30% of current cost of ownership 15. The
analysis found that costs had to decline by about 33% and market value of ancillary services
must increase by three fold 16 for such systems to economically viable.
15 Annualized cost of ownership is estimated at 80/kWh-year – estimates based on purchase power agreement
quotes from potential developers. This assumes the projects do not qualify for investment tax credits.
16 Increase from the current low $9/MW-h levels, back to the $25-30/MW-h levels seen previously.
12
Figure 5 illustrates how transmission grid-tied storage could be used to keep loads and
resources in balance at the transmission grid level—by absorbing excess energy (when supplies
exceed demands) to charge the battery and providing energy (when demands exceed supplies)
by discharging the battery.
Figure 5. Transmission Grid-Tied Storage Application for Frequency Regulation & Load Following
Demand Response, Energy Storage, and Distributed Energy Resources in Palo Alto
Demand Response Program
Customer Demand Response (DR) programs are designed to provide an incentive to customers
to change their electricity consumption based on signals provided by CPAU or the CAISO.
Customers capable of providing DR services can meet many of the applications identified for
storage systems without the need for additional storage hardware investments. Over the past 5
years Palo Alto has implemented a DR program that achieved 500 to 900 kW of demand
reduction when CPAU requests load reductions from the large customers participating in the
program during hot summer days. The cost of administering and compensating participating
customers is about $10,000 per year, with similar value to CPAU17.
Much of the DR has been achieved by participating customers controlling their air conditioning
and lighting loads. To achieve a similar level of load reduction, approximately 2 to 3 MWh of
17 Details of this program and planned next steps are outlined in the UAC Report from March 2016
13
storage systems would be needed, requiring a capital expenditure in excess of $2 million. Due
to the relatively favorable economics of DR programs compared to storage, CPAU anticipates
continuing its focus on expanding the DR program to other large customers and investigating
residential applications.
Initiative to Leverage Distributed Energy Resources and Meeting Distribution System Needs
Energy storage systems and DR programs are considered distributed energy resources (DER)
along with EVs, EV charging equipment, PVs, controllable thermostats and electric water
heaters, etc. In February 2016, staff issued a request for proposal to solicit proposals from
communicating and controllable DER vendors who already have such systems installed at
customer premises in Palo Alto.
Examples of services that can be provided by networked and controllable DER devices include
the following:
• Reduced charging of EVs when the value of energy is high. This application is similar to
discharging a battery when the value of electricity is high.
• Injecting capacitive energy into the distribution grid from existing PV systems by
controlling the inverter operation when CPAU’s distribution power factor is low. Smart
inverters in BES can also provide this service18.
• Pre-cooling homes in the morning on hot summer days using thermostat controls in
order to reduce electricity consumption during afternoon peak load periods. This is
equivalent to charging the batteries in the morning and discharging them at night.
Staff is in the process of evaluating proposals and anticipates making pilot scale commitments
to leverage such resources for the benefit of CPAU operations in conjunction with the services
customers are already receiving for such DERs. While these commitments will be for services,
staff is evaluating the merits of providing incentives for the installation of related hardware
such as storage systems.
A comprehensive DER strategy to meet CPAU’s needs in the long term, including potential pilot
scale storage system incentives at customer locations, will be brought to the UAC and Council
for consideration and approval in 2017, along with a recommendation on whether or not to set
energy storage goals for the next 3 years.
Role of Distributed Energy Resources in Meeting Palo Alto’s Sustainability Goals
To the extent they become cost effective and feasible, DERs such as combined PV and storage
systems located at customer premises can enhance customer’s electricity reliability, lower
customer utility bills, improve community resiliency, and lower electricity transmission losses.
18 Inverters are becoming more versatile and new inverter standards will enable distributed energy resources such
as PV and storage systems to provide fast-acting local grid support services such as responding to changes in
system voltage and frequency. CPAU is in the process of testing these features in one of the larger PV systems in
town to improve customer and CPAU distribution system power factor during peak load periods.
14
As initiatives such as Community Solar or Ecodistricts19 help leverage the value of DERs, CPAU
will be well-positioned to facilitate the adoption of these systems where they benefit the
community.
Since CPAU’s electric supply is already carbon neutral, wide adoption of DERs in Palo Alto will
not reduce the community’s carbon footprint, but could help the statewide goal of increasing
the penetration of intermittent renewable electricity. In addition, Palo Alto’s initiative to
electrify water heating with efficient heat pump water heaters has the potential to add value as
energy storage mechanism in the long run by heating water during the times of day when
electricity prices are low20.
NEXT STEPS
Staff will return to the UAC and Council in early 2017 with a recommendation on whether to set
a goal for energy storage and an overall DER strategy. A pilot program may be recommended to
site energy storage systems at customer premises, for both residential and commercial
applications. Incentives for such a program would be identified as a Resource Impact.
RESOURCE IMPACTS
If an energy storage pilot program is recommended and approved, it could cost $250,000 in
customer rebates. Such a program would be administered along with City’s existing Demand
Response program. The staff resources needed for an expanded Demand Response and
Distributed Energy Resource program is anticipated to be 0.2 FTE, and would be managed with
existing resources.
POLICY IMPLICATIONS
Energy storage is a key technology to enable increased penetration of renewable energy in
California and, when installed in customer premises, reduce their utility use. These two aspects
conform to Utilities Strategic Plan objectives and Council policy on environmentally sustainable
utility and customer programs. Any use of storage systems to benefit from energy market price
differentials will be done in conformance with City’s energy risk management policies.
ENVIRONMENTAL REVIEW
The UAC’s discussion of energy storage and microgrid technologies is not a Project requiring
California Environmental Quality Act review.
19 Ecodistrict is a community level project to achieve various sustainability goals. One such goal could be self-
sufficiency in energy by a collective subscription to a larger scale community owned PV system.
20 CPAU’s electrification plan incorporates this possible application of using heat-pump water heaters as energy
storage devices in the long term.
ATTACHMENTS
A. Description of Energy Storage and Microgrid Technologies
B. Value of Electricity Storage in Providing Services to the City of Palo Alto
C. Case Studies of Battery Energy Storage Applications in Palo Alto
D. Thermal Energy Storage in Palo Alto
E. Outline of Energy Storage Regulations, Policies and Incentives
PREPARED BY:
REVIEWED BY:
APPROVED BY:
ANNE-LAURE CUVILLIEZ, Management Specia list
;fl.ENA PERKINS, Resource Planner y;1vA SWAMINATHAN, Senior Resource Planner
'UjN,J RATC~YE, Assistant Director, R"'es.ource Management
/7d11-Vd c£~ J!!' v~
__,ED SHIKADA
4
Interim Director of Utilities
15
Attachment A
A-1
Description of Energy Storage Technologies and Microgrid Technologies
1. Energy Storage technologies
Please refer to Staff Report 4384 for a review of energy storage technologies. The vast majority
of current grid connected energy storage systems 1 (90%) are pumped hydro projects, with 28
GW installed in the U.S. Thermal storage is the second most installed storage technology with
855 MW of storage in the US (~3%). 740 MW of Compressed Air energy Storage facilities exist in
the U.S, which represents 2.4% of the US capacity. Li-ion batteries (1.4%), lead acid batteries
(0.5%), flywheels (0.3%) and flow battery 0.1% follow. The fastest growing residential and
commercial applications of storage in California use battery energy storage systems (BES), much
of the report outlines applications of such systems. Thermal energy storage (TES) system
applications were also reviewed.
