HomeMy WebLinkAbout2017-03-01 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 Meeting held on February 1, 2017
IV. AGENDA REVIEW AND REVISIONS
V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI. DIRECTOR OF UTILITIES REPORT
VII. COMMISSIONER COMMENTS
VIII. UNFINISHED BUSINESS
None
IX. NEW BUSINESS
1. Electrification & Building Codes Issues & Update Discussion
A. Discussion of Staff Plans to: (1) Suspend Additional Work on Evaluating the Discussion
Feasibility of Implementing Local Building Code Amendments to Mandate Heat
Pump Water Heaters and Space Heaters; (2) Continue to Implement Pilot Scale Customer
Programs for Heat Pump Water Heaters and Initiate a Pilot Program for Space Heaters
B. Colleagues Memo: Electrification or Fuel Switching (Schwartz & Ballantine) Discussion
2. Utilities Advisory Commission Recommendation That Council Approve an Update to Action
the City of Palo Alto’s Ten-Year Gas Energy Efficiency Goals (2018 to 2027)
3. Staff Recommendation that the Utilities Advisory Commission Recommend that the Action
City Council Adopt: (1) a Resolution Approving the Fiscal Year 2018 Water Utility Financial
Plan; and (2) a Resolution Increasing Water Rates by Amending Rate Schedules W-1
(General Residential Water Service), W-2 (Water Service from Fire Hydrants), W-4 (Residential
Master-Metered and General Non-Residential Water Service), and W-7 (Non-Residential
Irrigation Water Service) and Removing the Drought Surcharge
4. Staff Recommendation that the Utilities Advisory Commission Recommend that the Action
City Council Adopt: (1) a Resolution Approving the Fiscal Year 2018 Wastewater
Collection Financial Plan
5. Utilities Strategic Plan Performance Update (Fiscal Year 2016) Discussion
UTILITIES ADVISORY COMMISSION
WEDNESDAY, MARCH 1, 2017 – 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: Eric Filseth
6. 2017 Utilities Strategic Plan Update Discussion
7. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: April 5, 2017
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)).
Public Letter(s) to the UAC
Utilities Advisory Commission Minutes Approved on: Page 1 of 17
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF FEBRUARY 1, 2017 MEETING
CALL TO ORDER
Chair Cook called to order at 7:00 p.m. the meeting of the Utilities Advisory Commission (UAC).
Present: Chair Cook, Commissioners Ballantine, Forssell, Johnston, Schwartz, and Trumbull
Absent: Vice Chair Danaher and Council Liaison Filseth
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Commissioner Trumbull moved to approve the minutes from the January 11, 2017 UAC special
meeting and Commissioner Johnston seconded the motion. The motion carried unanimously (6-0)
with Chair Cook, Commissioners Ballantine, Forssell, Johnston, Schwartz, and Trumbull voting yes
and Vice Chair Danaher absent.
AGENDA REVIEW AND REVISIONS
Chair Cook announced that New Business Item #6 (Utilities Strategic Plan) would be moved to Item
#1 and that New Business Item #4 (Preliminary Financial Forecasts and Rate Changes for Electric,
Gas, Wastewater Collection, and Water Utilities) be moved to Item #2.
REPORTS FROM COMMISSION MEETINGS/EVENTS
Commissioner Schwartz discussed her attendance at the Smart Grid Consumer Symposium at
Distributech in San Diego, where she moderated a session on safely unlocking the value of
consumer data. Jesse Berst, founder of the Smart Cities Council, gave the keynote speech on the
intersection of smart cities and utilities. He spoke on distributed generation, renewables, smart
grid technology, and how smart building formed the keystone of these technologies. He
demonstrated a mobile application called DubaiNow that provided services she thought Palo Alto
residents would appreciate. She said the City of Fort Collins won the Utility Clear award from SGCC
for its Peak Partners program, which was a combined demand response and energy efficiency
program designed to reduce their peak load, and Efficiency Works, a regional program focused on
water and energy efficiency measures for homes and businesses. She spoke with a representative
of EPB, Chattanooga, Tennessee’s municipal utility. She confirmed that their fiber rollout had
primarily been to provide smart metering and smart grid services, and that providing cable and
telecom services had been a secondary benefit. The smart grid services had greatly improved their
reliability in the face of the weather issues they experience. The improved connectivity due to the
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 17
fiber system had attracted businesses. They were able to achieve 55% penetration in the cable and
telecom market due to the fact they had been underserved by major cable and telecom
companies. The EPB representative was not able to name any unusual or special benefits of fiber
connectivity to residents aside from the cable and telecom services. The smart grid services had
provided benefits to residents, including prepaid electricity services, which were popular with
renters. She was also working on an event in July for the National Town Meeting (Grid Evolution
Summit), and she was hoping to get other Commissioners or staff to attend.
UTILITIES DIRECTOR REPORT
Seeking Applications for the Silicon Valley Water Conservation Awards
The Silicon Valley Water Conservation Awards Coalition is seeking applications and nominations
for businesses, organizations, agencies and individuals who have demonstrated excellence in
water conservation. The City of Palo Alto Utilities is a coalition member and received the award for
Water Utility of the Year in 2014. This year’s deadline to submit an application or nomination
is Friday, February 3rd. Find details, link to application form and information on past award
winners at waterawards.org The Awards Ceremony will be held on World Water Day, March 22.
Please join us and recognize these heroes of our precious natural resource!
Impact to Water Supply Conditions Following Recent Rain
Storage in the Hetch Hetchy Regional Water System is essentially full due to the recent storms.
Governor Brown, however, has not declared an end to the drought, and the State Water
Resources Control Board is proposing to extend the Emergency Water Conservation Regulation
through the end of May 2017. A decision will be made February 7. The impact of extending that
regulation is negligible to Palo Alto as the City already has a “zero p ercent” state-mandated
conservation target and is on track to save more than 20 percent compared to the baseline year of
2013. The much-improved water supply situation may cause customers to wonder why the
drought surcharge is still in effect in Palo Alto. The surcharge was implemented to cover the
mostly fixed costs of operating the water system during a time when water sales, and thus
revenue, were low. A slight rebound in water sales is predicted, and reserve levels are healthy
enough that staff will recommend lifting the drought surcharge in July 2017.
Utilities Employee Wins Award for Winemaking
Congratulations to Utilities Supervisor John Reinert, who not only monitors and delivers millions of
gallons of high quality drinking water for the City by day, but also produces an award-winning wine
in his off-hours. When John isn’t working, he and his wife Stacy run Brilliant Mistake Wines, and
their Cabernet Sauvignon was the top red wine choice in a "friendly" competition at the NCPA
Strategic Issues Conference.
Art Rosenfeld, “Godfather of Energy Efficiency,” Passes Away
Art Rosenfeld, known unofficially as the “Godfather of Energy Efficiency” in the utility industry,
passed away last Friday at the age of 90. Over the span of the past four decades, Art has tirelessly
advocated for energy efficiency, from developing energy efficiency technologies for lighting and
windows, to persuading policymakers and utilities to invest in “negawatts” instead of power
plants. Art Rosenfeld was instrumental in helping the California Energy Commission adopt the
state’s Title 24 energy standards, which set the most stringent building energy code in the country.
California’s per capita energy usage has remained flat since the mid-1970s, whereas the rest of the
country has experienced a 50% growth in per capita energy usage. Palo Alto is a direct beneficiary
of this “Rosenfeld effect,” and the energy code and utility energy efficiency program tools that
Utilities Advisory Commission Minutes Approved on: Page 3 of 17
Palo Alto has used to keep its electric load flat or declining over the past few decades are largely
due in part to his efforts.
COMMISSIONER COMMENTS
None.
UNFINISHED BUSINESS
None.
NEW BUSINESS
ITEM 6: DISCUSSION: Utilities Strategic Plan
General Manager Ed Shikada presented on the Strategic Plan. Now was a good time to provide an
update, since the last update was in 2011. The key objectives for the current strategic plan were
safety and reliability, customer service excellence, cost manage ment, and environmental
sustainability. The plan used a “balanced scorecard” structure. It provided a good basis for the
next strategic plan. The next UAC update would provide an overview of the utility’s progress on
the 2011 strategic plan. The preliminary approach for updating the plan was expected to be to
identify key policy, program, and operating drivers, understand emerging issues, perform an
analysis of strengths, weaknesses, opportunities, and threats, and organizational needs, then
establishing strategic priorities and implementing actions. This was a conceptual plan, and staff
intended to release a Request for Proposals (RFP) for a consultant soon to assist with the process.
The goal was to complete the process by the end of December. Check-ins with the City Council
would happen early and late in the process, while check-ins with the UAC would happen
throughout the process. Keeping to the timeline was important to keep people engaged. Staff
engagement would also be critical to a successful process. He presented a sample of questions
that might be explored during the Strategic Plan update. Some addressed service reliability
objectives, some financial objectives, some related to the workforce, and others related to the
services the utility provided. He welcomed feedback on how the UAC would like to engage with
the process.
Chair Cook asked whether this could be a standing item. He felt it was important and looked
forward to working on it with staff.
Shikada said it would continue to be a standing item.
Chair Cook said it was important for the UAC to be engaged on this process and he was looking
forward to working on it with staff and the other Commissioners.
Commissioner Schwartz asked about the appropriate way to refer strategic planning consultants to
staff without creating conflicts of interest.
Shikada said to pass contact information to him and they would be informed of the RFP.
Commissioner Schwartz emphasized that the term “behavior modification” used in Shikada’s
sample questions was an industry term that was not intended to be nefarious, and was rather
intended to refer to providing information to customers.
ACTION: No Action.
Utilities Advisory Commission Minutes Approved on: Page 4 of 17
ITEM 4: DISCUSSION: Preliminary Financial Forecasts and Rate Changes for Electric, Gas,
Wastewater Collection, and Water Utilities
Acting Senior Resource Planner Eric Keniston introduced himself as the City’s Rates Manager. He
said staff would present the preliminary financial forecasts and rate changes for all utilities that
night. The formal rate recommendations and financial plans for the water and wastewater utilities
would be provided to the UAC in March, followed by the rate recommendations and financial
plans for the electric and gas utilities in April. He reviewed the reserves guidelines and various
reserves for the utilities, emphasizing that the key contingency reserve for all utilities was the
Operations Reserve. He said overall rate increases were expected to be slightly less than projected
last year. He reviewed the rate changes for the Electric, Gas, Water, and Wastewater utilities, and
showed the projected Refuse and Storm Drain rates as well, stating that the overall increase for
the average resident’s bill was projected to be five percent effective July 1, 2017. Future year bill
increases were projected to be three to five percent. This was lower than the previous year
projections, which had projected nearly a nine percent increase in customer bills in 2017.
Assistant Director of Resource Management Jonathan Abendschein emphasized that this was an
annual process where staff either recommended rate changes or that rates remain unchanged.
Keniston stated that the preliminary projection for electric rate increases was twelve percent in
2017 and nine percent in 2018. Reserves were low due to reduced hydroelectric output due to the
drought, which had resulted in increased costs. As a result, staff was recommending a short -term
loan from the Electric Special Projects Reserve to the electric utility’s Operations Reserve,
projected to be repaid within two years. He showed historical and projected costs and revenues
for the utility. Electric supply costs were increasing in FY 2017, then flattening out through the
forecast period. The increased costs were due to more renewable projects coming online as well
as increasing transmission charges from the California Independent System Operator (CAISO). The
City was also increasing its capital investment in the electric distribution system going forward.
Lastly, there were increases in operating costs, in part due to a contract staff had put in place to
complete maintenance work that was not being performed due to staff shortages. In addition,
after the July 1, 2016 rate increase, sales had decreased by roughly 5%, which was unanticipated,
leading to a decrease in revenues. This meant staff was projecting higher rate increases than
forecasted last year. He spoke about other long term uncertainties and projects that could affect
costs, including smart grid. Staff was also considering recommending adoption of a hydroelectric
rate adjuster to help manage volatility created by its hydroelectric resources.
Commissioner Schwartz asked, given the use of contractors for maintenance not performed due to
staff shortages, whether it would be more cost-effective to pay higher wages. She asked whether
staff had performed any sensitivity analysis on the issue.
Abendschein said pay was not the only thing creating the staff shortages. There were not as many
people coming in to the industry as there were leaving. All electric utilities were experiencing
these pressures.
Shikada said the City was not at the point where it had the capability to do these types of
sensitivity analyses yet. Staff recognized there was an issue. It was a challenge to reconcile the
Utilities Advisory Commission Minutes Approved on: Page 5 of 17
competitive environment faced by the utility portion of the workforce with the competitive
environment faced by the rest of the citywide workforce. The different markets created divergent
pay scales. It was an ongoing challenge that the City continued to struggle with.
Commissioner Schwartz asked whether the City had reached out to organizations like the Institute
of Electrical and Electronics Engineers (IEEE) that were working to bring students into the industry,
particularly women engineers.
Shikada said he was not sure how active the City was with IEEE, but the City was involved through
Northern California Power Agency (NCPA) and professional organizations.
Commissioner Schwartz recommended reaching out to the IEEE Power and Energy Society and
branching out beyond the California public power community.
Commissioner Forssell noted that in previous years staff had stated they were consciously drawing
down reserves, but now reserves were below their minimum guideline levels. She asked whether
this was intentional.
Keniston stated the plan was to draw down reserves, but to still keep them above minimum levels,
but various events, including sales decreases, led to the reserves ending below minimum levels.
Abendschein noted that there were multiple reserves. The Rate Stabilization Reserve had been
intentionally drawn down. The Operations Reserve and Hydroelectric Stabilization Reserves were
intended as contingency reserves for situations like the drought. These had been drawn down to
deal with the drought, as expected, but had ended up lower than expected due to other factors,
including the sales decreases.
Commissioner Ballantine noted that last year he had been surprised at how little latitude the UAC
had in designing rates once a cost of service study was completed. He had been surprised at the
different increases for different customer classes. He understood why, giv en that phenomenon,
those rate changes had been delayed as long as possible.
Chair Cook noted that outer year rate projections were uncertain.
Keniston confirmed that was the case. For example, if customer consumption patterns changed or
there was low rainfall, it could affect the forecasts. If there were changes in Capital Improvement
Program (CIP) costs, it could affect the forecasts.
Abendschein emphasized that the reserve projections shown in the presentation depended on a
short term loan from the Electric Special Projects reserve.
Keniston presented the preliminary projections for gas rate increases. He said that no rate changes
were proposed for the distribution portion of the gas rates, though changes in wholesale gas
prices and Pacific Gas & Electric (PG&E) transmission rates would be passed through to customers
through the commodity and transmission rate components as usual. One to three percent
increases to the overall gas rates were projected for the rest of the forecast period to pay for
cumulative increases in operating and capital costs. Capital spending was projected to be lower in
FY 2017 and FY 2018 due to a delay in gas main replacement. A side effect of the lower capital
Utilities Advisory Commission Minutes Approved on: Page 6 of 17
spending was the ability to phase projected rate increases in slowly over several years, leading to a
more gradual increase in rates as compared to last year’s forecast. Staff had seen some other
beneficial changes from the previous year forecasts, including increases in gas sales. He noted
uncertainties for the Gas Utility included the potential long term effects of building electrification
and uncertainty about the State’s cap and trade program.
Commissioner Schwartz said it was important not to present a policy of encouraging building
electrification as a foregone conclusion. She did not think the issues had been adequately
discussed. She asked whether staff could frame this as something to be discussed. She said gas
was a commodity that was decreasing in price, and that if it were a more efficient heating method,
staff should not assume it was a certain policy.
Keniston said staff had meant to portray it as an uncertainty and he had not included any building
electrification in the forecast.
Shikada said the point was well taken and that staff would make it clear tha t building
electrification was still a topic under discussion.
Keniston presented the preliminary projections for wastewater rates. Staff was proposing a 2%
increase to wastewater rates on July 1, 2017, with 5% to 8% increases in later years. This was due
to projected cumulative increases in operational and capital investment costs, combined with
increases in wastewater treatment costs. The increase in treatment costs was due to projected
increases in operations and maintenance costs at the Regional Water Quality Control Plant
combined with a major capital investment program to replace aging infrastructure at the Plant.
These costs were shared between the City and other agencies that were served by the Regional
Water Quality Control Plant. Reserves for the wastewater collection fund were adequate to phase
rate increases in more gradually than had been projected in last year’s forecast. This was because
no new sewer main replacement was planned for FY 2017 or FY 2018, since projects were being
delayed while projects currently in progress are completed.
Keniston then presented the preliminary projections for water rates. Staff was proposing a 6%
increase in water rates effective July 1, 2017, all of which would go toward an expected increase in
San Francisco Public Utilities Commission (SFPUC) wholesale water rates charged to the City.
Additional 6% rate increases were projected for subsequent years through FY 2022. The majority
of these increases were related to increasing wholesale water purchase costs due to the SFPUC’s
Water System Improvement Project (WSIP), a major rehabilitation of the regional water system.
Staff was planning to propose a pass-through rate for wholesale water costs to ensure annual
changes in wholesale water costs were passed through to customers accurately. Currently staff
relied on SFPUC estimates of wholesale costs for rate setting, which were frequently different
from the final wholesale rate adopted by the SFPUC. This meant that the difference between the
estimate and the final adopted rate affected reserves. A pass -through charge would eliminate that
discrepancy. He then stated that the water utility had seen decreased sales during the recent
drought, though sales were beginning to increase again. The utility’s reserves, however, had been
protected through the adoption of drought surcharges. Staff was planning to propose deactivating
these surcharges now that Palo Alto was no longer subject to drought restrictions. In addition, th e
utility’s reserves were benefitting from a delay in water main replacement. No projects were
planned for FY 2017 or FY 2018. As a result, the forecast was for water rates to increase more
slowly than had been projected in last year’s forecast, since rese rves could be used to phase rate
Utilities Advisory Commission Minutes Approved on: Page 7 of 17
increases in gradually. He discussed uncertainties in the projection. It was unclear how much
water consumption would rise after the drought. Costs for seismic rehabilitation of reservoirs and
the Foothills transmission line were still uncertain. And while the WSIP rehabilitated a significant
portion of the regional water system, there were still sections of the Hetch Hetchy system up in
the Sierras that had not yet been evaluated and could require investment in the future. Lastly, a
recycled water project was being evaluated, with uncertain costs and benefits.
Chair Cook stated there was no public comment.
Shikada said it was important to note staff was apprehensive about the increases in rates. While
staff approached its rate evaluations from an analytic point of view, they were conscious of the
impact of increasing rates on ratepayers.
Commissioner Trumbull noted that electric utility reserves were being replenished. He asked what
portion of revenue would go toward replenishing reserves.
Keniston noted revenues were below costs, so revenues were generally going towards paying the
costs of the electric utility. He did not know exactly what portion of revenues went towards
replenishing reserves.
Abendschein said it was important to note that reserves replenishment was not the primary driver
of the increases. The need to replenish reserves affected the pace of rate increases more than the
absolute size of the increases.
Commissioner Schwartz asked what feedback staff had been receiving from customers, and
whether staff tracked that feedback.
Keniston stated he had not personally received complaints.
Abendschein stated staff did not have formal reports on feedback. Informal feedback from
customer service staff was that the number of concerned customers was lower than in previous
years. Communication efforts had improved, and he suspected customers were more aware of the
reasons for the increases, such as infrastructure investment.
Shikada stated staff would bring back more specific information regarding customer responses. He
noted that decreases in demand were evidence of a customer response.
Commissioner Schwartz noted there was discussion in the trade press about how electric rates
across the country were dropping. We were in an unusual area, though Palo Alto’s rates were still
below PG&E’s.
Commissioner Ballantine asked whether the cost of service study would need to be redone
because of the rate increase.
Keniston said it would not. Generally you did not need to red o the cost of service study every year.
Commissioner Ballantine said that it was likely, then, that the rate increases for residential
customers would be higher than the rate increases for commercial customers.
Utilities Advisory Commission Minutes Approved on: Page 8 of 17
Keniston said that was not the case, that the changes would be very similar across all customer
classes.
Commissioner Ballantine asked whether the reference to Smart Grid in the presentation referred
to improved telemetry to avoid outages or whether it just referred to smart metering.
Assistant General Manager Dean Batchelor said smart grid efforts encompassed both types of
technology.
Commissioner Trumbull asked how responsive customers were to rate changes. He asked whether
changes in rates led to large changes in consumption.
Keniston said most utilities did not show major consumption changes in response to rate changes,
but the electric utility had seen a significant response as a result of the previous year’s rate
changes. That may have been because of how long it had been since the previous rate increase. In
addition, all utilities were on the same bill, and so changes in other utility rates can sometimes
affect electric usage.
Commissioner Trumbull asked whether there was a potential for a cycle in which efficiency could
drive price increases, which would then continue to drive further efficiency, to the point that it
adversely affected the financial position of the utility.
Shikada said the likelihood of this phenomenon creating a critical financial issue was low, at least
in the near term.
Commissioner Schwartz said electrification of vehicles created a beneficial new source of revenue
for the electric utility that was also beneficial to the customer and the environment.
Commissioner Forssell asked staff to confirm that electric usage had dropped six percent in the
previous year, and whether that had happened before. She asked whether there had been a
difference between residential and commercial reductions.
Keniston said electric usage had dropped before, but this was a larger decrease. All customer
classes had decreased consumption similarly, with slightly greater decreases for commercial
customers.
Commissioner Forssell asked whether there was any evidence that some of the decrease had been
related to efficiency rather than rate changes.
Keniston said he did not have an exact number. He expected the contribution from efficiency was
a small share of the decrease, but would bring more information back to the UAC.
Commissioner Forssell asked how large a rate increase would be needed to avoid a loan from the
Electric Special Projects reserve.
Keniston said he did not have that number, but it would be a much larger increase in the near
term followed by a decrease in a later year, since replenishing reserves was not an ongoing cost.
Utilities Advisory Commission Minutes Approved on: Page 9 of 17
Commissioner Forssell asked what the Electric Special Project Reserve was used for.
Keniston said it was for project approved by Council. The primary projects currently expected to
use Electric Special Projects Reserve funding were a second transmission line and smart grid
investments.
Chair Cook said it would be helpful to know what the demand assumptions were and to have
those communicated. He asked whether the equity transfer to the General Fund was included in
the forecast.
Keniston said those transfers were included in both the Electric Utility and Gas Utility forecasts.
Chair Cook asked staff to describe the transfers.
Abendschein stated these transfers were a return on the General Fund’s original equity
investment in the system. The transfers were based on a methodology adopted in 2009 and had
not been changed since then.
Chair Cook asked whether the transfers were projected to end in the future.
Abendschein said they were not, which was the same as any other return on an original
investment in an asset.
Chair Cook asked how that transfer related to cost of service.
Senior Deputy City Attorney Jessica Mullan said that when a cost of service analysis is done, the
transfers based on the previously adopted methodology are included in the analysis.
Commissioner Schwartz said it was a pretty typical transfer for a municipal utility.
Chair Cook said there were aspects of the transfer he did not understand, and wanted to get a
better understanding of it in the future.
Abendschein said it was a concept that had been discussed extensively between the UAC and
Council in the past.
Chair Cook said the idea of continuing these transfers when rates were increasing was difficult for
him to understand.
Commissioner Schwartz said she had not been hearing customer complaints about the transfer.
Mullan said it was important to remember that this was a transfer for a specific purpose based on
a well-defined Council-adopted methodology.
Abendschein said previous discussions between the UAC and Council had come to the conclusion
that this was a clearly defined part of the electric and gas rate structures.
Utilities Advisory Commission Minutes Approved on: Page 10 of 17
ACTION: No Action.
Chair Cook left the meeting at 8:30 p.m., after hearing Item 4, designating Commissioner
Ballantine as Acting Chair.
ITEM 1: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that
the City Council Adopt a Resolution Establishing Pledged Sources of Revenue for Repayment of
State Revolving Fund Loans for Wastewater Enterprise Capital Improvement Projects at the Palo
Alto Regional Water Quality Control Plant, and Repealing Resolution 9631
Assistant Director of Public Works Phil Bobel described the distinction between the Wastewater
Treatment Fund, which is managed by Public Works, and the Wastewater Collection Fund, which is
managed by the Utilities Department. The Collection Fund pays Palo Alto’s share of the costs for
the Treatment Fund, which is shared among a number of partner agencies. This issue was being
brought to the UAC due to a last minute request by the State that the City pledge the Wastewater
Collection Fund’s revenue as a condition of a loan the City was seeking for improvements to its
treatment plant.
Water Quality Control Plant Manager Jamie Allen said the City had a plan to replace the Regional
Water Quality Control Plant (RWQCP) incinerators with a sludge dewatering facility to enable
sludge to be transported for off-site processing. The City was seeking a $30 million loan from the
State for that project. The State loan provided a very low interest rate compared to a revenue
bond. The City was also seeking a $6.75 million planning and design loan for other plant
improvements. The City requested that the debt coverage for that loan be provided only from the
City’s Wastewater Treatment Fund. In 2007 and 2009, similar loans from the State required both
Wastewater Collection Fund and Wastewater Treatment Fund revenues to be pledged, so it was
not a surprise that the State denied the City’s request and required that the Wastewater
Collection Fund revenues be pledged as well. Council had previously approved a resolution
pledging only the Wastewater Treatment Fund revenues for repayment of this loan, s hould the
State grant it, and staff was requesting that the UAC recommend that the Council approve a new
resolution repealing the previous resolution and pledging the revenues of both the Wastewater
Treatment and Wastewater Collection Funds.
Bobel noted that the partner agencies had pledged repayment of their share of the debt service,
but regardless, the State required the pledging of the revenues from these City funds.
Allen noted that the contract for these improvements was in the process of being awarded.
Acting Chair Ballantine asked for public comments
Herb Borock, Palo Alto resident, said Palo Alto should not be the only agency pledging revenues
from their wastewater utility. The other partner agencies should have the same requirement to
pledge their net revenues.
Allen stated other partners had made contractual agreements for repayment with the partner
agencies to the satisfaction of the State.
Utilities Advisory Commission Minutes Approved on: Page 11 of 17
Commissioner Johnston clarified that this was not a request for additional funding, but rathe r a
request to pledge an additional revenue stream as collateral.
Bobel confirmed this was the case. For the State, the City’s enterprise fund setup, with separate
treatment and collection funds, was not something they commonly encountered. They looked at
Palo Alto’s sewer system as a single system, with both collection and treatment, rather than as
two separate systems. As a result, they requested that the City pledge the revenues from both
funds.
Allen noted the State would not provide the loan without this commitment.
Commissioner Forssell asked about Appendix F of the staff report. She noted the bonds were
junior to the 1999 bonds. She asked whether the Collection Fund had ever been called on to pay
for those bonds.
Allen confirmed that these bonds would be junior to the 1999 bonds.
Abendschein confirmed the Collection Fund had not been called on to pay for those bonds .
Commissioner Forssell asked what the revenue source was for repayment of these bonds.
Allen stated the revenue source was the contractual payments made by all partners in the RWQCP,
including the City.
Bobel stated that each partner paid a share of the operating and capital costs for the RWQCP,
including the City, and these revenues for the Wastewater Treatment Fund were used to pay the
debt service.
Commissioner Forssell asked whether the wastewater treatment and collection costs were
presented separately on customer bills.
Bobel stated they were not. There was only one charge for sewer service shown on the bill.
Abendschein confirmed that was the case.
ACTION: Commissioner Schwartz moved, seconded by Commissioner Trumbull to recommend that
the City Council repeal Resolution No. 9631 and replace it with a Resolution (Attachment 1 of the
staff report) pledging an additional source of revenue for the repayment of two State Revolvin g
Fund loans from the State Water Resources Control Board: one loan for design and construction of
the Regional Water Quality Control Plant sludge dewatering and load-out facility, and one for
planning and design of three additional projects: the laboratory/environmental services building,
primary sedimentation tank rehabilitation, and fixed film reactor rehabilitation projects. The
motion carried unanimously (5-0, with Acting Chair Ballantine and Commissioners Forssell,
Johnston, Schwartz, and Trumbull voting yes and Chair Cook and Vice Chair Danaher absent).
Utilities Advisory Commission Minutes Approved on: Page 12 of 17
ITEM 2. DISCUSSION: Amendment to Utilities Rule and Regulation 27, Generating Facility
Interconnections
Electric Engineering Manager Tom Ting gave a presentation on changes to Rule and Regulation 27.
This rule governs interconnection of generation facilities to the City’s electric distribution system.
The resolution amending the Rule was adopted by Council in December 2016. The Rule is
consistent with CPUC Rule 21 and with IEEE 1547. The goal of this revision effort was to streamline
the process and address review of solar interconnection applications and to complement the
streamlining the Development Center had adopted. In addition, the Division was also seeking to
become consistent with surrounding utilities (where it made sense for Palo Alto), to address
advances in technology, and to better define requirements, timelines, and the screening process .
Senior Electrical Engineer Mike Mintz described the significant changes to the Rule. This included
revisions to several sections, addition of Smart Inverter requirements, removal of Supplemental
review criteria, and addition of definitions to Rule and Regulation 2 (Definitions) that related to
changes in Rule 27. The “supplemental review” process in Rule 27 was removed to simplify the
Rule. Any issues that came up that would require supplemental review under the existing
procedures would be discussed directly with the applicant in the future instead of going through a
separate process.
Commissioner Schwartz asked if these changes only applied to roof top solar or if it also applied to
other types of generation.
Ting confirmed it would apply to all generation projects.
Commissioner Schwartz asked if would apply to the generator at the anaerobic digester and
whether there were any micro grids or black start generators in Palo Alto.
Ting confirmed it would apply to the anaerobic digester and there were no micr ogrids or black
start generators in Palo Alto.
Commissioner Ballantine commended staff for working to improve the interconnection process in
line with what other utilities in California had done with their processes. He said the revised rules
for inverters to conform to IEEE 1547 would improve grid resiliency by mitigating the chance that
solar inverters would shut off when the grid was experiencing temporary voltage problems. He
said there was also the possibility to integrate more advanced inverters that could provide grid
support.
ACTION: No Action.
ITEM 3. ACTION: Utilities Advisory Commission Recommendation That Council Approve the
Update on the City of Palo Alto’s Ten-Year Electric Energy Efficiency Goals (2018 to 2027)
Resource Planner Lena Perkins presented on the electric energy efficiency goals. She said one
important context for this goal setting exercise was the adoption of SB 350 in 2015. The legislation
required doubling of energy efficiency in the State of California. Utility energy e fficiency was only
one component of that doubling, and utilities with aggressive goals like the City had less room to
increase their energy efficiency goals. A computational model was used to assess program
potential. The 2015 model, as compared to the 2012 model, included high impact, low cost
behavioral programs. These new types of programs included training of facility managers and
Utilities Advisory Commission Minutes Approved on: Page 13 of 17
green building code adoption. Most savings were expected from commercial and industrial
customers as compared to residential customers. Most residential savings were likely to come
from behavioral programs. She showed the proposed goals compared to the previous goals. The
proposed goals were ambitious, a 20-30% increase over existing goals. There were a number of
new programs staff planned to use to achieve the goals. However, they were even more
aggressive considering the energy efficiency measures that could not be counted because they
were incorporated into Building Codes and Standards. She showed historical savings, noting t hat
2012 savings were particularly high due to a large data center project that was unlikely to be
replicated. She noted that the long term rate impact of the efficiency measures was roughly 5%,
but that the loss of revenue could be offset by increases in load due to electric vehicle adoption or
other load growth.
Commissioner Johnston asked about the rate impact why we were setting such aggressive targets
when we might be seeing negative load growth in the future.
Perkins replied that the state was considering setting EE goals for mid -sized POUs. Perkins also
stated that we were required to both collect funds to spend on EE and show that our EE programs
delivered real, cost-effective savings. She noted that any EE savings in City facilities would allow
the City to save money.
Abendschein added that EE savings could make room on the existing distribution system for load
growth such as increased EV charging. Abendschein also made the distinction between retail rates
and bills, as bills are projected to remain nearly flat while the retail rates may go up.
Commissioner Schwartz asked why we were setting such aggressive targets.
Perkins stated that the State was considering setting utility specific EE targets, and that these goals
might not be aggressive compared to those targets.
Commissioner Schwartz asked about the cost effectiveness of the City’s portfolio.
Perkins stated that staff was focused on creative, cost-effective programs. The portfolio as a
whole is projected to be cost-effective.
Commissioner Schwartz asked about the home energy reports, since many residents were
unhappy with the comparison to their neighbors.
Perkins replied that the Home Energy Reports had been discontinued two years ago, but that Staff
was working on a Behavioral Program centered around “carrots” and gamification in the form of
the potential residential Energy Lottery.
Commissioner Schwartz asked about the Program for Emerging Technologies.
Perkins responded that the Program for Emerging Technologies was housed within the Utilities
Department, and offered to send more information about the program.
Utilities Advisory Commission Minutes Approved on: Page 14 of 17
Commissioner Forssell asked about the Navigant energy efficiency model discussed in Attachment
A of the staff report. She referenced that the model was highly sensitive to the “Willingness and
Awareness value” used. She asked what value was used for Palo Alto.
Perkins said the values used were a bit stale but were in the process of being updated by the State.
There is also a question of how people actually behave around conservation, whether there is a
rebound effect or whether perhaps once people conserve in one area they view themselves as
conservation type people.
Commissioner Schwartz stated that she has seen people where they define themselves as “green”
and they want to do more and more conservation and environmental programs.
Commissioner Ballantine asked how EVs factored into these programs
Perkins stated EVs were not factored in. The CEC had recommended that these not be included.
Commissioner Ballantine asked how EVs were factored in to the behavioral programs. He noted
that his EV had made him get a bad score on his Home Energy Report.
Perkins stated the savings were based on actual measures installed according to a reporting
methodology. The City was only able to make savings claims based on rebates actually provided
and assumptions about the savings from that specific measure.
Commissioner Schwartz said this was a regular problem for measurement and verification,
particularly for education and marketing programs. She disclosed she was starting a measurement
and verification project with Navigant to do a project in Colorado, and asked the City Attorney to
let her know if she needed to recuse herself.
Commissioner Ballantine asked whether load increase from EVs would negatively affect the
savings the City could claim.
Perkins said that load increase from EVs or others would not affect those savings as the EE savings
will be reported in absolute energy savings numbers to the CEC.
Commissioner Schwartz recommended approval of the staff recommendation since any model is
inherently limited.
Perkins responded that a great deal of work and sensitivity analysis went into these recommended
goals, but that any model was limited by the quality of the data and the structure of the model.
Trumbull moved to approve the staff recommendation , Ballantine seconded staff
recommendation.
Passed 5-0
ACTION: Commissioner Trumbull moved, seconded by Commissioner Ballantine to recommend
Council approve the proposed annual and cumulative Electric Energy Efficiency Goals for the
period 2018 to 2027 as shown in the following table:
Utilities Advisory Commission Minutes Approved on: Page 15 of 17
Summary Table: Annual Electric Energy Efficiency Goals
(% of total City customer usage)
Electric
(%)
Electric
MWh
2018 0.75% 7,300
2019 0.75% 7,300
2020 0.80% 7,800
2021 0.80% 7,800
2022 0.85% 8,300
2023 0.85% 8,300
2024 0.90% 8,600
2025 0.90% 8,600
2026 0.95% 9,100
2027 0.95% 9,200
Cumulative
10-year EE Goal
5.7% 54,900
The motion carried unanimously (5-0, with Commissioners Ballantine, Forssell, Johnston, Schwartz,
and Trumbull voting yes and Chair Cook and Vice Chair Danaher absent).
ITEM 5. DISCUSSION: Property Assessed Clean Energy (PACE) Financing: Program History and
Future Considerations in Palo Alto
Staff Specialist Lisa Benatar presented on PACE financing. Many cities around the State authorized
PACE providers to provide service in their areas. The City has one PACE provider in its territory,
and a natural question was whether to expand the program. This presentation provides a high -
level overview of PACE financing. Benatar explained the basics of the PACE program. PACE was a
way for home owners to finance energy/water efficiency or renewable energy projects without
having to qualify for a traditional loan. California was the first state to become PACE enabled. The
players in the program were the property owner, contractor, PACE provider, and JPA. Cities
designate areas where willing property owners can enter into contracts with City officials to install
energy efficiency and renewable energy measures. The property owner’s credit rating was less
important than his or her history of paying property taxes, so the approval process can be simpler.