2. Microgrids
a. Microgrids value
The value of microgrids concentrates around four main areas (see Figure A1):
- Security: by offering an uninterruptible power supply for critical loads.
- Reliability: contiguous quality power supply 24/7 with local generation
- Sustainability: allows the integration of local renewable generation
- Cost efficiency: opportunities to do peak shaving, demand-response, and hedge against
high grid prices
Figure A1: Graphical representation of microgrid values
1 http://www.energystorageexchange.org/
Security
Reliability
Sustainability
Cost
efficiency
UPS for critical
loads
Islanding
Lower CO2 footprint
On-site generation
Peak shaving
Grid independence
Hedging
Effective energy
management
Attachment A
A-2
Microgrids can provide several services to the main grid:
- Ancillary services
- Demand/response, Curtailment
- Ramping, flexible capacity
b. Key components and functions of a microgrid
The microgrid needs to be able to operate the loads and energy sources in grid connected or
islanded mode and transition smoothly between the two modes. Hence, the microgrid has the
following needs:
- Islanding detection: During islanding mode the microgrids is responsible of voltage and
frequency regulation. The microgrid controller provides these regulation services.
Detection can be done locally, by measuring local variables (voltage, frequency) or
remotely by communicating with the main grid.
- Fault current protection: The microgrids require detection and protection against fault
current flows, i.e. short circuits.
- Power quality: Harmonic contents and voltage unbalance. This can also provide
ancillary services to the main grid.
- Black start: when islanded
Other desirable functionalities of the microgrids include:
- Energy optimization: this includes power curtailment, peak shaving, storage
management
Those functions are performed by the microgrid master controller (see Figure A2), supported by
a strong communication and sensor network. The main function of the master controller is to
match loads and generation (See A2 and A3) and to provide monitoring of the microgrid.
Figure A2: Master Controller functions within the microgrid
Attachment A
A-3
Figure A3: example of microgrid block diagram, Experimental Power Grid Centre (EPGC)
microgrid test facility2
The main applications of the commercial microgrids are for community-sized systems and
campuses that have critical loads to protect (i.e. fire station, police station, and
communications) and want to integrate local renewables in the grid.
c. Nanogrids
Nanogrids are microgrids for a single-load or single-building microgrid. Nanogrids can also
island from the main grid. The main commercial applications of nanogrids are residential homes
and single commercial buildings with solar panels and back-up battery storage.
2 Thangavelu et al., Integrated Electrical and Thermal Grid Facility - Testing of Future Microgrid Technologies, Energies 2015,
8(9), 10082-10105, http://www.mdpi.com/1996-1073/8/9/10082/htm
Attachment A
A-4
Figure A4: Illustration of a nanogrid in a residential house
The PV panels and battery bank are connected to the inverter. The main breaker is the point at
which the house can be islanded from the grid. The battery, PV, critical loads and inverter
interaction is managed at the subpanel interface (See Figures A4 and A5). The utility meter is
located between the main grid and the main breaker.
Figure A5: Main elements of a nanogrid
Attachment A
A-5
Two different design philosophies can be adopted for nanogrids. Those grids can operate in
Direct current (DC) or alternating current (AC) current. The two different strategies and the
corresponding systems depicted on Figure A6 depend on how many inverters are used in the
system. PV panels produce energy in DC current, and most houses loads requires AC current.
Batteries take DC current as well.
In the AC strategy, the DC current from the PV panels in converted to AC through an inverter
and can serve house loads or be exported to the grid. When charging the battery, the current is
converted back to DC through a second inverter. This type of installation is usually chosen when
the storage is added after the PV panels were already installed.
In the DC strategy, the DC current from the PV panels can be used to charge the battery directly
or be converted to AC through an inverter to be used for the house or exporter to the grid. Only
one inverter is required. Energy from the grid cannot be used to charge the batteries.
Figure A6: Schematic representation of AC (left) and DC (right) energy storage
The advantages and differences of both systems are outlined in Table A1.
Table A1: Comparison of AC and DC storage system
Attachment B
B-1
Value of Electricity Storage in Providing Services to the City of Palo Alto
This section describes in detail the 13 services that storage systems could provide to the three
stakeholder classes—customers, utility and the California Independent System Operator
(CAISO)—as outlined in the report.
Table B1: Summary table of 13 services provided by storage
Service Percentage of
cost
Evolution
A.
SO
/
R
T
O
S
e
r
v
i
c
e
s
1. Frequency regulation 15%
Possible at medium term. Revenue
streams in CAISO are not beneficial
at the moment.
2. Spin/Non-Spin Reserve 7%
Unlikely to become financially viable
in the years to come. Regulation is
the service generating the most
revenue at the moment
3. Voltage support N/A at the time
Unlikely since the burden is on the
generators.
4. Energy Price
Differentials
8%
Not beneficial for this purpose only,
but can provide additional value
streams for other usage. Could
evolve if gas prices go up.
B.
U
t
i
l
i
t
y
Se
r
v
i
c
e
s
5. Resource Adequacy 15%
Not beneficial for this purpose only,
but can provide additional value
streams for other usage.
6. Transmission Deferral 0%
Not beneficial in the case of Palo
Alto since transmission is billed by
unit of energy.
7. Transmission
Congestion Relief
10%
Could become necessary if
congestion becomes a big problem
Attachment B
B-2
8. Distribution Deferral 50% ( case by
case) – but N/A at
the moment in PA
On a case by case basis. Expensive
upgrades unlikely because of current
state of transformers.
9. Distribution loss savings <1%
Not beneficial for this purpose only,
but can provide additional value
streams for other usage.
C.
C
u
s
t
o
m
e
r
S
e
r
v
i
c
e
s
10a. Backup power -
residential
<1%
Not beneficial, especially with high
reliability and unlikely to go up
enough to justify an investment.
10b. Backup power -
commercial
case by case
Can be 100%
Already financially viable if the
industry is highly dependent on
electricity and critical loads are low
(i.e. server vs full building). Likely to
become a package with other
services to the grid, although those
services might be conflicting.