Once the contract is approved, the contractor does the work and the PACE provider pays the
contractor. The JPA issues bonds and the PACE provider sell s off the bonds to investors. The
property owner makes PACE payments on his or her property tax bill, and those funds flow to the
investors, who are repaid, with interest. PACE financing was developed in 2006-07, and in 2008 CA
passed AB 811 enabling the programs, and Palo Alto authorized CaliforniaFIRST to operate in Palo
Alto in 2009. PACE was intended to overcome the high up-front costs and long payback periods for
some energy efficiency and renewable energy measures, like solar. The benefits included the fact
that the PACE provider vets the contractors and loan approvals are easier, so it was expected that
more projects would be done. They would help cities achieve their GHG goals. PACE providers
would provide reports that cities could use. Authorizing multiple providers should bring interest
Utilities Advisory Commission Minutes Approved on: Page 16 of 17
rates down through competition, though that has not occurred. The downsides of PACE include
high interest rates. In addition, in Palo Alto it is difficult to find PACE-eligible measures that provide
enough savings to make PACE payments favorable. The biggest obstacle to PACE financing in Palo
Alto may be that PACE tax assessments are in a senior position relative to mortgages. PACE
programs paused in 2010 when the Federal Housing Finance Agency (FHFA) issued a statement
warning government lenders of the risks of providing loans for properties that had PACE tax
assessments. California attempted to sue the FHFA to resolve the problem and lost, so the State
subsequently instituted a State-wide mortgage loss reserve fund. This did not get the FHFA to
change its position, but it did help the uptake of the program. Some PACE providers began
agreeing to subordinate PACE liens, although this may not technically be possible, and there are
fees. In addition, legislation in 2016 provided some consumer protections. Thirty -five states are
now PACE enabled, though most PACE activity is still in California. In Palo Alto, with one PACE
provider, there have been 23 applications of which 21 were approved, but only 7 projects were
funded through the end of 2015. All projects were residential. There were various reasons why
uptake has been low. Income demographics are important. Palo Alto has a high medi an income.
20% have incomes below $50,000, while 62% have incomes above $100,000. High -income
customers are usually eligible for lower-interest financing like a home equity line of credit. Low-
income customers are eligible for the City’s Residential Energy Assistance Program (REAP), which
provides energy efficiency upgrades at no cost to the customer . In addition, 42% of Palo Altans are
renters rather than homeowners, including, most likely, many middle-income customers. Benatar
then gave some examples of the types of projects normally financed with PACE. In Menlo Park
eight of eleven PACE projects were solar projects. The most common PACE projects in general
were solar, HVAC, and roofing. HVAC was a low likelihood measure for Palo Alto, given the climate,
while roofing was not really something that was encouraged and did not necessarily count as an
efficiency measure. Solar was far more cost effective when financed as a leased system, or with a
home equity loan, or a loan from a solar provider instead of a P ACE provider, since the interest
rates were lower.
Commissioner Ballantine stated there was no public comment.
Commissioner Johnston asked what the cost was to the City for maintaining the PACE
infrastructure.
Benatar stated the cost was minimal.
Commissioner Schwartz asked whether there was any major staff time commitment.
Benatar stated there was not, unless there were some concerns that the PACE program was a
government sponsored program and that the customers asked the City to mediate problems with
a PACE provider.
ACTION: No Action.
ITEM 7. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting
General Manager Shikada stated the rolling calendar was busier than it had been in the previous
month. The Strategic Plan had been added as a standing item. He called attention to several
upcoming items, including the Financial Plans for the March and April meetings, an electrification
update in March, an update on Fiber to the Home in March, and a performance update on the
Utilities Advisory Commission Minutes Approved on: Page 17 of 17
2011 Strategic Plan in March. He also noted the Sustainability Implementation Plan discussion
coming up in April. This was a discussion of specific implementation plans for goals set in the
Sustainability and Climate Action Plan (S/CAP) recently adopted by Council.
ACTION: No Action.
Meeting adjourned at 9:53 p.m.
Respectfully Submitted,
Marites Ward
City of Palo Alto Utilities
1A
A
A
A
A
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: DEVELOPMENT SERVICES AND UTILITIES DEPARTMENT
DATE: MARCH 1, 2017
SUBJECT: Discussion of Staff Plans to: (1) Suspend Additional Work on Evaluating the
Feasibility of Implementing Local Building Code Amendments to Mandate Heat
Pump Water Heaters and Space Heaters; (2) Continue to Implement Pilot Scale
Customer Programs for Heat Pump Water Heaters and Initiate a Pilot Program
for Space Heaters
______________________________________________________________________________
RECOMMENDATION
Staff requests that Utilities Advisory Commission (UAC) discuss and provide input on staff’s plan
to: a) Suspend further work in evaluating the feasibility of implementing building code
mandates to require heat-pump water heating and heat-pump space heating/cooling
appliances in buildings and re-evaluate the feasibility of such a program within the next five -
years, no later than 2022, b) Continue undertaking heat-pump water heating and heat-pump
space heating pilot scale programs to encourage early adopters and reduce barriers to
customer adoption of such technologies. Staff anticipates providing an informational report to
Council in the Spring to update the Council on the UAC’s discussion.
EXECUTIVE SUMMARY
On August 2015, City Council approved a ten-point greenhouse gas reduction plan (the
“Electrification Work Plan,” Attachment B) prepared in response to a December 2014
Colleague’s Memo on electrification (Attachment A). The reduction plan focused on
electrification measures related to electric vehicles, and electric heat -pump based technologies
to replace water and space heating appliances in the community.1 As part of that effort,
Council directed staff to analyze the cost-effectiveness, market viability, and building code
impacts of a potential mandate to use heat-pump water heating (HPWH) and heat-pump space
heating (HPSH) for new and remodeled residentia l and commercial buildings (Task 4, subtasks
(a) and (b) of the greenhouse gas reduction plan). Council also directed staff to promote heat
pump technologies to homeowners as alternatives to natural gas water heating and space
heating and explore funding sources to offer customer rebates on heat pump appliances
(Task 1).
This report provides the findings from a feasibility study on the merits of mandating HPWH and
HPSH appliances in the building code. The analysis found that most scenarios for HPWH and
some scenarios for HPSH installation were not cost-effective. Further, the study results and
1 Since Palo Alto's electric supply is carbon neutral, electrifying gasoline vehicles and natural gas using appliances
would result in the elimination of GHG emissions from these vehicles and appliances.
Page A-2
staff experience found multiple market barriers (such as contractor inexperience) that would
make a mandate to install HPSH and HPWH at this time imprudent. Therefor e, staff does not
plan to devote any additional resources to evaluating building code mandates related to
electrification of natural gas appliances, but instead plan to continue the pilot scale customer
program efforts to lower adoption barriers and to encourage early adopters for the next five
years. The goal of these pilot-scale efforts would be to decrease barriers to the point that HPSH
and HPWH programs became cost-effective and more accepted in the market, potentially
paving the way for larger-scale incentive programs or requirements. Staff intends revisiting the
topic of building code mandates for electrification within five years.
This report also provides an update on the status of staff activities related to promoting HPWH
and HPSH to residents and reducing barriers. The report also describes staff's outreach to other
organizations/utilities with similar objectives, as well as equipment vendors and state
regulatory agencies to lower potential barriers to electrification by homeowners.
BACKGROUND
Palo Alto has made tremendous progress in lowering community greenhouse gas (GHG)
emissions since 1990. The GHG emissions in 2015 are estimated to be 36% below 1990 as
illustrated in Figure 1.
This GHG reduction is primarily driven by greening the electric supply and through energy
efficiency gains of appliances and automobiles. Of the remaining 0.5 million MT of GHG
emissions, about one fourth is related to natural gas related emissions from building and nearly
two-thirds from vehicle emissions (Figure 2).
Page A-3
To further drive down GHG emission via greater use of carbon neutral electric supply, in
December 2014 Council directed staff to explore electrification options for natural gas
appliances and automobiles through a "City Council Colleagues Memo on Fuel -Switching"
(Attachment A). In response to the Council directive, staff developed, and Council approved, a
ten-point work plan in August 2015. The work plan included evaluation and actions to
encourage the adoption of electric vehicles and high-efficiency electric heat-pump based
technologies to replace water and space heating appliances in the community (Attachment B,
Staff Report #5961). This work plan was incorporated in the Sustainability and Climate Action
Implementation Action Plan Framework approved by Council in November 2016 , and will be
incorporated in the detailed sustainability implantation plans to be presented to the UAC and
Council later this year. A brief update on the progress on the ten-point work plan is provided in
Attachment C.
This report will focus on two elements of the ten -point work plan. The first is Task 4, "analysis
of cost-effectiveness, market viability, and building code impacts of a potential man date to use
heat-pump water heating (HPWH) and heat-pump space heating (HPSH) for new and
remodeled residential and commercial buildings." The second element is Task 1, the promotion
of HPWH and HPSH in existing homes (Task 1). Since May 2016, Utilities has launched a HPWH
pilot program and related market place and regulatory outreach. A similar pilot for HPSH is
being planned for Fall 2017.
Note that this Staff Report does not analyze applicable legal or regulatory requirements that
may be a prerequisite or barrier to the adoption of local building code amendments to either
mandate HPWH or HPSH or eliminate natural gas connections in existing or new construction.
Page A-4
DISCUSSION
Overview of Evaluation of a HPSH and HPWH Mandate
A building code mandate to use HPSH and HPWH would require a local amendment to the
California Building Code and California Energy Code. The California Energy Commission (CEC)
requires that a cost-effectiveness study be conducted and filed in the case of a local
amendment to the California Energy Code. It is required that the City demonstrate to the CEC,
using a cost-effectiveness study, that the amendments to the code are financially responsible to
the commercial and residential applicants.
Staff conducted a formal bid process to select a consultant to conduct a cost -effectiveness
study. Staff selected TRC Solutions based on their ability to provide both residential and non -
residential services within the same study and their ability to meet the project timeline. TRC
Solutions performed the study using CEC-approved energy modeling software. The results of
this Palo Alto Electrification Study are located in this report (Attachment D).
Development Services staff convened an Electrification Task Force (ETF) composed of members
of the community with an interest in building electrification. The task force included residents,
architects, engineers, contractors, green building experts, energy modelers, advocates, and
staff. The task force met three times to review the electrification study outline and goals of the
study. The results of the study were distributed to the ETF for review and comment.
Results of the Cost-Effectiveness Study
The function of Task 4 within the Electrification Work Plan was to explore residential and
commercial building code changes for new construction and remodeling projects to expedite
electrification. The main focus of Task 4, subtasks (a) and (b), was to study the feasibility of
mandating HPSH and HPWH installations as part of the local Energy Reach Code set of energy
mandates. If the requirements were incorporated as a mandate, the regulation would be
embedded into the energy portion of the California Green Building “CalGreen” Tier system.
The Palo Alto Electrification Study assessed the electrification of space heating and water
heating, and potential ramifications on the electrical service to the building, such as larger
panel or branch circuit capacities. The scope included both a barriers analysis and a cost
effectiveness analysis for residential and nonresidential buildings.
During the first phase of the study, TRC collected data by engaging with the local building
industry through surveys and interviews with various electrification experts, including
contractors, engineers, architects, and energy consultants. Industry engagement helped
identify the technical specifications as well as costs for electrification. Online retailers and RS
Means, an industry cost estimation software, were also used to collect cost data and product
specifications. TRC then conducted building energy simulations to assess the potential energy
impacts of electrification equipment.
Cost-effectiveness is determined by assessing the incremental costs of each measure and
comparing them to the energy cost savings using the energy modeling simulations. The analysis
uses both a societal perspective, required by the CEC for a local mandate, and customer
perspective reflective of on-bill savings.
Page A-5
The cost-effectiveness of heat pump measures is summarized in Table 1. The measures are
analyzed based on Time Dependent Valuation2 of energy benefits, with cost effective outcomes
highlighted in green. TRC used Net Savings (benefits minus costs) a s the cost-effectiveness
metric for the study, since this is what would be required for a potential code mandate. If the
Net Savings of a measure is a positive value, the measure or package is considered cost
effective. For simplicity, the measures are identified in Table 1 as either “Yes” or “No”
representing if the measures are cost-effective. Additional cost effectiveness data can be found
in Attachment D.
Table 1. Cost Effectiveness Study Results: Answers to the Question, Is the Measure Cost Effectiv e?
(Based on Societal Net Savings using Time Dependent Valuation of Energy Methodology)
Building Type Construction
Type
Heat Pump
Water
Heater
Heat Pump
Space
Heater
Heat Pump Package
(Gas Connection
Remains)
All-Electric Package
(No Gas Connection)
Single Family New NO YES YES YES
Alteration NO YES NO NO
Low-rise
Multifamily
New NO YES NO YES
Alteration NO YES NO NO
Small Office New NO NO NO YES
Alteration NO NO NO NO
Medium
Office
New NO NO NO NO
Alteration NO - - -
The measures in Table 1 reflect an analysis of HPWH and HPSH both on an individual basis and
on a combined package basis. The “Heat Pump Package” assumes that both HPWH and HPSH
would be installed and that the gas connection would remain to the building. The “All Electric
Package” assumes that both HPWH and HPSH would be installed and that there would be no
natural gas connection to the building.
HPWH as a standalone measure is not cost effective, primarily due to the costly electrical
upgrades they require. HPSH is cost effective in residential buildings because the equipment is
less expensive than the standard split air conditioner with a furnace, and they are not likely to
require an electrical upgrade if an existing central air conditioner exists. The cost-effectiveness
study found HPSH to be cost effective in the case of single -family and low-rise multi-family
residential projects. Although the study showed no financial burden to building owner, staff
believes that there are too many market barriers at the present time to recommend a mandate
on the use of HPSH. The consumer demand for both HPSH and HPWH these appliances is still
relatively low and there are not enough options in the market to support all the diverse needs
presented by single-family and low-rise multi-family residential builders. Further, the
2 Time Dependent Valuation is metric used by the California Energy Code to value energy efficiency based on when
energy savings occur, reflecting the variations over time in the cost of energy production and delivery.
Page A-6
construction community is not yet equipped to handle the added demand that a mandate
would have on the industry. There is need for consumer education on how these systems work
and how the maintenance requirements differ from traditional gas fired appliances. Staff
recommends the continuation of education and outreach effort s and pilot programs to reduce
these barriers as discussed later in this report.
When HPSH and HPWH measures are packaged together, they are generally only cost effective
in new construction scenarios when assuming that there is no natural gas piping connected to
the building. Any costs associated with switching to electric cooking ranges and dryers were not
included in the analysis. Homeowners may continue to have need and preference to use gas
appliances for uses other than heating space and water. The heat pump alternative for those
uses are not readily available and can be cost prohibitive. Therefore, mandating that a building
not have a natural gas connection would be unrealistic.
In one scenario listed in Table 1, new residential single-family homes, a package of HPSH and
HPWH measures were cost-effective regardless of whether the natural gas connection
remained. However, staff still does not recommend mandating HPSH and HPWH in new single-
family homes due to a variety of market barriers. As mentioned above, based on feedback from
the ETF, consumers and the construction community are not yet equipped to manage the
burdens a mandate would impose. HPWH also presents specific technical challenges, such as
the need to have both electric and plumbing trades involved in the installation, and sewer
connections for condensate runoff. Continued consumer and contractor education through
pilot programs will help reduce these barriers.
As policies and rates change over time, electrification may become more cost effective for Palo
Alto in the future. Improved heat pump equipment that achieve s similar outlet temperatures to
gas equipment and avoids costly electrical upgrades in existing buildings is emerging. As these
products proliferate, market forces may drive down prices and improve the cost effectiveness
of electrification. Rising carbon prices could affect the analysis as well. There are many
assumptions built into the cost-effectiveness estimates, and minor variations may lead to
significant changes in results. The logistical barriers related to equipment installation may
become less significant in the future.
The ETF discussed the cost-effectiveness study and potential that the results may differ if
certain assumptions were to change in the future. For example, the results of the Palo Alto
Electrification Study could be impacted by a change in the electric or natural gas rate schedule.
The Next Steps section of this report discusses future efforts to monitor changes to these
assumptions and update the study when appropriate .
Eliminating Regulatory Barriers to HPSH and HPWH Installations
Another objective of Task 4 was to reduce code barriers to HPWH and HPSP. Many of these
barriers are associated with Title 24 compliance software modeling, which the CEC is working
toward addressing. Residential technical barriers predominantly relate to the lack of experience
from contractors and owners with HPWHs. These barriers are expected to dissipate with
increased penetration of HPWHs in the coming years. The commercial building industry is much
more familiar with heat pump systems, but market -ready HPSH may not yet be widely available
at a competitive cost for many high-temperature and high-capacity applications, such as heat
Page A-7
pump boilers or providing makeup air in restaurants. While TRC found some code, technical,
and operational barriers to HPWH and HPSH implementation, they are not insurmountable.
Heat pump technology is emerging and there is potential for increased adoption in Palo Alto.
As part of the study, Utilities and Development Services staff collaborated to seek permission
from the CEC to remove the requirements for individual building cost-effectiveness analysis
required to permit installation of HPWH when switching from a gas-fired water heater. This
type of analysis is a cost and time barrier to the building owner which hinders the installation of
a HPWH. As a result, the CEC released a simplified compliance pathway allowing the installation
of a HPWH as long as the appliance maintained a minimum energy factor (EF) of 2.8. The details
of the compliance pathway are outlined in the 2016 California Energy Code Residential
Compliance Manual, Chapter 9 found in Attachment E.
Development Services and Utilities staff worked together to develop both a permit phase and
inspection checklist containing the components for a permitting process and field inspection
protocol to support HPWH installations. These departments will remain in regular
communication to support continuous improvement of the checklist materials.
In 2015-16, as part of Development Services staff efforts to establish an Energy Reach Code,
staff explored potential scenarios to streamline the permitting process for projects pursuing
electrification. Staff found that the greatest barrier for project applicants is the CEC software
for showing compliance with the state California Energy Code and local Energy Rea ch Code.
Specifically, staff found that the software favors the pricing of natural gas compared to
electricity in the energy modeling process resulting in a benefit for gas-fired appliances. As a
result, projects pursuing an all-electric building had a more difficult time meeting the local
Energy Reach Code than a similar building using both gas and electricity. Due to this issue,
projects pursuing all-electric building designs are exempt from the local Energy Reach Code
requirements, reducing the barriers to projects pursuing all-electric new construction in Palo
Alto. This building code provision could have a significant positive impact in the adoption of
electric heat pump appliances in Palo Alto.