11. Time-of-Use Bill
Management
<1%
Highly dependent on TOU rates.
Unlikely to go up because peak
consumption is not an issue in Palo
Alto.
12. Demand Charge
Reduction
40%
Getting closer to competitive. Likely
to become more competitive as
more offerings become available.
13. Increased-PV Self-
Consumption
18%
Unlikely to go up with CPAU low
electricity tariffs.
Attachment B
B-3
A. ISO/RTO Services
Ancillary services provide the CAISO the resources to reliably maintain the balance between
generation and load. The different types of ancillary services are described in Table B2.
Table B2: Ancillary services description1
Storage technologies like batteries and flywheels are most qualified for fast response times,
which cheaper gas peakers struggle to achieve at low standby cost. Gas peakers need to be
running continuously at low power and burn fuel in order to be online within minutes, a
requirement which is easily achieved by a battery.
The City of Palo Alto’s 56 MW share of the Calaveras Hydroelectric Project satisfies the ancillary
services needs of the city. This study evaluated the possible value that could come from owning
new storage technologies for ancillary services.
1 http://web.ornl.gov/~webworks/cppr/y2001/rpt/122302.pdf
Attachment B
B-4
1. Frequency regulation
Most US electric equipment relies on a grid operating at a frequency of 60 Hz with very low
tolerance for variation. When the demand and supply are not exactly matching, the grid
frequency varies. Storage, by absorbing or releasing power, can provide regulation to increase
or decrease the frequency of the grid.
CAISO monthly market performance reports2 contain average ancillary services prices for
regulation in the Day Ahead market for 2015. The average payment for regulation in 2015 was
$8.77 per MW and per hour.
It is noteworthy that ancillary services prices have been trending upward in January 2016.
Projected average prices for 2020 are about 15$/MW, but should reach at least 35$/MW for
several hours per day.3 FERC Order 755 has stipulated that ISOs implement “a payment for
performance that reflects the quantity of frequency regulation service provided by a resource
when the resource is accurately following the dispatch signal.”4 However, in the current CAISO
market the mileage payment5 that act as payment for performance is too low to be relevant
with $0.01-$0.03/MWh in the Real Time market and 0.09$/MWh in the Day-Ahead market.
Hence this study did not consider a mileage payment.
Data from the model prepared by StrateGen for the California Energy Storage Alliance (CESA)6
was used to assess the cost and revenue of battery for regulation.
At the assumed price of $600/kWh, batteries for regulations systems only do not make sense
financially. An installed price of under $50/kWh would make battery systems for regulation
break even under current pricing. Three strategies were considered: 1) several cycling per day;
2) only bid for the highest hour of the day (~15$/MWh); and 3) only bid for the highest ten
hours of the month (~50$/MWh).
The optimum is to bid for 5-7 hours a day (see Figure B1) and reserve the use of battery for
other services for the rest of the day, which could complement the revenue of the system. The
marginal benefice of bidding additional hours on a 20-year system did not map out to a
significant increase in revenue because of the replacement cost of the battery. The
replacement cost of the battery was assumed equal to the initial installation cost.
The ancillary services payment per MW per hour has been lower in the past years due to the
low prices of gas. In 2010 prices were around $30/MW. Prices in 2020 should reach at least
2 https://www.caiso.com/market/Pages/ReportsBulletins/Default.aspx
3http://energy.gov/sites/prod/files/2015/12/f27/Ancillary%20Service%20Revenue%20Potential%20for%20Geothermal%20Gen
erators%20in%20California.pdf
4 https://www.ferc.gov/whats-new/comm-meet/2011/102011/E-28.pdf
5 https://www.caiso.com/Documents/Pay-PerformanceRegulationFERC_Order755Presentation.pdf
6 http://www.strategen.com/storagealliance/sites/default/files/White%20Papers/CESA_FR_White_Paper_2011-
02-16.pdf
Attachment B
B-5
35$/MW for 5 hours per day. In this case the breakeven price would be around $150/kWh
installed.
Note: The utility would be unlikely to own the system as considered in this study, and would
have to contract through a third party to own and manage the storage system. This will likely
increase the prices of storage and delay the timeline at which regulation could become
profitable.
Figure B1: Maximum battery system investment cost per kWh needed for a null 20-year NPV
regulation in function of cycles per day
2. Spin / Non-Spin Reserve
Storage can bid as spinning, non-spinning or supplemental reserve. However, the value of those
services is lower than frequency regulation by at least 50%. The return on investment of those
services would be lower than for regulations. Hence, this study did not consider the economics
of those markets.
3. Voltage support
Reactive power is the non-usable part of power (see Figure B2). The power factor is defined as:
𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑝𝑝𝑝𝑝= 𝑃𝑃,𝑝𝑝𝑝𝑝𝑓𝑓𝑟𝑟 𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑆𝑆,𝑓𝑓𝑝𝑝𝑝𝑝𝑓𝑓𝑝𝑝𝑝𝑝𝑎𝑎𝑓𝑓 𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
$50.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24Ma
x
i
n
v
e
s
t
m
e
n
t
c
o
s
t
i
n
$
/
k
W
h
Number of cycles per day
Attachment B
B-6
Figure B2: Real, Apparent and reactive power, By Wikieditor4321 - Own work, CC BY-SA 4.0,
https://commons.wikimedia.org/w/index.php?curid=45518503
In order to supply a load, the real power must be equal to the load. A high reactive power
increases the ratings necessary in the lines, but decreases the efficiency since only “real power”
is usable. For example, if the power factor is 0.6, then apparent power is 1.67 times the load,
which increases transmission losses. In order to carry this extra power, all the transmission and
distribution system would need to be oversized. This is why grid-tied systems are required to
supply power above a defined power factor.
However, there might be times where the independent system operator wishes to increase or
decrease the apparent power in order to keep the grid operating within the voltage range that
it can tolerate. In that case, reactive power is the main source of control of the apparent power
experienced by the transmission lines. In order to keep the transmission lines within
operational range of voltage, injection or withdrawal of reactive power is necessary.
CAISO “maintains acceptable voltage levels and VAR flow on the CAISO Controlled Grid”
through participating generators that are required to operate within a specified power factor
band. Participating load at interface points are not compensated, only generators.7
Payment to generators is in form of lost opportunity cost to the Locational Marginal Price (LMP)
when operating outside of normal conditions. CAISO has also procured voltage control through
Reliability-Must-Run facilities at the rate of $50,000/MVAr or $50/kVAr.8
Capacitors are best suited to solve reactive power issues, and increase power factor.9 However,
this will need to be procured by power producers. Batteries have been proven effective at
controlling power drops from local distributed generation, which would be useful in the case of
microgrids.10 Palo Alto would only be concerned if the local generation power factor became
problematic.
7 https://www.caiso.com/Documents/3320.pdf
8https://www.caiso.com/Documents/CalPeakandMalagaCommentsReactivePowerRequirementsandFinancialCompensationRevi
sedStrawProposal.pdf
9 http://www.hv-eng.com/2011CEDCapacitors.pdf
10 J. Yi, P. Wang, P. C. Taylor, P. J. Davison, P. F. Lyons, D. Liang, S. Brown and D. Roberts, “ Distribution Network Voltage Control
Using Energy Storage and Demand Side Response”, 2012 3rd IEEE PES, ISGT Europe, Berlin
Attachment B
B-7
4. Energy Price Differentials
A storage system enables buying electricity when prices are low and use the electricity when
prices are high. For Palo Alto, the average price difference between peak and off-peak pricing is
0.00717 $/kWh (expected to rise to $0.011/kWh by 2025). At this revenue, over 10,000 cycles
and with 80% round trip efficiency, a battery would only generate $57 per kWh of installed
capacity, which does not financially justify such a system.
B. System/Utility Benefits
5. Resource Adequacy
CAISO mandates that each Load Serving Entity (LSE) must submit a resource adequacy plan “to
satisfy its forecasted monthly Peak Demand and Reserve Margin for the relevant reporting
period.”11 Palo Alto currently procures capacity at the rate of $28/kW-yr. The offers that the
utility received from remote storage have been at least double this value. A current flexible
resource adequacy policy is being considered12, but the City’s ownership share of the Calaveras
Hydroelectric Project would satisfy those requirements.
6. Transmission Deferral
A higher load can trigger a transmission line upgrade to accommodate a higher power rating.
However, if the upgrade is triggered by a peak load that happens only a couple hours of the
day, months or year, it might be advantageous to procure storage to displace the peak
consumption to a later hour of the day instead of upgrading the lines.
CPAU is currently paying for transmission charges per unit of energy (kWh) and does not
experience demand charges. Therefore peak shifting for avoiding transmission charges does not
offer any financial incentive for CPAU. The demand is satisfied by the resource adequacy
described in the previous paragraph and procured at a price that do not justify considering
storage.
7. Transmission congestion relief
CPAU has Power Purchase Agreements (PPAs) with generators in California. CPAU then sells this
energy at the Locational Marginal Price (LMP) at the node where generation interconnects.
Nodes that experience a higher load than the transmission line can accommodate are called
congested node and experience a lower price for energy because of congestion charges. In
some cases the energy price can be negative and force the curtailment of the generation. This
study analyzed one year of LMP data at the interconnection node for the Hayworth solar farm
with which the City has a PPA13 and considered two strategies:
11 https://www.caiso.com/Documents/CIRAResourceAdequacyToolUserGuideforMarketParticipants.pdf
12 https://www.caiso.com/Documents/StrawProposal-FlexibleResourceAdequacyCriteria-
MustOfferObligationPhase2.pdf
13 City of Palo Alto Solar PV PPA Projects -
https://www.google.com/maps/d/viewer?mid=zm8TOActUeOA.k1KfA2u9T8u4&hl=en_US&usp=sharing
Attachment B
B-8
1. Store the production of the four most congested hours of the day (between 11AM and
3PM) and sell the storage during the highest three hours of the evening peak; and
2. Store the production of the most congested hour of the day (at 12PM) and sell the
storage during the highest priced hour of the evening peak.
The power plant’s daily production was estimated using PV watts14, and assumed roundtrip
efficiency around 70%. In each case the storage did not make economic sense. For a high
efficiency (93%) battery with one discharge per day, the value per kWh displaced increased to 2
cents, which is still below the required value to break even.
However, if the trend of negative pricing during peak hours keeps increasing and battery prices
keeps falling then there would be scenarios in which batteries would be cost effective. For
example, if the amount per kWh displaced reached $0.04/kWh on average and the batteries
reached $200/kWh then the storage would be cost effective.
8. Distribution Deferral
Distribution deferral uses storage to absorb a growing load on a transformer. The growing load
would trigger a transformer upgrade, but with storage peak shaving, the transformer upgrade
can be deferred to a later time. This allows for a longer utilization of the infrastructure and
lowers the investment risk of the utility.
According to the Sandia study “Electric Utility Transmission and Distribution Upgrade Deferral
Benefits from Modular Electricity Storage” by Jim Eyer 15, the distribution deferral is more
profitable in its first year, so the study makes a case for reusable and transportable storage that
will defer upgrades up to the point that the upgrade is necessary and then be installed on
another transformer. In this case, they find that with an average cost of transformer upgrade
around $75/kW, the value of reusing the storage system in 5 different locations would reach a
cumulative value of $1,700/kW after 10 years. For three hours battery storage, this represents
$566/kWh which could be cost effective in the future.
As a case study, data from the 2009 PNNL study “Avoiding Distribution System Upgrade Costs
Using Distributed Generation”16 was used. The cost data of different transformer upgrade
projects was compared to the cost to defer the entire upgrade capacity with a battery system:
1. Four-hour Li-ion battery system at $600/kWh
2. Three-hour Li-ion battery system at $600/kWh
3. Three-hour 2020 horizon for Li-ion batteries at $300/kWh
The results show that most transformer upgrades would be more cost effective than a full
upgrade with a battery. Certain projects which are especially costly can beneficiate from a
battery system compared to an upgrade, as long as the peak is narrow enough that the battery
14 http://pvwatts.nrel.gov/
15 http://prod.sandia.gov/techlib/access-control.cgi/2009/094070.pdf
16 http://www.sandia.gov/ess/publications/SAND2010-0815.pdf
Attachment B
B-9
has sufficient capacity. By 2020, if battery costs are halved, more battery systems could become
more cost effective than an upgrade. These results are also confirmed in the Sandia report,
mentioning the E3/EPRI study17 which reported values of T&D deferral for PG&E ranging from
$230/kW and $1,173/kW, in which the upper range would make batteries close to cost
effective.
CPAU’s current distribution transformer upgrade costs range from $40 to $220/kW. The best
candidates for deferral are transformers where the projected load growth is slow and the peak
band is narrow. The smaller the storage needed for the one-year deferral, the more cost
effective it is, since the investment is smaller. Smaller upgrades tend to be pretty expensive per
kW, but the storage power required is generally too high to make sense for a deferral (>10%). In
2016, the only systems that could be cost effective for a one-year deferral have a slow load
growth (under 2%) and high T&D cost (over $100/kW) which is experienced by small
distribution overhead transformer upgrades in Palo Alto. However, the storage power required
for the distribution overhead transformers is generally above 20%, which makes the deferral
not cost effective. In the future, with an average cost of $300/kWh installed for batteries,
projects with high cost and moderate growth, or low growth and average cost could benefit
from a one-year deferral through battery storage. So far CPAU transformers all have above 20%
remaining capacity and the load has been stable, which means that no upgrade will be required
in the next years. In the event that several transformers reach capacity in the long-term, mobile
battery storage could be beneficial to defer several upgrades.