Promoting HPWH & HPSH in Existing Homes
Electric HPWHs have been commercially available for a few decades, but the technology has
remained a niche market due to reliability issues with early models and practical issues related
to replacing an existing natural gas water heater. In the past few years, leading water heater
manufacturers including A.O. Smith, GE, Stiebel Eltron and Rheem have introduced HPWH
models that are marketed as energy efficient alternatives to electric resistance water heaters,
with EFs that are typically higher than 2.03. As of January 2017, there are over 100 HPWH
models available in the market, with storage capacity between 50 to 79 gallons that are Energy -
Star rated.
Within Palo Alto, gas water heating accounts for over 90% of the single family residential
households.4 To promote HPWH among residents, Utilities staff developed a HPWH pilot
3 Energy Factor (EF) is the ratio of useful energy output from the water heater to the amount of energy input. A
typical electric resistance water heater has EF between 0.9 and 0.95. A gas tank water heater has EF of 0.6 to 0.8.
The latest HPWH models have EF that range from 2 to over 3.
4 It is estimated that 5-10% homes have inefficient electric resistive heating.
Page A-8
program to encourage residential customers replace their gas water heaters with HPWHs.5 Heat
pump appliances are much more efficient compared to electric resistance appliances and
natural gas appliances. In the case of water heaters, the efficiency of a HPWH can be 30% more
efficient that of a high efficiency gas tank water heater from a source energy basis. Replacing
gas water heaters with HPWHs also helps to reduce GHG emissions due to the carbon-neutral
electric supply in Palo Alto.
Following were the objectives of the HPWH pilot:
1. Promote energy efficient heat pump water heaters among consumers
2. Support market transformation within the supply chain
3. Streamline permitting process for both customer and building inspector
4. Gather customer feedback on retrofit process and performance of HPWHs
CPAU launched the HPWH pilot program in late spring 2016.
Preliminary Findings from the HPWH Pilot Program
Early results of the pilot program suggest substantial barriers exists that hinder the adoption of
HPWH in existing homes, even for highly motivated residents. From a contractor perspective,
replacing a gas water heater with an electric HPWH involves both plumbing and electrical work.
However, there are very few plumbers who are also licensed to do electrical work, and vice
versa. Among the licensed plumbers contacted by staff, very few are familiar with HPWHs or
stock these units for emergency replacement. From a customer perspective, a major inhibiting
factor is the upfront costs of replacing a gas water heater with a HPWH, especially for
households that need to upgrade their electric panel to accommodate a dedicated 30 amp
circuit for the HPWH. Also, the increase in electric consumption from operating a HPWH may
be charged at a higher electric rate tier, which may result in little or no overall utility bill
savings. Additional considerations for installing a HPWH unit include height/side clearance and
condensate management. Limited availability of HPWH units from distributors/retailers is also
an issue. Due to low demand, there are very few retailers that maintain an inventory of HPWH
units in their warehouse.
Coordinating with Industry Stakeholders
CPAU staff is currently coordinating with other entities such as Sacramento Municipal Utility
District (SMUD)6 and Northwest Energy Efficiency Alliance (NEEA)7 to facilitate wide-scale
adoption of HPWHs on a regional basis. NEEA in conjunction the Department of E nergy is
pursuing the goal of tripling the shipment of HPWH units in 2017 from 2016. Examples of
program ideas currently under consideration include: offering HPWH and rooftop Photovoltaics
(PV) as a bundled package, and outreach to corporations to allow u se of Flex Spending Account
dollars to pay for HPWH conversion, and offering free HPWH units to contractors to install in
5 The customer pilot program offers residents up to $1,500 for converting from a gas water heater to a HPWH. The
pilot website (www.cityofpaloalto/HPWHpilot) provides useful resources to homeowners as well as a cost-benefit
calculator.
6 SMUD currently offers $1,000 customer rebate for replacing electric resistance water heater with HPWH, and
$1,500 rebate for replacing gas water heater with HPWH.
7 NEEA works with 77 utilities in the Pacific Northwest to promote HPWH through both upstrea m and downstream
rebate programs.
Page A-9
their home/warehouse. Additionally, CPAU is planning a contractor training in May and will
include presentation by A.O. Smith, a leading HPWH manufacturer.
Planning for the HPSH Pilot Program
In parallel with promoting HPWH, CPAU is also gearing up to promote HPSH. Currently, a
homeowner who wishes to replace a gas furnace with an electric space heating system in their
home will need to provide Title 24 energy modeling results to demonstrate that the new
heating system uses less energy than the prescribed energy baseline. Title 24 energy
consultants typically charge $500 or more for this energy analysis. To remove this modeling
burden from homeowners who are considering electrification of the space heating system,
CPAU is partnering with SMUD with input from the California Energy Commission (CEC) to
undertake a modeling study. Results of the study will be used to develop the heat pump sizing
and efficiency criteria of a HPSP pilot program based on the home’s construction year, square
footage, and envelope characteristics (i.e. attic and wall insulation). CEC may also use the
results of study to develop a prescriptive pathway to for residential heat pump space heating
alteration projects so that energy modeling is no longer required. The study is expected to be
completed by summer of 2017, followed by the launch of a HPSH pilot program in fall of 2017.
The objectives of the HPSH pilot program will be similar to the HPWH pilot program.
As demonstrated in the TRC cost effectiveness study, HPSH and possibly HPWH are cost
effective for new construction projects. While Development Services recommends against
mandating electrification in the City’s green building code, the City can continue to promote
voluntary installation of HPWH, HPSH, and voluntary new construction of all-electric buildings
through rebates and customer outreach.
Pilot Funding and GHG Reduction Projections through 2020
CPAU is funding the HPWH and HPSH pilot programs as R&D initiatives using the electric public
benefit funds8. The current FY 2017 budget for the HPWH pilot program is $100,000, which
covers customer rebates, education campaigns/workshops, and industry collaboration. An
additional budget of $100,000 has been included in the FY 18 budget for HPSH pilot program.
Staff anticipates this level of funding will be sufficient for the next 3 years. If the pilot programs
demonstrate sufficient interests from the community in electrification projects, CPAU will need
to consider alternative funding source for electrification rebates.
Staff projects that the pilots can potentially facilitate the conversion of 200 to 300 units of gas
water heaters and 20 to 30 gas space heating systems by 2020. The estimated annual GHG
emissions reduction related to this electrification effort is estimated at 300 to 450 M T per year
by 2020, a 0.2 to 0.3% reductions of Palo Alto total emissions related to natural gas appliances.
UAC Input on Staff’s Plans and Next Steps
Based on study results and installation hurdles currently experienced, staff does not
recommend mandating the use of HPWH/HPSH equipment at this time. Staff plans, at some
8 Electric public benefit charge is a state mandated surcharge collected by utilities on electricity sales. The public
benefit funds can only be used for “public benefits” programs in four categories: (i) cost -effective demand-side
management services to promote energy efficiency and energy conservation; (ii) new investment in renewable
energy resources; (iii) research, development and demonstration projects; (iv) services provided for low -income
electricity consumers.
Page A-10
point over the next five years, revisiting the potential mandate with a sensitivity analysis of
changes to the original assumptions, as outlined in Attachment D, have changed, and to identify
the variables and modifications that could have the greatest impact of cost effectiveness.
Staff anticipates that there will be a few hundred such residential installations in the
community in the next five years, and at some time on or after 2022 would be an opportune
time to revisit the analysis on the merits of mandating such appliances through the building
code. If the cost effectiveness and technology environment merits such requirements, the
requirements to install HPWH/HPSH could be incorporated into the 2023 building code.
Staff plans to continue the pilot level efforts to encourage the use of HPWHs and HPSHs via
utility rebates and by lowering barriers for building owners to install this equipment.
In the meanwhile, staff will pursue efforts to study the reduction of greenhouse gas emissions
in existing buildings. The work plan on the broader category of implementing energy efficienc y
and electrification to lower greenhouse gas was part of the Sustainability and Climate Action
Plan (S/CAP) presented to Council in April 2016 and will be discussed in a forthcoming report on
S/CAP Implementation Plan (SIP) scheduled to go to City Council in the second quarter of 2017.
Staff will keep the Utility Advisory Commission informed of these upcoming approvals.
RESOURCE IMPACT
The staffing resources allocated to the electrification work plan were approved by City Council
on August 2015. Staff has expended about $145,000 in the cost-effectiveness evaluation and
code analysis from Council approved funds for Development Services. At such time that the
staff decides to update the building code related analysis and related sensitivity analysis, staff
will come back to the City Council with a budget amendment order and a proposed contract for
professional services.
The expenditure from Utility funds for pilot projects is approximately $40,000 at this time, but
in FY 2018 staff has budgeted $200,000 to continue implementing the HPWH and to launch a
HPSH related pilot. The budget would cover customer educational programs, appliance rebates,
supply chain related activities such as bulk-buy program, and collaboration with other entities
interested to promote electrification technologies. The funding source for this effort is the
Public Benefits Research and Development funds. Utility staff related effort related to the pilot
program this year and in the coming year is budgeted at 0.6 FTE with staff effort spread over a
few existing staff members.
POLICY IMPLICATIONS
This analysis implements Council policy direction on electrification in the attached
Electrification Colleague’s Memo, and fulfills various objectives of the Sustainability and Climate
Action Plan (S/CAP). Staff recommends further analysis of building code related policy on HPSH
and HPWH within five years, to coincide with the 2023 code cycle and the next S/CAP update.
These work items will also be incorporated into the sustainability implement ation plans to be
discussed with the UAC and Council at a later date.
ENVIRONMENTAL REVIEW
Discussion regardjng certain natural gas appliance electrification recommendations ~rom Staff
to: (1) suspend additional work on local building code amendments to mandate heat pump
water heaters and space heaters, with review of the issue by 2022; and (2) continue
implementation and initiation of pilot scale customer programs for heat pump water heaters
and space heaters does not meet the definition of a project under the California Environmental
Quality Act (CEQA), pursuant to Public Resources Code Section 21065.
ATTACHMENTS
A. 11 Clty Council Colleagues Memo on Fuel-switching" discussed at the December 14, 2014 City
Council meeting
B. City Council approved Ten-point Electrification Work Plan (Staff Report #5961)
C. Brief Update on Progress Related to the Ten-point Electrification Work .Plan
D. Cost-Effectiveness Study
E. CEC Memorandum Outlining Energy Factor (EF) Requirements for HPWH
PREPARED BY:
REVIEWED BY:
PETER PIRNEJAD, Director of Development Services
SHIVA SWAMINATHAN, Senior Resource Planner
CHRISTINE TAM, Senior Resource Planner
GIL FRIEND, Chief Sustainability Officer
}<-J~N ABENDSCHEIN, Asst. Director, Resource Management
L~· DEPARTMENT HEAD:
ED SHIKADA
General Manager of Utilities
Page f'-11
CITY OF PALO ALTO OFFICE OF THE CITY CLERK
December 15, 2014
The Honorable City Council
Palo Alto, California
Colleagues Memo From Council Members Berman, Burt, and Klein
Regarding Climate Action Plan Implementation Strategy to Reduce Use
of Natural Gas and Gasoline Through “Fuel Switching” to Carbon-free
Electricity
Requested Action by Council:
Direct the City Manager to prepare a report to the Council, outlining (1)
prospective programs and incentives that would result in the use of electrical
devices to replace those using natural gas, (2) possible building code changes to
require, where feasible, the use of electrical appliances rather than natural gas
appliances in the construction and renovation of residential and commercial
buildings, (3) possible changes to utility rate structures that would not penalize
fuel switching, (4) evaluation of additional strategies to support adoption of
electric vehicles. The report should consider and take into account applicable
legal requirements, and identify potential legal, code or regulatory barriers that
would need to be changed to facilitate fuel-switching. The City Manager will
return to the Council by the first meeting in February with an initial report to
Council on the timeframe required to research and develop this report, and the
staff and related resources that will be necessary, as this initiative would be an
important component in the 2015 Work Plan.
Discussion:
Starting in 2013 Palo Alto is one of the first cities globally to provide 100 percent
carbon-neutral electricity to all of our utility customers and at rates 20% below
PG&E. This is an important accomplishment, but only addresses approximately
1/5 of the greenhouse gas (GHG) emissions previously generated in the city.
However, our clean electricity resource provides an exceptional opportunity to be
ATTACHMENT A
Page 2
used as a clean energy foundation to reduce our other major GHG sources, in
support of the city’s Climate Action Plan.
The United Nations Intergovernmental Panel on Climate Change (IPCC), in its
latest report, again emphasized the dire straits we’ll all be in if government at all
levels doesn’t take far more significant steps to achieve large reductions in the
generation of greenhouse gases.
Building on our carbon-free electricity resource, key next steps for Palo Alto are to
promote switching from appliances and other devices that presently use natural
gas to devices that are powered by our clean electricity, and to support the
adoption of electric vehicles and other fossil fuel-free transportation alternatives.
Natural gas enjoys good press, but is in fact only marginally better than coal, in
part due to the high amounts of “fugitive” emissions which are unintentional
releases of harmful non-combusted methane gas that are emitted into the
atmosphere during natural gas extraction and delivery processes. Our carbon-
neutral electricity is far better for the environment and we therefore believe that
Palo Alto should take a series of steps to promote change from gas use to use of
electricity. Additionally, we should pursue more steps to support adoption of
electric vehicles powered by clean electricity, replacing use of petroleum, our
largest source of greenhouse gases.
This is a bold and significant initiative and given its “game-changer” potential,
warrants a thoughtful assessment of the opportunities and constraints this
presents and a clear identification of the resources and time commitment to
develop the report. Council recognizes that staff must first return with that initial
report on timeline and resource requirements by early February, as a prerequisite
to the Council’s direction to proceed with the actual research and report being
requested.
This report has been reviewed by the City Manager and City Attorney and has
incorporated their comments.
Page 3
Department Head: Beth Minor, Acting City Clerk
Page 4
City of Palo Alto (ID # 5961)
City Council Staff Report
Report Type: Consent Calendar Meeting Date: 8/17/2015
City of Palo Alto Page 1
Summary Title: Fuel Switching / aka Electrification
Title: Utilities Advisory Commission Recommendation to Approve Work Plan
to Evaluate and Implement Greenhouse Gas Reduction Strategies by
Reducing Natural Gas and Gasoline use Through Electrification
From: City Manager
Lead Department: City Manager
Recommendation
Staff and the Utilities Advisory Commission (UAC) request that the Council approve the
proposed work plan to facilitate electrification in Palo Alto.
Executive Summary
In December 2014, Council approved a Colleagues Memo directing staff to develop an initial
report on the resources and timeframe required to evaluate prospective fuel-switching1
programs and incentives for the community to reduce the use of natural gas and gasoline and
to electrify buildings and vehicles.
This report recommends a work plan with ten tasks to facilitate electrification in Palo Alto over
the next five years. An estimate of resource needs and time lines for each of the tasks is also
provided. Given the current state of technology, upcoming state regulations, and resource
constraints, the report also recommends tasks that can be deferred until a more opportune
time.
The UAC considered the work plan at its July 1, 2015 meeting and unanimously recommended
that Council approve the work plan.
Staff will communicate progress on the work plan to the Council as each task yields results or
when further Council direction is required. Staff will also provide a summary report on the
progress of each of the work plan tasks as part of the annual Earth Day Report. This work plan
1 The term fuel-switching is a general term that refers to changing the fuel for a given application or end use from
one source to another. This report focuses exclusively on electrification, which is a type of fuel-switching referring
to switching from any other fuel (here, fossil fuels) to electricity, which in Palo Alto is carbon-neutral.
ATTACHMENT B
City of Palo Alto Page 2
does not cover energy efficiency, renewable natural gas, or lo cal solar development, as these
activities already have robust programs and plans approved by Council2 and are not directly
related to the topic of electrification.
Background
On December 15, 2014, Council approved a City Council Colleagues Memo (Colleagues Memo)
that directed staff to develop an initial report on the resources and timeframes required to
evaluate four “fuel-switching”, or electrification, topics:
1) prospective programs and incentives that would result in the use of electrical devices to
replace those using natural gas;
2) possible building code changes to require, where feasible, the use of electrical appliances
in the construction and renovation of residential and commercial buildings;
3) possible changes to utility rate structures that would not penalize fuel -switching; and
4) evaluation of additional strategies to support the addition of electric vehicles.
On February 2, 2015, Council approved a two-phase work plan to prepare a report responsive
to the Colleagues Memo (Staff Report 5463). The first phase of the work plan is to determine
the scope of the analysis and identify any staff and/or consulting resources required to
complete it. The second phase involves detailed analysis of the measures identified in the first
phase and the development of an implementation plan. This staff report is the deliverable for
the first phase of the work plan; the second phase would be subject to Council approval of this
work plan.
The report draws from staff analysis on the current cost -effectiveness of various electrification
options for Palo Alto Utilities customers. The report also outlines the State’s analysis of
potential greenhouse gas (GHG) emissions reduction measures through 2030 in order to
provide context to Palo Alto’s own focus and work plan in the next five years. The report
includes a list of recommended projects for the next five years for Council consideration as well
as deferred projects, and the rationale for such prioritization.
Discussion
Existing Natural Gas and Gasoline Use Profile and Related GHG Emissions in Palo Alto
Vehicle fuel and natural gas usage account for more than 80% of Palo Alto’s direct fossil fuel
use and associated GHG emissions. Surface transportation related GHG emissions for Palo Alto
are estimated to be 335,000 metric tons of CO2e per year (MT/year), while natural gas use
accounts for 160,000 metric tons of GHG emissions per year.
2 Energy efficiency goals and performance (12/17/2012, Staff Report 3358); energy efficiency performance
(5/18/2015 staff report 5708); Local solar plan and goals (4/21/2014, Staff Report 4608 and Resolution 9402); and
PaloAltoGreen Gas program approval and alternatives analyzed (3/4/2014, Staff Report 4343).
City of Palo Alto Page 3
Figure 1: Natural Gas End-Use in the Residential(R) & Commercial (C) Sectors3
Figure 1 illustrates the estimated distribution of natural gas end -use in Palo Alto. Programs to
reduce natural gas use will need to target each of these end -uses. Space heating and water
heating are the two dominant natural gas end-uses, followed by cooking in the commercial
sector.
Analysis of GHG emissions reduction paths and targets by 2030 for California
With the state of California on track to meet the GHG emissions goal of reducing to 1990 levels4
by 2020, the Governor set a 2030 GHG emission reduction goal of 40% below 1990 levels 5. The
intent of the 2030 goal is to help guide policy and program development efforts that will enable
the achievement of the state’s 2050 GHG emissions reduction target of 80% below 1990 levels.
3 Based on state-wide estimates, adjusted to account for Palo Alto’s space heating profile.
4 This is equivalent to approximately 15% reduction from the peak statewide GHG emissions seen in year 2005.
5 It is worth noting that Palo Alto’s 2014 GHG emissions have already been reduced by approximately 37% b elow
1990 levels. These reductions only account for natural gas/electricity use, fossil fuel used for surface
transportation, and City operation; it does not account for other consumption related emissions.
City of Palo Alto Page 4
The California State Agencies’ PATHWAYS Project6 explored the feasibility and cost of a range of
GHG emission reduction scenarios and potential technology options in the future. The study
findings confirm that deep GHG emissions reductions will require significant progress in
multiple areas, such as achieving higher building efficiency, facilitating the rapid adoption of
zero emissions vehicles, increasing renewable electric supply, and encouraging fuel-switching of
water heating and space heating applications to low carbon fuels such as renewable electricity.
These findings are in line with the intent of the Colleagues Memo to explore ways to promote
electrification in Palo Alto, leveraging the City’s carbon-neutral electric supply.
Palo Alto’s Progress To-date to Facilitate Electrification
In addition to establishing a carbon-neutral electric supply portfolio, the City has undertaken
several measures and analyses in recent years in support of electrification, including:
x Implemented a time-of-use (TOU) electric rate pilot program to provide discounted
electric rates for night time charging of electric vehicles (EVs) at homes (2012, in
progress, plan to expand in 2016)
x Installed EV chargers in parking garages and librarie s; encouraging new development to
install public chargers7 (since 2010, on-going)
x Adopted a policy preference for an EV City Fleet, except where not feasible (2015)
x Modified the building code requiring new construction to be pre-wired for EV charging
equipment (EVSE) installation and to accommodate installation of PV systems (2014)
x Served as an information source for residents interested in purchasing EVs (since 2009)8
x Streamlined the approval of permits for EV chargers9 (2012)
x Completed analysis that found compact electric vehicles and heat pump water heaters
(HPWH) are currently the most cost-effective electrification measures in Palo Alto
homes10 (2013, updated in 2015)
Most recently, staff updated the analysis to estimate the cost and benefit of electri fication of a
new single family home in Palo Alto. Figure 2 summarizes the monthly net costs incurred by a
home for each electrification measure.
6 The PATHWAYS Project: Long-term Greenhouse Gas Reduction Scenarios is a study conducted by Energy +
Environmental Economics (E3), sponsored by the California Air Resources Board (CARB), California Public Utilities
Commission (CPUC), the California Energy Commission (CEC), and the California Independent Systems Operator
(CAISO). Study results from April 2015 can be found at this web link:
https://ethree.com/public_projects/energy_principals_study.php .
7 For example, the new development at 101 Lytton Avenue
8 For example the Cost Estimation Calculator for EV charging
http://www.cityofpaloalto.org/gov/depts/utl/residents/sustainablehome/electric_vehicles/ev_calculator.asp
9 Requests for EV chargers that have a charging capacity of less than 10kW are granted permits over the counter
10 See Staff Report 5971 in the August 17, 2015 Council Packet (previously presented as staff report to the UAC July
1, 2015: Results of the Cost-effectiveness Evaluation of Electrification Options for Appliances and Passenger
Vehicles in Single Family Residential Homes, and
City of Palo Alto Page 5
Figure 2: Monthly Net Cost of Electrification to Household
The analysis suggests that compact EVs are cost-effective compared to their gasoline
counterparts11. Switching from a standard gas water heater to an air -sourced water heater
(heat pump water heater, or HPWH) a household is estimated to save $4/month; switching to
heat pump space heating (HPSH) would incur a net incremental cost of about $2/month.
However, staff’s research suggests that there is some uncertainty in these results, based on the
wide variety of assumptions present in each of the scenarios examined. The accompanying line
for each measure illustrates the range of possible cost or benefit for different scenarios
examined; for example, switching to a HPWH could save as much as $10 per month or could
cost an extra $10 per month, depending on assumptions such as the future cost of gas versus
electricity. If all five measures are implemented, the potential monthly cost impact could range
from a cost of over $60 to a saving of about $60. HPWH and HPSH technologies12 are the
primary ways to energy efficiently electrify water heating and space heating end-uses, and
these applications account for approximately 75% of natural gas related GHGs in Palo Alto13.
For electrifying existing single-family homes, the study found the largest barrier is the upgrade
of electric panel capacity to accommodate t he increased electrical load; this upgrade alone
could cost $2,500 to $5,00014. In addition to this panel upgrade cost, costs associated with
11 On a Net Present Value (NPV) basis, net of federal and state rebates for electric vehicles.
12 An appliance made with air-sourced heat-pump technology use electricity to operate a heat exchanger to absorb
thermal energy from the atmosphere to heat water or building space.
13 Residential applications are estimated to account for 42% and commercial application 33% of natural gas-related
GHGs in Palo Alto.
14 The results in Figure 2 exclude any costs associated with the electrical panel, such as upgrading to a 200A or
400A service.
City of Palo Alto Page 6
running conduit and wiring to the appliance location could cost an additional $1,000 to $2,000
per appliance. These estimates emphasize that 1) new construction is a more cost-effective
intervention point; and 2) creative programs and initiatives will be required to help existing
homes to overcome the substantial additional up-front costs associated with electrification.
Staff expects to undertake a similar high level assessment of the cost effectiveness for
commercial building applications. An initial survey suggests that heat pump technologies for
water and space heating applications are feasible in small and medium sized commercial
buildings; in many of these smaller buildings, which account for about 40% of the square
footage of all commercial buildings in Palo Alto, HPSH applications are not uncommon, and
retrofitting smaller buildings with HPSH is relatively less burdensome. However, retrofitting
existing large commercial buildings for space heating applications is likely to be cost prohibitive.
Outline of Staff’s Recommended Work Plan and Tasks
Based on the insights gained from these initial analyses and projec ts, staff recommends
studying, and when feasible implementing, the ten tasks outlined below to promote
electrification. Tasks #1 and #2 are related to encouraging the use of HPWH and HPSH
applications in homes, which are largely cost effective in new residential construction, but face
barriers to entry in existing homes as discussed earlier. Many of the tasks include both
evaluation and implementation elements, but these three tasks are solely related to evaluation
of the feasibility of implementing project s and programs in the future:
x Task #4 (explore possible building code changes)
x Task #9 (explore new financing sources)
x Task #10 (explore feasibility of district heating options)
Estimates of timelines and resource requirements for each task are also provided in the list
below. Upon Council consideration and approval of an electrification work plan staff will seek
the additional resources needed as part of the annual or mid-year budgeting process.
The work plan does not cover energy efficiency, renewable natural gas, or local solar
development, as these areas have either already been analyzed and communicated to Council,
or are not directly related to the topic of fuel switching. For example, sourcing natural gas from
renewable sources was found to be expensive when evaluating the green-gas program options
in 201415. The City also has robust programs related to local solar and energy efficiency already
in place. This work plan also includes a list of projects that staff does not recommend analyzing
or promoting in the near term. This is either because these measures are clearly not cost -
effective at this time or because they are not prudent to promote now given limited staff
resources and upcoming changes in the State’s building standards and regulations.
15 PaloAltoGreen Gas Program alternatives analyzed (3/4/2014, Staff Report 4343) concluded that biogas at a cost
premium of 50 cents/therm is equivalent to approximately $94/ton of carbon dioxide equivalent (CO2e) compared
to offsets costing less than 10 cents/therm.
City of Palo Alto Page 7
For this work plan, each element will be considered in the context of all applicable legal,
statutory and regulatory requirements. Such requirements include, for instance, constitutional
limitations on the use of ratepayer funds imposed by Californians whe n they adopted
Proposition 26, obligations set forth in the cap-and-trade regulations adopted by the California
Air Resources Board, and other miscellaneous requirements embedded in the California Public
Utilities Code and Federal Energy Regulatory Commission rules.
Description of Work Plan Elements and Estimates of Timeline/Resource Requirements
1. Promote HPWH and HPSH in existing homes
a. Provide customers information on options and cost-effectiveness of HPWH and HPSH
solutions, including web-based calculator tools.
b. Explore funding source for HPWH and HPSH rebates for customers.
c. Inform and educate water heater installers about HPWH.
d. Explore mechanics and funding sources to incentivize installers to offer HPWH as a
default option in Palo Alto.
e. Explore the feasibility of implementing a HPWH bulk-buy program (possibly in
collaboration with surrounding cities).
f. Explore the feasibility and economics of retrofitting multi-family buildings that presently
have electric baseboard heating with HPSH appliances.
g. Explore the development of an analytic process that would enable staff to predict the
life expectancy of older water heaters, based on past building permit data, and use
those predictions to target promotion and installation of HPWH before natural gas
water heaters reach end of life or fail.
h. Time and Resource: This initiative is estimated to take 0.25 FTE and $10k over a 9 to 15
month period to explore various program options discussed above and to implement
items 1.a and 1.c. Existing resources could be channeled to undertake this task; no
additional budget approvals required by Council. Estimated completion date: December
2016.
2. Provide resources to homeowners to convert existing homes to all-electric homes.
a. Compile list of qualified architects, develop case studies, set up communication
channels for homeowners to share ideas and host workshops on electrifying existing
homes.
b. Explore the feasibility of new funding sources to provide incentives to electrify existing
homes on a pilot scale.
c. Time and Resources: This initiative is estimated to take 0.25 FTE staff time with an
additional expense of $15k for public outreach. Existing resources could be channeled to
undertake this task; no additional budget approvals required by Council. Staff will
evaluate customer incentives if new funding sources can be identified in Task #9.
Estimated completion date for Task 2.a is December 2016.
City of Palo Alto Page 8
3. Explore the development of retail electric rate schedule for homes that electrify
a. Evaluate an all-electric rate schedule for residential customers as part of the upcoming
electric cost of service analysis; if feasible, recommend such retail rates for Council
consideration and approval.
b. Time and Resources: 0.1 FTE and $25k consultant cost to evaluate cost of service and
retail rate options. Funds already allocated to this task; no additional budgets required.
Estimated completion date: July 2016.
4. Explore additional residential and commercial building code changes for new construction
and remodeling projects to expedite electrification
a. Study the feasibility of including HPWH installations as part of CalGreen Tier 1 and Tier 2
elective or pre-requisite criteria16.
b. Study feasibility of including heat pump space heating installations as part of CalGreen
Tier 1 and Tier 2 elective or pre-requisite criteria.
c. Study the feasibility of requiring sufficient electrical panel capacity and outlets to
accommodate the electrification of the house in the future.
d. Study and seek permission from the California Energy Commission (CEC) to remove
certain requirements that impede electrification (such as case-by-case cost-
effectiveness analysis) to permit installation of heat-pump based heating appliances.
e. Work with other interested parties to lobby CEC to consider carbon content (in addition
to energy efficiency) of building energy systems when updating building energy codes
for the January 2017 code update cycle.
f. Research and analyze the necessary components for a permitting process and field
inspection protocol to support electrification.
g. Explore potential scenarios for an expedited permitting program for projects pursuing
electrification.
h. Time and Resources: This effort is anticipated to take about 0.02 FTE of staff time and
$145k of consulting assistance, and would take approximately 12 months to complete.
This project has not been incorporated into staff’s existing work plan and will require
mid-year budget increase through the Budget Amendment Ordinance (BAO) process.
Estimated Completion Date: December 2016.
5. Evaluate utility connection fees and permitting fees associated with electrification projects
a. Analyze the cost of providing electricity connection upgrade services to homes. The
analysis will be based on estimates of number of future electrification projects.
b. Time and Resources: This effort is anticipated to take about 0.1 FTE of staff time and
$30k of consulting assistance for cost of service work. The effort related to this project
has already been included in staff’s work plan; no additional budget approvals required.
16 Calgreen Tier 1 and Tier 2 is the building code structure used for permitted building projects in Palo Alto under
Green Building Ordinance 5324. This structure enables Development Servic es to streamline the enforcement of
local amendments to the Green Building Code.
City of Palo Alto Page 9
Analysis (and if feasible implementation) could take 6-18 months with an estimated
completion date of Summer 2016.
6. Promote the installation and use of Electric Vehicle Supply Equipment (EVSE) for public use
and at multi-family homes17
a. Explore ways to overcome the inadequate supply of public charging facilities and
hurdles to installing chargers at multi-family dwellings in Palo Alto.
b. Explore if low carbon fuel standard (LCFS) credit revenue could be used to finance EV
charger installation projects.
c. Evaluate pricing policies for public EV charging stations.18
d. Time and Resources: Resources required to set-up the program is estimated at 0.1 FTE
at the start and 0.05 FTE for on-going effort. This effort is already included in the staff
work plan; no additional budget approvals needed. Funds available through the LCFS
program are estimated at $70k per year, but could range between $50k to $200k per
year over the next five years depending on the volume of credits and the market price
of the credits. Subject to Council approval to spend available LCFS funds to promote
such EVSE installations, the design of such incentive based promotion is expected to be
in place by Spring of 2016.
7. Explore offering Time-of-Use (TOU) electric rate options; for example, for residential EV
charging
a. A pilot TOU rates program is currently underway, to reduce EV charging cost at homes.
Early results show that the pilot TOU rates reduce costs by about $1/month and enable
the utility to claim LCFS credits. Staff is contemplating expanding the 150 customer TOU
rate pilot program to an additional 200 customers by July 2016
b. Explore offering TOU rates to all residential customers, including EV customers..
However, billing systems limitations and staff resource limitations may hinder this effort
in the short-term.
c. Time and Resources: This task may require manual processes in the absence of
upgrading the customer billing and smart grid systems. Staff resources of 0.5 FTE
allocated at present; no additional consulting help anticipated. TOU-capable electric
meters would cost $150 for each customer enrolled, or $30,000 if 200 additional
customers are enrolled in to current pilot program. No additional budget approvals
anticipated. Expected completion date is Summer 2016.
8. Explore opportunities to electrify existing and new City buildings
a. Explore opportunities to utilize HPWH and HPSH at existing City buildings
b. Explore opportunities to electrify space and water heating systems for new City
buildings
17 Note: Palo Alto building codes require new construction to install EV charging equipment (EVSE). The above
mentioned initiative is to encourage EVSEs installation at existing buildings.
18 This clarifying item was added after UAC review.
City of Palo Alto Page 10
c. Time and Resources: Staff will develop an inventory of existing water heater locations
suitable for replacement with HPWH by September 2015 and would replace gas water
heaters with HPWH at suitable locations over a period of time based on the age of the
existing water heaters. Replacement cost is estimated at $2,000 per water heater. T his
will be an ongoing effort; additional staffing resources needed are estimated to be
minimal at this time, so no additional mid-year budget requests anticipated. Projects
related to HPSH will be evaluated after the initial survey results.
9. Explore new financing sources to expedite electrification
a. Identify and evaluate the use of the City’s General Fund resources, voter approved
carbon fees/taxes, revenue-neutral fee-bates (such as fees on natural gas used to
incentivize reduction in natural gas through electrification projects, to the extent
consistent with constitutional mandates) and other financing options for electrification
projects and other de-carbonization strategies.
b. Timeline and Resources: Resources needed for an initial framing of this effort are
already included in the Sustainability and Climate Action Plan development process,
estimated at $5k. Additional detailed analysis, legal review, and other efforts will
require additional resources and is not recommended until after Council review and
adoption of the Sustainability and Climate Action Plan (S/CAP) and associated strategies
in late 2015. Initial framing of this effort will be presented to Council in Fall 2015.
10. Analyze, in a high level pre-feasibility study, options for district heating19 for buildings
a. Explore the feasibility of district heating options in the downtown area and the Stanford
Research Park area, with geothermal heat pumps or other heat-exchanger type
technologies, to reduce natural gas use in commercial buildings.
b. In the long term, this type of technology/project could assist in reducing natural gas use,
but initial analysis suggests it is not cost effective for a mild climate zone like Palo Alto.
c. Time and Resources: The effort is anticipated to be undertaken with intern as sistance
and input from Stanford Energy System Innovation (SESI) program staff. Resources may
also be needed including building energy monitoring equipment, staff effort of 0.25 FTE
over 2 years and funding of $50k. This task is not in the current work pl an and budget,
but if approved, resources will be allocated and sought as part of the annual budgeting
process in FY 2017. The task is projected to commence in 2017 and be completed by
2019.
All tasks outlined above will facilitate electrification in Palo Alto in the long-run, but will have
minimal reduction in GHG emissions in the short-term. However, if the community desires to
accelerate the adoption of electrification technologies well ahead of state regulations,
additional financial resources for customer cash incentives would likely be needed to
accomplish such goals. Currently, for example, staff anticipates Task #1 could result in the
replacement of approximately 1,000 HPWH in single family homes in Palo Alto by 2020.
19 District heating refers to systems that heat and/or cool a group of adjoining buildings using a central
heating/cooling plant.
City of Palo Alto Page 11
Similarly, several homes undergoing major remodels are opting to go all-electric, but at the
current rate the penetration of such homes are estimated to be well below 1,000 by 2020. If,
for example, 1,000 homes in Palo Alto go all-electric, the community’s GHG emissions
associated with natural gas use would reduce by approximately 2%.20
Tasks Recommended Deferred Until a Later Time
Staff recommends the following tasks be deferred until a later time:
A. Evaluate and implement bulk-buying program of EVs for Palo Alto residents: This activity
requires a relatively high level of effort and the value to customers is uncertain. Staff
recommends that we defer and consider the necessity and value of such a program after
2017 when 200+ mile range automobiles become prevalent in the mass consumer market.
B. Facilitate electrification of space heating in existing large commercial buildings: While
space heating with heat pumps is common in small/medium commercial buildings
(<50,000 square feet), it is burdensome to electrify space heating application f or existing
larger buildings > 50,000 square feet).
C. RECO/CECO Program: Should the community elect to study Residential and Commercial
Energy Efficiency Ordinance (RECO/CECO) as an energy efficiency implementation tool at
the time of real estate sale, electrification shall be studied as a potential element in such a
program.
Commission Review and Recommendation
The UAC reviewed the proposed work plan at its July 1, 2015 meeting. At the same meeting,
staff presented its analysis of the cost-effectiveness of electrification options for appliances for
new residential buildings and for EVs.