9. Distribution loss savings
The system experiences on average 3% losses to distribute electricity. However, the losses are
higher during peak hours (4%) than off-peak (2%). By storing electricity locally during off-peak
hours and distributing it during peak hours, CPAU can avoid 2% distribution losses.
𝐸𝐸𝑟𝑟𝑝𝑝𝑓𝑓𝑓𝑓𝑝𝑝𝐸𝐸𝑓𝑓𝐸𝐸𝑓𝑓𝐸𝐸 𝑠𝑠𝑓𝑓𝑠𝑠𝑝𝑝𝑠𝑠(𝑘𝑘𝑘𝑘ℎ)=𝐸𝐸𝑟𝑟𝑝𝑝𝑓𝑓𝑓𝑓𝑝𝑝𝐸𝐸𝑓𝑓𝐸𝐸𝑓𝑓𝐸𝐸 𝑝𝑝𝑝𝑝𝑝𝑝𝑓𝑓ℎ𝑓𝑓𝑠𝑠𝑝𝑝𝑠𝑠 (𝑘𝑘𝑘𝑘ℎ)× �10.98 −10.96� 𝐸𝐸𝑟𝑟𝑝𝑝𝑓𝑓𝑓𝑓𝑝𝑝𝐸𝐸𝑓𝑓𝐸𝐸𝑓𝑓𝐸𝐸 𝑠𝑠𝑓𝑓𝑠𝑠𝑝𝑝𝑠𝑠(𝑘𝑘𝑘𝑘ℎ)=𝐸𝐸𝑟𝑟𝑝𝑝𝑓𝑓𝑓𝑓𝑝𝑝𝐸𝐸𝑓𝑓𝐸𝐸𝑓𝑓𝐸𝐸 𝑝𝑝𝑝𝑝𝑝𝑝𝑓𝑓ℎ𝑓𝑓𝑠𝑠𝑝𝑝𝑠𝑠 (𝑘𝑘𝑘𝑘ℎ)× 2.13%
For peak prices around $30/MWh, that’s $0.64/MWh shifted (0.064 cents per kWh). With this
revenue, over 10,000 cycles and with 80% round trip efficiency, a battery would only generate
$5.10 per kWh of capacity in addition to the $57 per kWh of benefits, which does not justify
financially such a system.
17 http://connection.ebscohost.com/c/articles/9508071617/marginal-capacity-costs-electricity-distribution-
demand-distributed-generation
Attachment B
B-10
C. Customer benefits
10. Backup power
In order to estimate the cost of customer outage for the different classes of customers given
CPAU’s reliability data, the Interruption Cost of Energy tool funded by DOE18 was used using
most default parameters with an adjustment for Palo Alto median income to $123,495 from
2013 data19 adjusted to 2016 dollar value (see Table B3).
Table B3: Estimation of 2012-2015 average yearly cost of power interruption in Palo Alto for
each customer class
The average yearly cost of outages shows that residential customers would derive very little
economic value in having a backup power given that their annual losses are relatively low.
However, for certain commercial customers, investing in storage as a backup power for critical
loads can be justified to mitigate losses in case of power interruption, especially if the critical
loads are small.
Diesel generators cost about $200/kW. However, a 5kW generator will consume about 18
gal/day, which costs about $40-50 per day to run. A larger commercial-scale generator sized at
300 kW will consume 20 gal/hr. A battery system has no running cost. Given the reliability of
CPAU, a battery storage system will never be cheaper than a diesel generator for residential or
18 http://www.icecalculator.com/
19 http://www.city-data.com/income/income-Palo-Alto-California.html
Residential customer
Small commercial
customer (<50,000
kWh)
Medium and large
commercial customers (
>50,000 kWh)
Average yearly cost of power
interruption $26.96 $852.86 $65,413.18
$-
$10,000.00
$20,000.00
$30,000.00
$40,000.00
$50,000.00
$60,000.00
$70,000.00
Average yearly cost of power interruption per customer class
Attachment B
B-11
commercial applications. The exception to this rule would be in case of an extended period of
time without power (i.e. earthquake related) and with the inability to supply enough diesel to
run a generator, a commercial customer could then beneficiate from a PV+storage system that
would allow the critical operations to keep running without a diesel supply.
11. Time-of-Use Bill Management
When a customer is on a time-of-use (TOU) rate schedule, electricity is more expensive during
peak hours. Instead of consuming electricity during peak time, it might be more economical to
use the energy stored, and recharge using the grid during off-peak hours. The storage system
allows customers to optimize when they buy, store or export power. Peak shaving contributes
to lowering the demand on the grid during peak hours.
A study carried by Stanford student Tha Zin looked at the net present value (NPV) of peak
shaving with current CPAU rates. The dataset used in her analysis was the hourly electricity
consumption (load profile) data of 1,923 households in Bakersfield, California from August 1,
2010 to July 31, 2011. To evaluate the NPV of storage, the study varied the following
parameters: TOU rates 20, roundtrip system efficiency, and system costs as well as different
amount of peak shifted. For the last parameter, the battery was sized to shift at the peak load
for only a certain percentages of the days per year (5-100%). If the percentage of the days is
5%, then it means that the battery was sized to shift the highest 5% peaks of the year.
For each household, the NPV of a storage system was calculated. Results show that given the
current values in TOU, efficiency and cost only one customer out of the pool would have a
positive NPV with a storage system.
12. Demand Charge Reduction Commercial customers
See case study II in Attachment C.
13. Increased-PV Self-Consumption
See case study I in Attachment C.
20 http://www.cityofpaloalto.org/civicax/filebank/documents/32678
Attachment C
C-1
Three Case Studies of BES Storage Applications in Palo Alto
Outlined below is the analysis of three most relevant storage applications for Palo Alto:
I. Residential customer application. Storage is installed after solar PV panels with the
intent to do time-of-use bill management under the successor net energy metering
program to increase PV-self consumption.
II. A commercial customer application within Palo Alto (Palo Alto City Hall). The size is in
the tens or hundreds of kW/kWh range and designed to provide electric customer
demand charges reduction and meet CPAU resource adequacy needs.
III. A transmission grid-tied storage unit, either close to Palo Alto or located at one of Palo
Alto’s central PV plants. Due to the relatively large size, in the MW/MWh scale, it is
assumed that the system cannot be located within Palo Alto due to the lack of suitable
land. The application would be to provide CAISO services such as frequency regulation
and flexible resource adequacy capacity.