The work plan received universal support from the UAC, but one commissioner noted that work
plan item #7 should not refer only to EV charging at night since TOU rates coul d evolve and the
best time to charge EVs could actually be in the middle of the day when solar energy is
generating the most renewable energy. After discussion, the UAC voted unanimously to
recommend that Council approve the proposed work plan with the insertion of “for example” in
work plan item #7 so that it would read: “Explore offering Time-of-Use electric rate options; for
example, for residential EV charging.” (5-0 with Commissioners Cook, Danaher, Eglash, Foster
and Schwartz voting yes, Commissioner Hall absent). The notes from the UAC’s July 1, 2015
meeting are provided as Attachment C.
Resource Impact
Staff estimates that accomplishing these ten tasks will require approximately 1.6 FTE of staff
resources and $380,000 of consulting/equipment resources over the next two-to-three years.
Much of the staffing resources would come from current staffing and approved budgets, except
for Task #4 and #10, which will require additional budget approvals. In addition, if the
20 Staff notes that State legislative actions could result in a lack of recognition for the benefits from early action
and could have the effect of a higher standard and hurdle being applied to Palo Alto over other gas utilities.
City of Palo Alto Page 12
exploration in various tasks (e.g. Task #4, #9, #10) results in a recommendation to actually
implement programs, additional resources may be needed and staff would return to Council
with a request for additional resources. If Council approves a subset of the recommended ten
tasks or varies the scope of tasks, the resources required would change accordingly. Staff will
bring Council requests for any additional resources needed to undertake a Council approved
work plan part of the annual budgeting process, or when staff seeks mid -year budget
amendments.
Policy Review
This work was coordinated with the S/CAP process and meets the City’s goal of reducing GHG
emissions related to City and community activities.
Environmental Review
Researching and developing a community solar program does n ot meet the California
Environmental Quality Act’s (CEQA) definition of “project” under California Public Resources
Code Sec. 21065, thus no environmental review is required.
Attachments:
x Attachment A: Colleagues Memo Dec 15 2014 (PDF)
x Attachment B: Staff Work Plan 2/2/15 in Response to Colleagues Memo (PDF)
City of Palo Alto Page 13
x Attachment C: Excerpted Draft UAC Minutes of July 1, 2015 meeting (PDF)
x Attachment D: Public Letters to Council (PDF)
CITY OF PALO ALTO OFFICE OF THE CITY CLERK
December 15, 2014
The Honorable City Council
Palo Alto, California
Colleagues Memo From Council Members Berman, Burt, and Klein
Regarding Climate Action Plan Implementation Strategy to Reduce Use
of Natural Gas and Gasoline Through “Fuel Switching” to Carbon-free
Electricity
Requested Action by Council:
Direct the City Manager to prepare a report to the Council, outlining (1)
prospective programs and incentives that would result in the use of electrical
devices to replace those using natural gas, (2) possible building code changes to
require, where feasible, the use of electrical appliances rather than natural gas
appliances in the construction and renovation of residential and commercial
buildings, (3) possible changes to utility rate structures that would not penalize
fuel switching, (4) evaluation of additional strategies to support adoption of
electric vehicles. The report should consider and take into account applicable
legal requirements, and identify potential legal, code or regulatory barriers that
would need to be changed to facilitate fuel-switching. The City Manager will
return to the Council by the first meeting in February with an initial report to
Council on the timeframe required to research and develop this report, and the
staff and related resources that will be necessary, as this initiative would be an
important component in the 2015 Work Plan.
Discussion:
Starting in 2013 Palo Alto is one of the first cities globally to provide 100 percent
carbon-neutral electricity to all of our utility customers and at rates 20% below
PG&E. This is an important accomplishment, but only addresses approximately
1/5 of the greenhouse gas (GHG) emissions previously generated in the city.
However, our clean electricity resource provides an exceptional opportunity to be
Page 2
used as a clean energy foundation to reduce our other major GHG sources, in
support of the city’s Climate Action Plan.
The United Nations Intergovernmental Panel on Climate Change (IPCC), in its
latest report, again emphasized the dire straits we’ll all be in if government at all
levels doesn’t take far more significant steps to achieve large reductions in the
generation of greenhouse gases.
Building on our carbon-free electricity resource, key next steps for Palo Alto are to
promote switching from appliances and other devices that presently use natural
gas to devices that are powered by our clean electricity, and to support the
adoption of electric vehicles and other fossil fuel-free transportation alternatives.
Natural gas enjoys good press, but is in fact only marginally better than coal, in
part due to the high amounts of “fugitive” emissions which are unintentional
releases of harmful non-combusted methane gas that are emitted into the
atmosphere during natural gas extraction and delivery processes. Our carbon-
neutral electricity is far better for the environment and we therefore believe that
Palo Alto should take a series of steps to promote change from gas use to use of
electricity. Additionally, we should pursue more steps to support adoption of
electric vehicles powered by clean electricity, replacing use of petroleum, our
largest source of greenhouse gases.
This is a bold and significant initiative and given its “game-changer” potential,
warrants a thoughtful assessment of the opportunities and constraints this
presents and a clear identification of the resources and time commitment to
develop the report. Council recognizes that staff must first return with that initial
report on timeline and resource requirements by early February, as a prerequisite
to the Council’s direction to proceed with the actual research and report being
requested.
This report has been reviewed by the City Manager and City Attorney and has
incorporated their comments.
Page 3
Department Head: Beth Minor, Acting City Clerk
Page 4
City of Palo Alto (ID # 5463)
City Council Staff Report
Report Type: Consent Calendar Meeting Date: 2/2/2015
City of Palo Alto Page 1
Summary Title: Approval of Staff Work Plan in Response to Colleagues Memo
on Fuel Switching
Title: Approval of Staff Work Plan Developed in Response to the December
15, 2014 City Council Colleagues Memo on Climate Action Plan
Implementation Strategies to R educe Use of Natural Gas and Gasoline
through Fuel Switching to Carbon Free Electricity
From: City Manager
Lead Department: City Manager
Recommendation
Staff requests Council approval of its proposed work plan to prepare a report responsive to the
December 15, 2014 City Council Colleagues Memo (the “Colleagues Memo”) on measures to
encourage utility customers to switch from natural gas and gasoline to electricity where
appropriate and to reduce the obstacles to such fuel switching.
Executive Summary
On December 15, 2014 the City Council directed staff to return by the first meeting in February
2015 with an initial report on the resources and timeframe required to evaluate the four fuel
switching related topics outlined in a Colleagues Memo. Staff has already completed or
currently plans to undertake significant analysis of the potential for, and the economics of fuel
switching in various areas, as described more fully in Attachment B to this Staff Report.
Because the City’s major remaining greenhouse gas (GHG) emissions are related to mobile
transportation and the use of natural gas, fuel switching to the City’s carbon neutral electricity
supplies will also be a major element of the Sustainability and Climate Action Plan (S/CAP).
Staff is in the process of developing a detailed work plan with two phases to respond to
Council’s Colleague’s Memo. The first phase (Phase I) will determine the scope of the analysis
and identify any staff and/or consulting resources required to complete it. This phase is al ready
underway. Phase I will contain additional information to inform Council’s decisions about
whether to pursue or not pursue those actions related to fuel switching either identified initially
in the Colleagues Memo or in the Phase I analysis. Should Council elect to proceed, the second
phase (Phase II) will involve detailed analysis of proposed actions and measures identified in the
Phase I and the development of an implementation plan. Phase I will be undertaken in
City of Palo Alto Page 2
coordination with the S/CAP, and staff is currently planning to deliver it to Council around the
same time as the S/CAP in the Spring of 2015.
All measures and actions proposed as part of Phase I and Phase II must be specifically analyzed
and considered in the context of all applicable l egal, statutory and regulatory requirements,
including, for instance, constitutional limitations on utility rates and use of ratepayer funds
imposed by Californians when they adopted Proposition 26, obligations set forth in the Cap-
and-Trade regulations adopted by the California Air Resources Board, and other miscellaneous
requirements embedded in the California Public Utilities Code.
Background
The December 15, 2014 Colleagues Memo (Attachment A) directed staff to prepare a report,
outlining:
1) prospective programs and incentives that would result in the use of electrical devices to
replace those using natural gas;
2) possible building code changes to require, where feasible, the use of electrical
appliances in the construction and renovation of residential and commercial buildings;
3) possible changes to utility rate structures that would not penalize fuel switching; and
4) an evaluation of additional strategies to support the addition of electric vehicles.
Staff has already completed or commenced several activities related to fuel switching. These
are summarized below, and are described in more detail in Attachment B:
x On February 10, 2014, staff presented an analysis of the cost -effectiveness of replacing
residential natural gas fired appliances with electric appliances, given existing
technologies and rate structures.1 The analysis also addressed the cost-effectiveness of
converting from gasoline-fueled vehicles to electric vehicles (EVs). An update to this
analysis is already underway and is currently scheduled to be presented to the Utilities
Advisory Commission (UAC) in Spring 2015.
x Staff is currently doing the preliminary research to begin a cost of service analysis
(COSA) for the electric utility, which will evaluate if there are any rate design obstacles
to fuel switching. Prior to the conduct of the Electric COSA, the UAC and Council will
have an opportunity to discuss the possible rate designs and the issues to be considered
when choosing between them. The timeline for this policy discussion is in the s pring of
2015.
x After Council adopted the City’s EV policy2 in December 2011, staff undertook a variety
of programs to encourage wider adoption of EVs in Palo Alto, one of which was the
adoption of and EV ordinance that requires all new residential an d non-residential
1 Staff Report # 4422, dated 2/10/2014: www.cityofpaloalto.org/civicax/filebank/documents/38922
2 Staff Report 2360, dated December 19, 2011: http://www.cityofpaloalto.org/civicax/filebank/documents/41528
City of Palo Alto Page 3
construction to install new EV chargers and/or needed infrastructure to accommodate
future chargers as seen in Municipal Code Section 16.14.370.
Discussion
The Colleagues Memo suggests consideration of a more comprehensive evaluation of fuel
switching in the context of the long-term S/CAP goals to dramatically reduce GHG emissions.
Staff’s proposed work plan for this effort is divided into two phases:
Phase I, already in progress, is to develop a detailed scope to address each area of focus
identified in the Colleagues Memo, including identification of potential measures or strategies
that would address requests 1 (outlining prospective programs and incentives), 2 (outlining
possible building code changes) and 4 (evaluation of additional strategies to support adoption
of electric vehicles) in the Colleagues Memo. In Phase I:
x Staff intends to use the ideas, work products, and community input from the S/CAP
process to help inform its work in Phase I. In turn, the Phase I scoping work will
contribute to the analysis of fuel switching for the development of the S/CAP.
x The deliverable for Phase I will be a report setting forth a project scope and timeline for
completion of Phase II (should Council elect to pursue it), including a list of potential
programs and incentives, building code changes, gas and electric rate options that may
be available, and potential additional strategies to encourage EVs. The Phase I report
will identify the tasks and timeline needed to analyze the cost implication to applicants
being affected by any mandates, to identify and assess any constraints that may exist
(including any imposed by legal, statutory or regulatory requirements) and other items
to be determined in the course of Phase I.
x Staff may provide alternative approaches to Phase II requiring differing levels of effort
and expenditure of resources, since the Phase II report could require considerable staff
effort.
x Staff currently anticipates that Phase I will be completed and will roughly coincide with
the completion date of the S/CAP in spring 2015.
Phase II, should Council elect to proceed with it after considering Phase I, will involve a more
detailed cost/benefit analysis along with more comprehensive policy and legal evaluations of
the options outlined in Phase I, particularly for request 3 (possible changes to utility rate
structures that would not penalize fuel switching) of the Colleagues Memo. In Phase II:
x Staff will coordinate this effort with the Electric COSA, including analysis of the impact of
various rate designs on fuel switching and any legal, regulatory, cost-effectiveness or
City of Palo Alto Page 4
other barriers that may impose constraints on using rates as a tool to implement or
otherwise incentive fuel switching.
x The deliverable for Phase II will be a report that can be used as a basis for accepting or
rejecting each option.
Because there is substantial work needed to develop a timeline and assess required resources
to look at the issues raised in the Colleagues’ Memo, staff plans to return to Council in Spring
2015 with the Phase I report (the more detailed scope and timeline) to inform Council’s
determination on whether staff should proceed with the Phase II effort. Council should be
aware that work activities related to fuel switching will be an integral part of the S/CAP.
Resource Impact
Completion of the Phase I report will require a total approximately 0.2 FTE per month of staff
time over three to four months from the following City departments: Sustainability, Utilities,
Development Services, Public Works, Planning and Community Environment and City Attorney.
The proposed Phase I scoping report can largely be completed with existing resources.
The level of effort, inclulding staffing and calendar time, needed to complete the Phase II work
will be identified in the Phase I report. Any additional resources needed, or existing or planned
work products that must be delayed to complete Phase II will be identified in the Phase I report
as well.
Policy Implications
This project will be coordinated with the S/CAP process and will provide data to support
decision making about possible programs to implement any carbon-reduction goals the Council
adopts as part of that process.
Environmental Review
Approval of staff’s proposed work plan for addressing the Colleague’s Memo on fuel switching
does not meet the definition of a project pursuant to section 21065 of the California
Environmental Quality Act (CEQA).
Attachments:
x Attachment A: Colleagues Memo Dec 15 2014 (PDF)
x Attachment B: Fuel Switching Work Plan - Colleagues Memo (DOC)
CITY OF PALO ALTO OFFICE OF THE CITY CLERK
December 15, 2014
The Honorable City Council
Palo Alto, California
Colleagues Memo From Council Members Berman, Burt, and Klein
Regarding Climate Action Plan Implementation Strategy to Reduce Use
of Natural Gas and Gasoline Through “Fuel Switching” to Carbon-free
Electricity
Requested Action by Council:
Direct the City Manager to prepare a report to the Council, outlining (1)
prospective programs and incentives that would result in the use of electrical
devices to replace those using natural gas, (2) possible building code changes to
require, where feasible, the use of electrical appliances rather than natural gas
appliances in the construction and renovation of residential and commercial
buildings, (3) possible changes to utility rate structures that would not penalize
fuel switching, (4) evaluation of additional strategies to support adoption of
electric vehicles. The report should consider and take into account applicable
legal requirements, and identify potential legal, code or regulatory barriers that
would need to be changed to facilitate fuel-switching. The City Manager will
return to the Council by the first meeting in February with an initial report to
Council on the timeframe required to research and develop this report, and the
staff and related resources that will be necessary, as this initiative would be an
important component in the 2015 Work Plan.
Discussion:
Starting in 2013 Palo Alto is one of the first cities globally to provide 100 percent
carbon-neutral electricity to all of our utility customers and at rates 20% below
PG&E. This is an important accomplishment, but only addresses approximately
1/5 of the greenhouse gas (GHG) emissions previously generated in the city.
However, our clean electricity resource provides an exceptional opportunity to be
Page 2
used as a clean energy foundation to reduce our other major GHG sources, in
support of the city’s Climate Action Plan.
The United Nations Intergovernmental Panel on Climate Change (IPCC), in its
latest report, again emphasized the dire straits we’ll all be in if government at all
levels doesn’t take far more significant steps to achieve large reductions in the
generation of greenhouse gases.
Building on our carbon-free electricity resource, key next steps for Palo Alto are to
promote switching from appliances and other devices that presently use natural
gas to devices that are powered by our clean electricity, and to support the
adoption of electric vehicles and other fossil fuel-free transportation alternatives.
Natural gas enjoys good press, but is in fact only marginally better than coal, in
part due to the high amounts of “fugitive” emissions which are unintentional
releases of harmful non-combusted methane gas that are emitted into the
atmosphere during natural gas extraction and delivery processes. Our carbon-
neutral electricity is far better for the environment and we therefore believe that
Palo Alto should take a series of steps to promote change from gas use to use of
electricity. Additionally, we should pursue more steps to support adoption of
electric vehicles powered by clean electricity, replacing use of petroleum, our
largest source of greenhouse gases.
This is a bold and significant initiative and given its “game-changer” potential,
warrants a thoughtful assessment of the opportunities and constraints this
presents and a clear identification of the resources and time commitment to
develop the report. Council recognizes that staff must first return with that initial
report on timeline and resource requirements by early February, as a prerequisite
to the Council’s direction to proceed with the actual research and report being
requested.
This report has been reviewed by the City Manager and City Attorney and has
incorporated their comments.
Page 3
Department Head: Beth Minor, Acting City Clerk
1
Attachment B:
5463 - Fuel Switching Work Plan
Colleagues Memo
Outline of Initiatives Currently Underway to Facilitate Fuel Switching
1) Residential Natural Gas to Electric Fuel Switching Analysis: In February 2014, staff provided
Council an evaluation of the cost effectiveness of residential natural gas-to-electric fuel
switching options for appliances and vehicles.1 The analysis concluded that residential
natural gas-to-electric fuel switching is not cost-effective at prevailing energy prices and the
prevailing cost of carbon, but could become cost effective at carbon costs of $130/ton for
water heating and $270/ton for space heating applications. The report also concluded that
fuel switching for water heating applications for new construction or during major remodels
may also prove to be cost effective. The analysis found that purchasing carbon-offsets was
the least cost option to neutralize greenhouse gas (GHG) emissions related to natural gas
use. This analysis is being updated at present and is expected to be presented to the
Utilities Advisory Commission by Spring 2015.
With respect to fuel switching from gasoline-fueled automobiles to electric vehicles (EVs),
the analysis found that purchasing EVs can be more cost-effective than buying new gasoline
vehicles. Leasing EVs may provide additional cost advantages. The analysis did not review
natural gas to electricity fuel switching options for commercial buildings nor look at possible
changes to building codes to encourage fuel switching.
2) Utilities Cost of Service Studies: Staff is undertaking an electric utility cost-of-service
analysis (COSA) in 2015 to evaluate different electric rate making options and has begun the
initial preparations for that study. The primary focus of the Electric COSA will be on
ensuring that electric rates are equitable and represent the cost of service to customers, but
the report will also identify the impact of current and proposed rate structure options on
fuel switching, including the impact of tiered rates. Other issues to be considered as part of
the Electric COSA include:
x the impact of current and proposed rate designs on t he economics of rooftop solar,
x the impact of rate designs on low-income customers,
x the impact on energy efficiency (“conservation pricing”), and
x the possibility of introducing time-of-use rates.
Any proposed rate designs must be specifically analyzed and considered in the context of all
applicable legal, statutory and regulatory requirements and guidance, including, for
instance, constitutional limitations on utility rates imposed by Californians when they
adopted Proposition 26, obligations set forth in the Cap-and-Trade regulations adopted by
the California Air Resources Board, and other miscellaneous requirements embedded in the
California Public Utilities Code
1 Staff Report 4422 dated 2/10/2014. https://www.cityofpaloalto.org/civicax/filebank/documents/38922
2
A Gas COSA was completed two years ago and no changes to gas rate structures are
planned at this time. Starting in 2015, the City’s gas utility must participate in the State’s
GHG cap-and-trade program. On January 20, 2015, the Council adopted changes to the
City’s gas rates to include the cost of GHG allowances the City must purchase for the gas
utility in the State’s cap-and-trade auction (Staff Report 5397). Therefore, gas customers
will be paying for GHG emissions associated with their gas usage through their gas rates.
3) Encouraging Electric Vehicle Adoption: In December 2011 Council adopted an EV policy2,
which identified goals and projects. Since then, staff has undertaken a variety of programs
to encourage wider adoption of electric vehicles in Palo Alto, and is working on additional
programs. EV charging stations have been installed in three City-owned garages as well as
other City buildings. Utilities implemented the CustomerConnect program, an advanced
meter pilot program that was open to EV owners to test time-of-use electric rates to
encourage owners to charge their EVs in the less costly “off -peak” hours. Utilities also
applied to the California Air Resources Control Board (CARB) to receive credits through
CARB’s Low Carbon Fuel Standard (LCFS) program. The LCFS program is expected to provide
credits to Palo Alto worth $50,000 in 2015 to $100,000 in 2020. Staff is developing a
recommendation on how to spend the LCFS credits, which must be spent in a way to benefit
EV owners. Ideas include reducing the cost of electrical service upgrade fees (if the upgrade
is triggered by the need to install an EV charger at a home), subsidized permit fees for EV
charges, streamlining the EV permitting process from paper to web -based, etc.
Development Services has coordinated an EV Task Force which has worked to advance EV
readiness in the City, develop ordinances, streamline the EV permitting process, and will be
modifying code requirements to reduce barriers to entry. In addition, Council adopted an
“EV readiness” requirement in July 2014 for all new residential and non-residential
construction that requires the installation of EV chargers and/or infrastructure to
accommodate future chargers, as seen in Municipal Code Section 16.14.380.
Staff is also developing protocols for systematically shifting the City fleet to EVs where
appropriate, and is exploring third-party providers of EV charging infrastructure, as a
potential way to expand that infrastructure at minimal cost to the City.
4) Fuel Switching for New Residential Homes: As part of the S/CAP, staff will work with
consultants to identify a roadmap with steps that would need to be taken to accommodate
fuel switching for new residential development. Once it has been determined when, and to
what extent, if any, the City wants to undertake fuel switching, then staff would be required
to take the necessary steps to ensure that the proposed direction complies with the
requirements of Title 24, Part 6 of the California Code of Regulations. Such steps may
include, among other steps, (a) development of cost effectiveness studies and analysis, (b)
filing with the California Energy Commission, (c) adoption of findings (if possible) that
2 Staff Report 2360: www.cityofpaloalto.org/civicax/filebank/documents/41528
3
demonstrate that fuel switching will not contradict the Energy Code prior to adoption of
local amendments, and (d) ultimately adoption of local amendments and modifications to
the Building Code that could legally accommodate the pace and direction the City would
prefer to pursue.
5) Electrification of the wCity’s Fleet: Staff is developing a system to assess the suitability
of EVs, for each vehicle or vehicle type in the City fleet, and is exploring other fuel switching
strategies and options as part of the S/CAP, ranging from incentives and/or mandates for
specified technologies and building types to internal carbon trading for City operations and
other financial innovations to minimize climate impacts of heating spaces and water in Palo
Alto.
EXCERPTED DRAFT MINUTES OF THE JULY 1, 2015
UTILITIES ADVISORY COMMISSION MEETING
ITEM 2: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that
Council Review and Approve the Proposed Work Plan to Evaluate and Implement Greenhouse Gas
Reduction Strategies by Reducing Natural Gas and Gasoline Use Through Electrification
Chief Sustainability Officer Gil Friend said that his report is a comprehensive report addressing social,
economic, and environmental aspects of electrification. He noted that the December 2014 Council
Colleagues Memo directed staff to identify the resources required to evaluated electrification issues. In
February 2015, staff provided a work plan to respond to the Colleagues Memo and this is the Phase I
work plan. Friend stated that the proposed work plan evaluates fuel switching options, but doesn't
necessarily recommend implementation at this time.
Commissioner Schwartz said she was delighted to see Utilities working with the Sustainability Office, but
she saw that the plan includes boundaries that do not necessarily make sense, for example, advanced
meters may be beneficial for more than just EV owners. Friend responded that the overall effort may be
broad, but what's referred to in this work plan is for electrification only.
Vice Chair Cook stated that the action is to provide a recommendation for what staff is proposing to
explore. This does not mean that a direction has been selected, but only to explore the various areas.
This does not limit flexibility and choice. He advised that the points made in the last item merit
consideration as the exploration is done. Friend agreed that flexibility is very important.
Vice Chair Cook stated that the TOU rates will likely evolve so that we shouldn't refer to EV charging at
night since the best time to charge may change as more renewables come onto the grid. He
recommended that work plan item #7 should remove "for residential EV charging" to make the item
more broad.
Commissioner Eglash supports the proposed work plan. He commented that the tasks were largely
using existing staff so this effort will not require additional staff.
Commissioner Danaher said that the City is only carbon neutral for electricity in the short term due to
the purchase of offsets. Director Fong noted that by 2017, the City will be carbon neutral with long-
term renewables plus large hydroelectric resources. Director Fong stated that who pays and who
benefits must be considered.
Chair Foster noted that natural gas is one of the remaining two sources of the City’s GHG emissions.
Friend confirmed that about 61% is from mobile transportation and use of natural gas is about 31%.
Chair Foster asked if electrification reduces GHG emissions in the grand scheme of things. Friend
confirmed that it is important.
"55"$).&/5%
Public Comment
Walt Hays urges that the UAC recommend that the Council adopt the proposed work plan.
Bruce Hodge stated that Carbon Free Palo Alto had a large part in writing the Council Colleagues Memo
and that it has been a long time coming. He said that the proposed plan is reasonable and supportable.
He advised that the City become active in many EV-related events. He said that TOU rates can be useful
as devices can be grid-interactive and add value from that capability.
Commissioner Danaher asked if the timeline could be sped up. Director Fong said that the plan was
developed in consideration of the existing staff resources available for the work.
ACTION:
Vice Chair Cook moved to recommend that Council approve the proposed work plan with the insertion
of “for example” in work plan item #7 so that it would read: “Explore offering Time -of-Use electric rate
options; for example, for residential EV charging.” Commissioner Eglash seconded the motion. The
motion carried unanimously (5-0 with Commissioners Cook, Danaher, Eglash, Foster and Schwartz voting
yes, Commissioner Hall absent).
Carnahan, David
From:Richard Placone <rcplacone@sbcglobal.net>
Sent:Friday, July 31, 2015 4:20 PM
To:Council, City
Cc:Keene, James; Gitelman, Hillary; Fong, Valerie
Subject:Conversion to All Electric
Dear Council Members and staff,
I want to state early on that we will not under any circumstances be converting to all electric service as
long as we Iive in this house. Over the years since 1962, we have spent over $200,000 converting this
original small but well built cottage into the ten room, 2200 square foot handsome residence it now is. Along
the way, we have upgraded with each remodel to the most current building codes. This includes increasing
insulation, energy efficient windows throughout, solar heated water system still in use and energy efficient
appliances as the need for new equipment arose. In addition, we have modified the landscape to be
conserving of water, eliminating all lawns and installing semi permeable brick patios and driveway. No
water leaves this property when it rains!
My point is that I believe my wife and I have been good citizens when it comes to energy conservation. I
have done some calculations of the prospective cost of making your suggested conversion:
1. Conversion from 110 service to 220 $ 2,000
2. Rewiring to bring service to appliance areas $ 3,000
3. Cost of new appliances, medium grade + install. $ 8,000
4. Miscellaneous refinishing of surface areas $ 1,000
Project subtotal cost $14,000
5. Contingency for the unexpected - 10% $ 1,400
Total Project cost budget $15,400
I daresay the city will not be including in its plans any substantial subsidy or rebates to assist retired seniors
like ourselves be able to make such a conversion. Moreover, if I were to go forward with your plan, the
cost be damned, I would be un-installing current late model appliances that haven't begun to reach their
expected life span. I do have other concerns: Gas cooking is exceedingly superior to electric cooking in our
experience (based on usage in other members of our families households - two of whom are gourmet
cooks); when the power goes out, as it does from time to time, we can still cook on the cook top which
allows for this contingency by by-passing the electronic ignition (We do lose heat, the oven and the clothes
dryer as these appliances have electronic ignition) Finally, where do you folks think all the electricity comes
from? At present, it is my understanding that most is generated by either gas or coal, in spite that the city
claims all of its electricity is "green".
Not one to not offer a doable alternative (in the past councils have ignored this suggestion.):Require all the
large corporate consumers in town, both at Stanford and the Stanford Research Park, as well as well as
other commercial sites about town, to install solar panels on their roofs, and esp. on trellises erected over
their acres of parking lots. (see the Googleplex in Mt. View for how this is done.) Every new commercial
building and every new house should be required to install the maximum solar panels as part of the initial
construction. (Have I done solar on my roof, you might legitimately ask. The answer is no, since my roof if
90% shaded by two massive California Live Oaks rated heritage oaks by the city.)
$JUZPG1BMP"MUP]$JUZ$MFSLhT0GGJDF]1.
Thanks for taking the time to read this missive.
Sincerely,
Richard C. Placone
Chimalus Drive
Barron Park/Palo Alto
$JUZPG1BMP"MUP]$JUZ$MFSLhT0GGJDF]1.
Carnahan, David
From:Stephen Madsen <s8madsen@yahoo.com>
Sent:Wednesday, August 05, 2015 11:29 AM
To:Council, City
Subject:Message from the City Council Home Page
To members of Palo Alto City Council,
I am responding to a recent article in the Palo Alto Weekly about urging utility customers to switch from natural gas to clean
electricity because the city declared its electric portfolio "carbon neutral." Clean carbon neutral electricity is good; however, before
users are encouraged to switch from natural gas to electricity, there needs to be sufficient supply to meet the demand. At the
present, there is not enough supply to meet the demand, and we have flex alerts that ask us to reduce our electricity consumption,
yet the city of Palo Alto wants us to use more electricity. The first priority should be to provide sufficient supply to meet the
current and projected demand. So, I recommend that you start by generating more electricity.
Regards,
Stephen H. Madsen
$JUZPG1BMP"MUP]$JUZ$MFSLhT0GGJDF]1.
Carnahan, David
From:Nat Fisher <sukiroo@hotmail.com>
Sent:Thursday, July 30, 2015 1:01 PM
To:UAC; Council, City
Cc:Editor Weekly
Subject:switch from gas to electricity
Switching all appliances from gas to electricity, even in new homes, could be a catastrophe.
Electrical outages happen frequently and can be long-term, especially if there is a disaster such
as an earthquake. With gas, one can have heat in winter, hot water and hot meals.
And how is electricity generated; not all of it comes from hydropower. The rest comes from gas
and coal plants.
Natalie Fisher
Palo Alto
$JUZPG1BMP"MUP]$JUZ$MFSLhT0GGJDF]1.
City of Palo Alto | City Clerk's Office | 8/5/2015 1:45 PM
Carnahan, David
From:Wayne Martin <wmartin46@yahoo.com>
Sent:Sunday, August 02, 2015 5:44 PM
To:Council, City; Keene, James
Subject:US Energy Sources, By Type and Percentage
Palo Alto City Council
City of Palo Alto
Palo Alto, CA 94301
Cc: James Keene
Subject: US Energy Sources, By Type and Percentage
Elected Officials:
The following is for your information, and consideration. Please not the total percentage of energy generated/consumed by the
US that originates from fossil fuels: 66%. Also, please notice that wind and solar contribute only about 5% to the total energy
budget of our country.
http://www.eia.gov/tools/faqs/faq.cfm?id=427&t=3
Major energy sources and percent share of total U.S. electricity generation in 2014:
* Coal = 39%
* Natural gas = 27%
* Nuclear = 19%
* Hydropower = 6%
* Other renewables = 7%
* Biomass = 1.7%
* Geothermal = 0.4%
* Solar = 0.4%
* Wind = 4.4%
* Petroleum = 1%
* Other gases < 1%
It stands to reason that government officials at all levels of government should be aware of this important information.
Wayne Martin
Palo Alto, CA
www.youtube.com/wmartin46 <http://www.youtube.com/wmartin46>
www.twitter.com/wmartin46 <http://www.twitter.com/wmartin46>
Attachment C: Update on the Progress of the Ten-Point August 2015 Electrification Work Plan
In August 2015 City Council approved a ten-point work plan to facilitate electrification in Palo
Alto over a five year period. Outlined below is a high level summary of the progress on each of
these tasks. The items listed under next steps have been included in the Sustainability
Implementation Plan (SIP) for further Council approval in the spring of 2017.
Task Status/Findings Next Steps
#1: Promote HPWH and
HPSH in existing homes
HPWH pilot program underway utilizing $100k
of funds from Utility R&D funds. Early results
suggest substantial barriers exist and hinder
the adoption of HPWH in existing homes.
HPSH pilot program in planning stage.
Continue implement pilot
scale programs through
2020.
#2: Provide resources to
homeowners to convert
existing homes to all-
electric homes.
Staff is planning a webpage as a resource
guide on electrification for homeowners.
Continue website
development in
coordination with Task 1.
#3: Explore the
development of retail
electric rate schedule for
homes that electrify
Residential retail rates adopted in July 2016
reduced electric rate tiers from three to two
tiers – this measure will partially assist
electrification at homes
Explore additional ways
to encourage
electrification (e.g.
provide discount for EV
charging using LCFS
funds)
#4: Explore additional
residential and commercial
building code changes for
new construction and
remodeling projects to
expedite electrification
Completed study to examine the feasibility of
including electrification mandates in Palo
Alto’s building code. Study concluded that
such mandates are imprudent to implement at
this time.
No additional actions for
now. Re-examine the
feasibility in 2022 as part
of the 2023 building code
cycle, or sooner if
conditions warrant.
#5: Evaluate utility
connection fees and
permitting fees associated
with electrification projects
No progress to date due to other work
priorities.
Explore ways to provide
cost certainty in utility
connection fee, for
customer panel upgrades
>200 Amps
#6: Promote the
installation and use of EV
chargers for public use and
at multi-family homes
Launched a $3,000 EV charger rebate program
for multi-family homes in January 2017, with
funding of ~$400k/year from LCFS funds.
City also obtained multiple grants for EV
charger installation at public spaces. All city
facility upgrade projects have installed EV
chargers as part of project.
Continue to implement
LCFS program elements
approved by Council in
October 2016.
Continue to seek grant
and CIP funds to install
EV chargers.
#7:Explore offering Time-
of-Use (TOU) electric rate
options
Currently 50 customers are on a TOU rate
implemented in 2014-15. CPAU is unable to
expand this program due to lack of resources –
expansion planned in 2018-19
Expand TOU rate
program in 2018-19.
#8: Explore opportunities In the past few years the City has explored Continue to focus on
ATTACHMENT C
to electrify existing and
new City buildings
electrification option when upgrading city
buildings. For example, the upgraded
Rinconada library uses ground-sourced heat
pumps for space heating/cooling.
electrification in
upcoming CIP projects,
and develop a master
efficiency and
electrification plan for all
city buildings
#9: Explore new financing
sources to expedite
electrification
Electric public benefits R&D funds are being
used for pilot projects. Staff also examined
Property Assessed Clean Energy (PACE)
financing, but concluded that the benefits of
PACE loans may be less applicable in Palo Alto
than in other communities.
Continue to explore
other options for
financing sources,
including state grants.
#10: Analyze, in a high level
pre-feasibility study,
options for district heating
for buildings
Exploring opportunities with Stanford to study
their SESI district heating/cooling system and
develop tools to assess such project feasibility
in downtown Palo Alto and/or at the Stanford
industrial park.