I. Residential customer PV+ storage
a) Description of the Storage System & Cost: Residential customer installing battery
storage to store the energy produced by the solar panels during the day and to use later
during the evening and night. The consumer scenario was identical to the one defined in
Attachment C of the NEM Successor Program Staff Report 1. The three options are: 1) no
storage; 2) a 3.3 kW/7 kWh system 2; and 3) a 6 kW/12 kWh storage system.3
b) Application: Increased PV Self-Consumption
c) Value: energy exported to the grid is paid the NEM successor program export rate of
$0.07485/kWh; current electric retail rates are $0.11029/kWh for Tier 1 (up to
11kWh/day) usage and $0.16901/kWh for Tier 2 (over 11 kWh/day) usage.
d) Results and Conclusion: Calculations can be found in Table C1 below. Figure C1 shows
how the energy delivery is reduced by the battery storage. When taking into account
the round trip losses and current energy prices, the 7 kWh system saved $169/year and
the 12 kWh system saved $194/year. When taking into account the annualized cost of
installation of storage ($130/kWh-yr for a ten-year warrantied system), the benefits are
not sufficient to justify the installation of the system, as the payment for solar + storage
is higher than solar only (see Figure C2). At a price of $280/kWh installed and a delta
between on-peak and off-peak electricity price of $0.10/kWh, storage systems will break
even.
e) Assumptions:
• Round trip efficiency was assumed to be 92%.
• In both battery scenarios, the customer stores as much power as possible during the
day to use it later at night.
1 https://www.cityofpaloalto.org/civicax/filebank/documents/51848
2 With the 7 kWh system, the customer might not be able to capture fully the excess energy during the summer days. Installed
cost was assumed to $9,500.
3 With the 12 kWh system, the customer do not export any energy to the grid year round.
Attachment C
C-2
• Solar installed cost was assumed to be $3.50/W-DC ( group-buy price)
• Investment Task Credit (ITC) was applied toward solar panels but not storage, since
the installation of storage was assumed to happen after the customer installed PV.
Figure C1: Representation of energy delivered, exported to the grid, consumed out of
storage, netted on site and lost in the three storage cases
Figure C2: Energy annual cost for no solar and the three storage cases considered, to be
compared with no solar case.
-4000
-2000
0
2000
4000
6000
8000
10000
12000
14000
Solar only Solar + 3.3 kW/ 7
kWh system
Solar + 6 kW/12
kWh system
kWh
annual
Losses
Energy delivered
Energy exported to the grid
Stored energy consumed
Solar energy netted
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
No solar Solar only Solar + 3.3 kW/ 7
kWh system
Solar + 6 kW/12
kWh system
An
n
u
a
l
i
z
e
d
c
o
s
t
Energy bill
Battery cost
Solar system cost
Attachment C
C-3
II. Commercial Customer Storage Application, Located at Customer Premises
a) Description of the Storage System & Cost: Commercial customer installing batteries with
the goal to reduce demand charges and provide resource adequacy value to CPAU.
Using the Palo Alto City Hall’s load, the recommended size for a leased system for the
building was about 18 kW/36 kWh (i.e. 18 kW capacity with 2 hours of charge) for an
annual cost of about $5,000.
b) Application: Demand charges reduction for commercial building customer and (flexible)
resource adequacy value to the utility.
c) Value: The customer’s cost for demand charges can be reduced (current demand rates
on the E-4 Rate Schedule are $14.04/kW-month during the winter and $19.68/kW-
month during the summer). In addition, if CPAU is able to dispatch these systems to
meet resource adequacy needs, these systems can harness higher value stream
currently valued at $28/kW-yr. Since most of these storage systems also come with
telemetry and dashboards profiling entire building loads in real time, building operators
are able to garner greater insights to more optimally operate the building. However, this
value was not considered in this analysis since it is not directly derived from storage.
d) Results and Conclusion: The annual cost of the system is compared to the annual
revenue stream as shown in Figure C3. Because of the flatter load profile shape, the
required capacity to shave off the peak is higher than if the peak was narrow and tall.
Resource adequacy related values are also relatively small. Thus, such commercial
systems are not cost effective in Palo Alto.
e) Assumptions:
• System life: 10 years
• O&M cost are considered negligible for the self-operated system
• Winter peak is 3-hour long and summer peak is 5-hour long.
Figure C3: Comparison of yearly revenue to cost of commercial battery storage for Palo Alto
City Hall
Notes: The commercial systems considered do not offer the ability to island, which would
harness additional value, although at a potentially higher cost.
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
Third party operated 18 kW/36 kWh system
An
n
u
a
l
r
e
v
e
n
u
e
Demand charges reduction
Resource Adequacy
Cost
Attachment C
C-4
III. Transmission Grid-Tied Storage Located Outside Palo Alto
a) Description of the Storage System & Cost: Battery Energy Storage (BES) located outside
Palo Alto and tied to the CAISO grid at 115 kV and sized at 20 MW/80 MWh (i.e. 20MW
capacity with 4 hours of charge). Annual capital cost was assumed to be around
$190/kW-yr, and O&M cost around $20/MWh with a maximum number of discharge
cycles allowed per year (about once per day).
b) Application: provision of CAISO ancillary services of frequency regulation and flexible
resource adequacy capacity
c) Value: Regulation services valued at $9/MW-hour 4 (now) and $25/MW-hr (after 2020);
capacity is currently valued at $28/kW-yr, flexible capacity valued at $50/kW-year (after
2020)
d) Results and Conclusion: The annual cost for the system is compared to the projected
revenue stream on Figure C4. While the potential maximal revenue through regulation
is high, the charges for battery discharge and the limitation of one discharge per day do
not provide an incentive for use for regulation services. The revenue from resource
adequacy only would be too low to justify the investment. Currently, additional revenue
of $2 million per year would be necessary to break even with being paid twice a day for
only one discharge. Being paid four times per day with only one charge-discharge cycle,
the revenue could break even by 2020. However, a better understanding of the amount
of energy dispatched per period called by the CAISO would be critical to improve the
understanding of the revenue stream from the provision of regulation services, since the
bidding strategy is essential in deriving value from this investment.
e) Assumptions:
• Current prices for round-trip regulation are around $8-9/MW-h but prices are
expected to rise to $20-30/MW-hr within the next years.
• Arbitraging the CAISO energy price differential and relieving economic
curtailment could not be considered because they would compete with
frequency regulation, as the high frequency regulation prices would happen at
the time of curtailment and high energy prices.
• Capacity for regulation can be rated from a 320 MW for a 15-minute discharge to
20 MW for a four-hour discharge. However, the payment occurs per MW-hr, so
all combinations are equivalent in our calculations.
• Capacity for flexible capacity was rated for four0-hour discharge period (20 MW).
• The analysis considered the following two cases for regulation dispatching:
1. Paid twice a day: the analysis assumed that the system gets dispatched on
average half of the hours that were bid and awarded. In that case the system
can bid twice the capacity of regulation-up and regulation-down
2. Paid four times a day: the analysis assumed that the system gets dispatched
on average a quarter of the hours that were bid and awarded. In that case
the system can bid four times the capacity of regulation-up and regulation-
down.
4 Regulation and other ancillary services procured by CAISO is in the form of a capacity payment for every hour.
Attachment C
C-5
Figure C4: Comparison of economics of grid-tied batteries based on utilization of batteries in
CAISO market
20 MW / 80 MWh
Attachment C
C-6
Table C1: Bill Illustration of a Residential Customer with a Solar PV System only, Solar + 7 kWh system and Solar + 12 kWh battery
system under the NEM Successor Rate
1.
T
o
t
a
l
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n
e
r
g
y
C
o
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s
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m
p
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2.
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P
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t
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(
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3.
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n
e
r
g
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d
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(
k
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4.
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(
k
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)
5.
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n
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D
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C
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s
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6.
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t
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7.
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8.
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9.
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f
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7
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10
.
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C
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D
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l
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s
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(
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11
.
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Gr
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12
.
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13
.
M
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B
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14
.
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b
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+
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15
.
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+
1
2
k
W
h
sy
s
t
e
m
Jan 1,400 327 244 84 1,156 1,079 1,079 $175 $162 $162 ($6) $0 $169 $162 $162
Feb 1,204 314 250 64 954 895 895 $143 $133 $133 ($5) $0 $138 $133 $133
Mar 1,061 519 309 210 752 559 559 $107 $74 $74 ($16) $0 $91 $74 $74
Apr 918 610 311 299 607 414 332 $83 $51 $37 ($22) ($7) $61 $44 $37
May 885 704 341 363 543 343 209 $72 $38 $23 ($27) ($11) $45 $27 $23
Jun 882 659 352 307 530 337 248 $70 $38 $27 ($23) ($7) $47 $30 $27
July 929 711 377 334 552 352 245 $73 $40 $27 ($25) ($9) $48 $31 $27
Aug 894 582 312 270 582 382 334 $78 $45 $37 ($20) ($4) $58 $41 $37
Sep 930 551 301 250 629 436 399 $87 $54 $48 ($19) ($3) $68 $51 $48
Oct. 943 467 266 201 677 492 492 $94 $63 $63 ($15) $0 $79 $63 $63
Nov 954 348 191 157 764 620 620 $110 $85 $85 ($12) $0 $98 $85 $85
Dec 1,184 299 198 101 985 892 892 $147 $131 $131 ($8) $0 $139 $131 $131
Tot: 12,184 6092 3452 2640 8732 6,801 6,302 $1,240 $914 $848 ($198) ($41) $1042 $873 $848
Attachment D
D-1
Thermal Energy Storage Costs in Palo Alto
Thermal Energy Storage
Thermal energy storage (TES) is a “technology that stocks thermal energy by heating or cooling
a storage medium so that the stored energy can be used at a later time for heating and cooling
applications and power generation. TES systems are used particularly in buildings and industrial
processes.”1 This study focuses on the use of ice for deferring electric consumption for cooling
purposes in HVAC systems. In this process, cheaper night-time electricity is used to freeze a
fluid, which then reduces the electricity needed to provide air conditioning when electricity is
more expensive during the day.
History of TES in Palo Alto
In the late 1980s and early 1990s the City of Palo Alto Utilities (CPAU) had a generous incentive
program for TES through for commercial customers. These incentives were motivated by steep
and ratcheted demand charges imposed on Palo Alto by PG&E. Most of the systems installed
under this program have been dismantled or decommissioned due to failures, need for space,
or a lack of engaged operation and maintenance staff.
A TES study was carried out in 2013 an provided in the 2014 Energy Storage Procurement
report (see Attachment E (Thermal Energy Storage in Palo Alto) of Staff Report 4384.2)
TES benefits
The goal of the incremental addition of a TES system to existing chiller-based cooling systems’ is
to be able to turn off (completely or partially) the chiller during peak hours. This results in the
following benefits:
- Reduction of demand charges for commercial customers
- For customers on Palo Alto’s large commercial TOU rate, a TES system also delivers
energy charge savings by shifting energy consumption from high-price periods to low-
price periods
- Increased reliability of the cooling system
- Potential participation in Demand-response program
However, the need for large spaces for the TES system can be a challenge.
Utility-Owned and Operated Thermal Energy Storage
Another model for deploying TES which has become more popular is based on utility-ownership
and control. The utility-ownership model has been developed by Ice Energy, which makes the
“Ice Bear”, a packaged roof-top ice storage units that integrate with refrigerant-based (direct
exchange, or DX) roof top units (RTUs) commonly found in commercial cooling applications.
When called on by the utility, the Ice Bear will shut down the RTU compressor and condenser
1 https://www.irena.org/DocumentDownloads/Publications/IRENA-
ETSAP%20Tech%20Brief%20E17%20Thermal%20Energy%20Storage.pdf
2 https://www.cityofpaloalto.org/civicax/filebank/documents/38915
Attachment D
D-2
fans and provide cooling by sending ice-cooled refrigerant through a new evaporator coil
placed in series with the RTU’s existing coil.
Potential benefits of utility-controlled TES are:
- Resource adequacy cost reduction for the utility
- On-peak/off-peak energy purchase differentials
- Transmission and distribution deferral
- Control of additional Demand-Response assets
- Energy efficiency upgrade with TES installation
The value of TES is substantially lower in Palo Alto due to the milder climate and rather flat load
profile during the summer.
Update of 2013 study
Staff updated the 2013 model with the most current data of the system and utility cost and
confirmed that none of the TES systems considered makes economic sense currently. The
benefit-cost ratio is 0.39 for a full TES system and 0.7 for a partial TES system. A utility-
controlled Ice Bear program had a benefit cost ratio of 0.46.
Other TES systems
Heat pump or electric resistance water heaters for homes can also be used as TES. Water is
heated during off-peaks hours (either at night or with PV during the day) and then stored in a
tank for a later usage (see Figure D-1). As CPAU embarks on electrifying natural gas appliances,
it may want to evaluate the merits of encouraging customers to install controllable water
heaters that can be called upon by the electric utility to meet electric grid optimization needs.
Figure D-1: Load profile of traditional water heater vs. use during discounted rate periods
Water heated during discounted rate period
Attachment E
E-1
Energy Storage Regulation, Policies and Incentives
Energy Storage Regulations and Policies
California’s AB 2514 1 and the associated regulations are among many state policies designed to
encourage energy storage. In October 2013 the California Public Utilities Commission (CPUC)
established an energy storage target of 1,325 megawatts for Pacific Gas and Electric Company
(PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) by 2020, with
installations required by the end of 2024. The CPUC decision also establishes a target for
Community Choice Aggregators and electric service providers to procure energy storage equal
to 1% of their annual 2020 peak load by 2020 with installation no later than 2024, consistent
with the requirements for the Investor Owned Utilities (IOUs)2. On February 28, 2015, the three
IOUs (PG&E, SCE and SDG&E), filed their Energy Storage (ES) Application containing a proposal
for the first ES procurement period (2014-2016).3
In 2015, Oregon became the second state to approve energy storage targets. According to
House Bill 2193 4, electric companies with more than 25,000 customers will have to put 5 MWh
of energy storage in service by January 1, 2020, but it may not exceed 1% of the company peak
load (as of 2014). Laws promoting energy storage in New York and Texas have also been
passed, although these do not specifically require energy storage targets. Arizona, Connecticut,
Minnesota and Vermont added legislation that will clarify and promote storage.5 Washington
State gave $14.3 million in matching grants for utilities’ energy storage projects, and their 2015
budget included additional grants. Con Edison in NY offered $2,600/kW for thermal energy
storage (TES) and $2,100/kW for battery storage for projects completed by June 2016.6 New
Jersey offers $300 per kWh of storage capacity up to $300,000 or 30% of the project cost.7
Several states including Florida, New Jersey and Massachusetts offers loan and grants for the
development of resilient solar + storage systems.8 Other legislation indirectly supports the use
of storage systems in the case of rooftop solar installation. For example, Docket No. 2014-0192 9
in the state of Hawaii will support self-supply and benefit from temporal or locational energy
price differences with the use of batteries for rooftop solar owners. Hawaiian Electric Company
(HECO) issued an RFP for 0 to 200 MW of Energy Storage for Oahu in 2014.10
At the federal level, the Storage Act provide a 20% investment tax credit for grid-connected
energy storage systems and a 30% credit for behind-the-meter systems.11 The Federal Energy
Regulatory Commission (FERC) is also seeking to level the playing field for energy storage to
participate in energy markets. In 2007 and 2008, FERC issued Orders 890 and 719, which
1http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200920100AB2514 2http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M079/K171/79171502.PDF
3 http://www.cpuc.ca.gov/General.aspx?id=3462 4https://olis.leg.state.or.us/liz/2015R1/Downloads/MeasureDocument/HB2193 5http://www.renewableenergyworld.com/ugc/blogs/2016/01/state_energy_storage.html 6http://www.coned.com/energyefficiency/demand_management_incentives.asp 7 https://njcepelectricstorage.programprocessing.com/content/home
8 http://solaroutreach.org/wp-content/uploads/2015/09/SLStorage.pdf
9 http://puc.hawaii.gov/wp-content/uploads/2015/10/DER-Phase-1-DO-Summary.pdf
10 https://www.hawaiianelectric.com/clean-energy-hawaii/request-for-proposals---energy-storage-system
11http://www.energy.senate.gov/public/index.cfm/files/serve?File_id=FEDB4A77-7073-422D-B259-C8AF7F59E627
Attachment E
E-2
opened the door for non-generation resources such as energy storage to participate in ancillary
services markets. In response, CAISO made changes to its ancillary services operating and
technical requirements to enable these non-traditional resources to participate, such as
reducing the minimum size and output duration capability for eligible resources.12
In 2011, FERC enacted Order 755 specifically addressing frequency regulation services. As
described in Attachment A, some energy storage technologies are able to provide frequency
regulation services more quickly and accurately than conventional generating facilities;
however, markets for frequency regulation services typically do not differentiate between more
effective regulation providers. Order 755 attempts to rectify this by requiring appropriate “pay
for performance” in organized ancillary services markets. FERC notice proposes rules to reduce
other barriers that prevent energy storage facilities from participating in markets for ancillary
services as well as imposing similar “pay for performance” requirements on transmission
providers in traditionally regulated states. In July 2013, FERC issued Order 784 which eased the
market entry for third-part Ancillary Services providers and improved market transparency.
In response to FERC Order 755, CAISO modified the regulation up and regulation down product
in May 2013 with a market based mileage payment with accuracy adjustment.
Energy Storage Incentives and procurement activities in California
In 2009, the CPUC ruled that California’s IOUs must develop a Permanent Load Shift (PLS)
program to encourage TES directly. A statewide pilot PLS program from 2008-2011 provided
$500/kW of peak demand reduction. The current incentive for IOUs is $875 per kW of electric
load shift on the highest on-peak cooling load day of a customer’s annual cooling load profile.
The incentive is capped at 50% of project cost and $1.5 million per customer.
Customers of California’s IOUs are also eligible for the Self Generation Incentive Program
(SGIP), which includes a $1.31/Watt incentive to advanced energy storage systems.
California’s IOUs are also actively involved in energy storage project development to satisfy the
targets mandated by the CPUC. The first round of procurement RFOs was released in 2014 and
the next round of procurement will happen in 2016. The current progress of PG&E, SCE and
SDG&E has been summarized in Tables E1 and E2.
Most publicly owned utilities (POUs) declined to procure storage in 2014 for lack of cost
effective options. Seven POUs did set some procurement targets (see Table E3). Most POUs set
smaller goals, except the Los Angeles Department of Water and Power (LADWP). LADWP relied
mostly on a 21 MW pumped hydro upgrade to set its 2016 target, in addition to 3 MW of TES
systems. 2020 target includes 60 MW of TES at the generation level and 40 MW of TES at the
customer level, in addition to 50 MW of transmission level and 4 MW of distribution-level
batteries. Redding electric utility and Glendale Water and Power procured Ice Bear TES.
12 2020 Strategic Analysis of Energy Storage in California, 2011. Public Interest Energy Research for the CEC. CEC-
500-2011-047
Attachment E
E-3
Table E1: IOUs current projects and projects in development by storage technology
MW Li-Ion Zinc Sodium-
Sulfur
Flywheel PHS Thermal Other TOTAL
PG&E 42 13 6 20 10 91
SCE 246 16 26 69 357
SDG&E 20 40 19 79
Table E2: Storage location of current and in-progress projects and comparison to 2020 target
Current-in progress
(MW)/2020 target
(MW)
Transmission Distribution Customer Total
PG&E 50MW/310MW 33.5 MW/185 MW 8.2MW/85 MW 91 MW/580 MW
SCE 100 MW/310 MW 32.3 MW/185 MW 224.4 MW/85 MW 356.7MW/580 MW
SDG&E 60 MW/80MW 6.2MW/55MW 13MW/30MW 79 MW/165 MW
Table E3: 2016 and 2020 storage procurement target of the seven POUs who elected to
procure cost-effective storage