Begin such analysis when
opportunity arises and
resources become
available by 2020
436 14th St, Oakland, CA 92618
Phone: (916) 844-1033
Email: FFarahmand@trcsolutions.com
Palo Alto Electrification
Final Report
November 16, 2016
Submitted To:
Development Services
Mr. Peter Pirnejad
285 Hamilton Ave
Palo Alto, CA 94301
ATTACHMENT D
Palo Alto Electrification Study
i | TRC Energy Services
TABLE OF CONTENTS
EXECUTIVE SUMMARY ....................................................................................................................... 1
1. INTRODUCTION ......................................................................................................................... 3
Scope and Limitations ................................................................................................................. 3
Literature Review ......................................................................................................................... 4
2. METHODOLOGY ........................................................................................................................ 5
Industry Engagement .................................................................................................................. 5
Cost Effectiveness......................................................................................................................... 5
Cost Effectiveness Methodologies ............................................................................... 5
Prototypes ................................................................................................................... 7
Electrification Measure Description and Analysis ................................................................. 7
Heat Pump Water Heating .......................................................................................... 8
Heat Pump Space Heating......................................................................................... 10
Infrastructure ............................................................................................................ 11
3. COST EFFECTIVENESS RESULTS ............................................................................................ 14
4. BARRIERS AND FEASIBILITY RESULTS ................................................................................. 18
Code Barriers .............................................................................................................................. 18
Technical Barriers ...................................................................................................................... 19
Operational Barriers ................................................................................................................. 20
5. CONCLUSIONS AND RECOMMENDATIONS ....................................................................... 21
6. APPENDIX A – PROTOTYPE DETAILS ................................................................................... 23
7. APPENDIX B – COST DATA .................................................................................................... 26
Heat Pump Measures ............................................................................................................... 26
Infrastructure Upgrades ........................................................................................................... 28
8. APPENDIX C – COST EFFECTIVENESS TABLES ................................................................... 30
Residential ................................................................................................................................... 30
Single Family New Construction ................................................................................ 30
Single Family Alterations ........................................................................................... 32
Low-Rise Multifamily New Construction ................................................................... 35
Low Rise Multifamily Alterations .............................................................................. 36
Nonresidential ............................................................................................................................ 38
Small Office New Construction .................................................................................. 38
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Small Office Alterations ............................................................................................. 39
Medium Office ........................................................................................................... 40
9. APPENDIX D – SURVEY INSTRUMENT ................................................................................ 43
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iii | TRC Energy Services
TABLE OF FIGURES
Figure 1. Cost Effectiveness Summary – Societal Net Savings using Time Dependent Valuation of
Energy ......................................................................................................................................................... 1
Figure 2. Simulated Heat Pump Water Heater Models .............................................................................. 9
Figure 3. Electrical Components at a Building (source: 2011 National Electric Code Handbook) . 12
Figure 4. Cost Effectiveness Summary, Individual Heat Pump Measures ........................................... 15
Figure 5. Cost Effectiveness Summary, Packages ..................................................................................... 17
Figure 6. Residential Baseline Prototypes Summary................................................................................ 23
Figure 7. Nonresidential Baseline Prototypes Summary ......................................................................... 23
Figure 8. Residential Pre-code and New Construction Assumptions ................................................... 24
Figure 9. Nonresidential Pre-code and New Construction Assumptions ............................................ 25
Figure 10. Baseline Prototype Total Annual Energy Usage .................................................................... 25
Figure 11. Heat Pump Water Heater Incremental Cost Summary ........................................................ 26
Figure 12. Residential New Construction Heat Pump Space Heating Incremental Cost Summary26
Figure 13. Residential Alteration Heat Pump Space Heating Incremental Cost Summary ............. 27
Figure 14. Small Office Packaged Heat Pump Incremental Cost Summary ........................................ 27
Figure 15. Medium Office Incremental Cost Summary ........................................................................... 28
Figure 16. Electrical Infrastructure Costs .................................................................................................... 28
Figure 17. Natural Gas Plumbing New Construction Infrastructure Costs .......................................... 29
Figure 18. Permit Fees ..................................................................................................................................... 29
Figure 19. Single Family New Construction TDV Cost Effectiveness .................................................... 30
Figure 20. Single Family New Construction Customer Cost Effectiveness .......................................... 31
Figure 21. Single Family New Construction TDV Cost Effectiveness – Stiebel 220E ......................... 31
Figure 22. Single Family New Construction Customer Cost Effectiveness – Stiebel 220E ............... 32
Figure 23. Single Family Alterations TDV Cost Effectiveness ................................................................. 32
Figure 24. Single Family Alterations Customer Cost Effectiveness ....................................................... 33
Figure 25. Single Family Alterations TDV Cost Effectiveness – Stiebel 220E ...................................... 34
Figure 26. Single Family Alterations Customer Cost Effectiveness – Stiebel 220E............................ 35
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iv | TRC Energy Services
Figure 27. Low Rise Multifamily New Construction TDV Cost Effectiveness ...................................... 35
Figure 28. Low Rise Multifamily New Construction Customer Cost Effectiveness ........................... 36
Figure 29. Low Rise Multifamily Alterations TDV Cost Effectiveness ................................................... 37
Figure 30. Low Rise Multifamily Alterations Customer Cost Effectiveness ........................................ 38
Figure 31. Small Office New Construction TDV Cost Effectiveness ...................................................... 39
Figure 32. Small Office New Construction Customer Cost Effectiveness ............................................ 39
Figure 33. Small Office Alterations TDV Cost Effectiveness ................................................................... 40
Figure 34. Small Office Alterations Customer Cost Effectiveness ......................................................... 40
Figure 35. Medium Office New Construction TDV Cost Effectiveness ................................................. 41
Figure 36. Medium Office New Construction Customer Cost Effectiveness ...................................... 42
Thank You: Air Treatment Corporation, Bone Structure, Carbon Free Palo Alto, Norman S Wright, Nyle Systems,
Mr. Danny Oliver, Palo Alto Electrification Task Force, The City of Palo Alto, Redwood Energy, San Jose Boiler
Works, Water Quality Systems, Western Allied Mechanical, Wilkinson Construction, all the interviewees who
wish to remain anonymous, and our loving families.
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1 | TRC Energy Services
EXECUTIVE SUMMARY
The City of Palo Alto Development Services department engaged TRC to provide analysis for electrification of
new and existing buildings within the City. Electrification is a general term that means designing or converting a
building to use only electricity instead of gas for various end uses, including heating, cooling, lighting, cooking,
water heating, and process loads. TRC assessed the electrification of space heating and water heating, and
potential ramifications on the electrical service to the building, such as larger panel or branch circuit capacities.
The scope includes both a barriers analysis and a cost effectiveness analysis for residential and nonresidential
buildings.
TRC’s collected data by engaging with the local building industry through surveys and interviews with various
electrification experts, including contractors, engineers, architects, and energy consultants. Industry
engagement helped identify the technical specifications as well as costs for electrification. Online retailers and
RS Means were also used to collect cost data and product specifications. TRC then conducted building energy
simulations to assess the potential energy impacts of electrification equipment. Cost effectiveness is determined
by assessing the incremental costs of each measure and comparing them to the energy cost savings, using both
a societal and customer perspective. TRC uses Net Savings (benefits minus costs) as the cost effectiveness
metric. If the Net Savings of a measure is positive, the measure or package is considered cost effective.
The societal cost effectiveness of heat pump measures is summarized in Figure 1, measured based on Time
Dependent Valuation of energy benefits, with cost effective outcomes highlighted in green. Generally, results
using both the societal and customer perspective are consistent in determining which measures are cost
effective – one exception is the single family new construction Heat Pump Package, highlighted in the yellow.
Figure 1. Cost Effectiveness Summary – Societal Net Savings using Time Dependent Valuation of Energy
Building Type Construction
Type
Heat Pump
Water Heater
Heat Pump
Space Heater
Heat Pump Package
(Gas Connection
Remains)
All-Electric Package
(No Gas
Connection)
Single Family
New $(2,459) $5,180 $2,639ii $9,051
Alteration $(8,424) $3,866 $(3,737) $(5,170)
Low-rise
Multifamily
New $(21,982) $18,023 $(5,665) $12,041
Alteration $(54,324) $16,537 $(36,627) $(38,060)
Small Office
New $(777) $(5,620) $(6,397) $5,941
Alteration $(3,187) $(9,844) $(12,904) $(14,337)
Medium Office
New $(777) $(169,234) $(170,011) $(159,533)
Alterationi $(3,344) - - -
i HPSH alterations, and packages with HPSH alterations, will be less cost effective than new construction due to baseline system design.
Detailed calculations have not been performed.
ii The single family new construction Heat Pump Package is not cost effective when using the customer perspective methodology.
Heat pump water heating as a standalone measure is not cost effective, primarily due to the costly electrical
upgrades they require. Heat pump space heating is cost effective in residential buildings because the equipment
is less expensive than the standard split air conditioner with a furnace, and they are not likely to require an
electrical upgrade if an existing central air conditioner exists. When these measures are packaged together, they
are generally only cost effective in new construction scenarios when assuming that there is no natural gas piping
Palo Alto Electrification Study
2 | TRC Energy Services
connected to the building. (Note that any costs associated with switching to electric ranges and dryers are not
included in the analysis – thus, foregoing the natural gas connection is an aggressive assumption).
Many of the code barriers are associated with Title 24 compliance software modeling, which the CEC is working
toward addressing or eliminating. Residential technical barriers predominantly relate to the lack of experience
from contractors, building departments, and owners with HPWHs. These barriers are expected to dissipate with
increased penetration of HPWHs. The commercial building industry is much more familiar with heat pump
systems, but market-ready HPSH may not yet be widely available at a competitive cost for many high-
temperature and high-capacity applications, such as heat pump boilers or providing makeup air in restaurants.
While TRC found some code, technical, and operational barriers to HPWH and HPSH implementation, they are
not insurmountable. Heat pump technology is emerging and there is potential for increased adoption in Palo
Alto.
As policies and rates change over time, electrification may become more cost effective for Palo Alto in the
future. Improved heat pump equipment that achieve similar outlet temperatures to gas equipment, and/or
avoid costly electrical upgrades in existing buildings, are emerging. As these products proliferate, market forces
will drive down prices and improve the cost effectiveness of electrification. There are many assumptions built
into the cost effectiveness estimates, and minor variations may lead to significant changes in results. Further
analysis can help better understand the range of outcomes possible.
Palo Alto Electrification Study
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1. INTRODUCTION
The City of Palo Alto Development Services department engaged TRC to provide feasibility analysis for
electrification of existing and new buildings within the City. Palo Alto has a history of developing aggressive
building energy efficiency reach codes, an active community that is passionate about sustainability, and a utility
that provides 100% emission-free electricity. To mitigate the emissions associated with utility-provided natural
gas, the City is interested in the code feasibility and cost effectiveness of electrifying buildings. This feasibility
analysis may inform a variety of policy levers that the City may wish to implement, including building ordinances
and incentive programs.
Scope and Limitations
Electrification is a general term that means designing or converting a building to use only electricity instead of
gas for various end uses, including heating, cooling, lighting, cooking, water heating, and process loads. For most
of building end uses, such as space cooling, lighting, and plug loads, electricity is the common fuel. However,
space heating and water heating are among the higher energy consuming building functions typically using
natural gas for fuel.
TRC has been tasked with assessing the electrification of space heating and water heating, and potential
ramifications on the electrical service to the building, such as larger panel or branch circuit capacities. The scope
includes both new construction and alterations scenarios, in both residential and nonresidential buildings.
Analysis includes two overarching elements:
Feasibility Analysis. Investigating building codes, equipment technical capabilities, and on-going
operational characteristics that may pose feasibility barriers for electrification.
Cost Effectiveness Analysis. Investigating and comparing the costs and energy savings benefits
associated with electrification.
These elements are specifically with regard to heat pump space heating (HPSH), heat pump water heating
(HPWH), and associated infrastructural service costs (electrical and plumbing).
This study has the following scope limitations:
Prototypes. The prototypes studied are only low-rise residential and offices. Findings may not pertain to
high-rise residential or other commercial spaces, such as restaurants and fitness centers, which have
much higher water and space heating loads.
Existing Conditions. A wide range of existing conditions are possible, such as existing HVAC system,
DHW system, and electrical infrastructure capacity, and each has a potential to impact heat pump
measure cost effectiveness. Based on industry engagement and previous experience, TRC determined
costs using one set of assumptions for existing conditions. In some cases, software capabilities dictated
existing conditions – for example, a central HPWH serving a multifamily building cannot be modeled,
thus a central gas water heater was not investigated as a potential baseline for a HPWH retrofit.
Other Appliances. Other end-uses that typically use natural gas, such as stovetops, ovens, clothes
dryers, and pool heaters, have been explicitly excluded from the scope of this study. Nonetheless, TRC
assumed that natural gas is not being delivered to buildings in some scenarios.
Grid Upgrades. TRC did not consider electrical grid upgrades that are the responsibility of the utility,
such as transformer or service point upgrades.
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Literature Review
To draw upon existing work and avoid duplication of efforts, TRC reviewed the following reports and
summarized key findings:
Residential Electrification Opportunities in Palo Alto, by City of Palo Alto Utilities (2015)1 – This report
focuses on residential electrification only, and includes many elements outside of TRC’s scope including
electric vehicles and solar photovoltaics (PV). Key findings include:
• HPWHs are cost effective compared to natural gas tankless water heaters, but not when compared
to standard efficiency gas water heaters (0.58 energy factor), using a societal perspective. Using a
customer perspective, HPWHs are cost effective when compared to either tankless or a standard
efficiency gas water heaters. Note that since this study was performed tankless water heaters have
become the California prescriptive requirement in the 2016 Title 24 Building Energy Efficiency
Standards (Title 24).
• HPSHs are not cost effective compared to natural gas furnaces from both a societal and customer
perspective.
• Electrical retrofits can cost $2,000 or more per heat pump space heater or water heater, including
wiring and running conduit from the panel to the appliance. Upgrading the electrical panel from 60
Amp to 200 Amp can cost up to $5,000.
Grid Integration of Zero Net Energy Communities, by Electric Power Research Institute (Draft 2016)2 –
This study investigated the cost effectiveness of ZNE communities with electrification and high PV
penetration. The study found that the installation of HPWH and HPSH shifts the peak load (as high as 15
kW) so that it is non-coincident with peak PV generation, though this shift may be mitigated with grid
interactive water heaters. Perceptions that HPSH may not be able to maintain comfort, due to the lower
discharge temperature, are overcome by increasing run time.
Electrification Analysis, by Energy + Environmental Economics (2016)3 – This report investigates the
breakeven carbon price required for lifecycle TDV of electrification to be equivalent to mixed-fuel. The
report estimates that an electrified single family home will pay $5,530 more in utility bills over 30 years,
suggesting that a carbon price be developed to compensate for this cost.
TRC used these resources to guide research and compare costs and energy savings findings. Other similar
reports were briefly reviewed but not found to be highly relevant to the scope of this project.
1 Available at: https://www.cityofpaloalto.org/civicax/filebank/documents/47998
2 Available at:
http://calsolarresearch.ca.gov/images/stories/documents/Sol4_funded_proj_docs/EPRI_Ram/CSI_RDD_Sol4_EPRI_Grid_Int_ZNE_repo
rt_DRAFT.pdf
3 Available at: http://docketpublic.energy.ca.gov/PublicDocuments/16-BSTD-
06/TN212680_20160808T161828_Electrification_Analysis.pdf
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2. METHODOLOGY
TRC’s data collection efforts focused primarily on engaging with the local building industry through surveys and
interviews with various electrification experts, including contractors, engineers, architects, and energy
consultants. Industry engagement helped identify the technical specifications as well as costs for electrification.
TRC then conducted building energy simulations to assess the potential energy impacts of electrification
equipment, and inform cost effectiveness from a societal and customer perspective.
Industry Engagement
TRC and the City of Palo Alto distributed an online survey to local industry members to gather feedback on heat
pump water heaters (HPWH) and heat pump space heaters (HPSH) installations and experience. The goals of the
survey were to gather initial information about the prevalence of, and experience with, these technologies in
Palo Alto. The survey included both multiple choice and open ended responses regarding barriers, solutions they
used to address barriers, cost estimates, and recommendations for future installations.
The survey was distributed to approximately 500 industry members, including contractors, plumbers, architects,
and design engineers. Fifteen (15) respondents provided feedback, though for most questions the number of
responses is less than 15. Survey questions can be found in Appendix D – Survey Instrument.
TRC also interviewed over 25 contractors, distributors, and other experts to discuss barriers, design
specifications, and costs related to heat pump appliances and electrification.
Cost Effectiveness
TRC assessed the life cycle cost (LCC) effectiveness of Palo Alto’s 2016 Reach Code by analyzing heat pump
measures applied to new construction and alteration building prototypes in Climate Zone 4 (CZ4). TRC
determined cost effectiveness by assessing the incremental costs of each measure and comparing them to the
energy cost savings, using both a societal and customer perspective. Incremental costs represent the
construction and maintenance costs of the proposed measure relative to the 2016 Title 24 Standards minimum
requirements.
TRC uses Net Savings (benefits minus costs) as the cost effectiveness metric. If the Net Savings of a measure is
positive, TRC considers the measure or package as cost effective. In some cases, both the benefits and the costs
are negative for a particular measure. Using Net Savings, a measure that has negative energy cost benefits can
still be cost effective if the negative costs to implement the measure (i.e., cost savings) are greater than the
negative energy benefits.
Cost Effectiveness Methodologies
The societal perspective of energy savings benefits is estimated using the California Energy Commission (CEC)
LCC methodology, while the customer perspective is estimated using on-bill savings that would occur using Palo
Alto Utility retail rates. Measure costs are calculated in the same way for both methods.
California Energy Commission Life Cycle Cost Methodology – Societal Perspective
The CEC LCC methodology is approved and used by the CEC to establish cost effective building energy standards
(Title 24, Part 6). The LCC methodology involves estimating and quantifying the energy savings associated with
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measures using a Time Dependent Valuation (TDV) of energy savings.4 TDV is a normalized format for comparing
electricity and natural gas savings, and takes into account the cost of electricity and natural gas consumed
during different times of the day and year. The TDV values are based on long term discounted costs – 30 years
for all residential measures and nonresidential envelope measures, and 15 years for all other nonresidential
measures. TDV energy estimates are based on present-valued cost savings but are presented in terms of “TDV
kBTUs” so that the savings are evaluated in terms of energy units, and measures with different periods of
analysis can be combined into a single value.5 The CEC developed the TDV values that were used in the analyses
for this report, and are representative of Palo Alto’s climate zone.
Life Cycle Customer Costs – Customer Perspective
Customers who save energy through energy efficiency measures have lower energy bills. Societal benefits are
not included, in contrast with TDV. To estimate the customer cost savings, TRC estimated the monthly electricity
and natural gas demand for each prototype using Title 24 compliance simulation software. The following Palo
Alto utility rates were used to estimate the on-bill cost savings resulting from the efficiency measures6:
Residential
• Electric
- Tier 1 (≤ 330 kWh/month): $0.11/kWh
- Tier 2 (> 330 kWh/month): $0.17/kWh
• Gas
- Service charge: $10.32/month
- Tier 1 (≤ 20 therms/month in summer, ≤ 60 therms in winter): $0.87/therm
- Tier 2 (> 20 therms/month in summer, > 60 therms in winter): $1.41/therm
Commercial
• Small Office Electric (E-2)
- Summer: $0.17/kWh and no demand charge
- Winter: $0.11/kWh and no demand charge
• Medium Office Electric (E-4)
- Summer: $0.10/kWh and $19.68/kW demand charge
- Winter: $0.08/kWh and $14.04/kW demand charge
• Gas
- Service charge: $78.23/month
- $1.05/therm
4 Architectural Energy Corporation (2011). Life-Cycle Cost Methodology. Prepared for the California Energy Commission. Available at:
http://www.energy.ca.gov/title24/2013standards/prerulemaking/documents/general_cec_documents/2011-01-
14_LCC_Methodology_2013.pdf
5 kBTUs = thousands of British Thermal Units.
6 Attained on October 12, 2016 from: http://www.cityofpaloalto.org/gov/depts/utl/
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TRC performed a Net Present Value (NPV) calculation over 30 years, assuming a 3% discount rate and a 3%
energy escalation rate.
Cost Data Collection
TRC researched measure costs through interviews with contractors and distributors who serve the Palo Alto
region, and reviewed online sources such as Home Depot and RS Means. Taxes and contractor markups were
added as appropriate. Detailed costs are provided in Appendix B – Cost Data.
Measure costs are the same for both cost effectiveness methodologies described above. TRC did not include
incentives available for HPWHs from Palo Alto Utilities because the incentive is currently a pilot and not a
program.
Prototypes
TRC estimated the energy impacts of HPWH and HPSH both individually and combined using building
simulations. TRC used CBECC-Res 2016.2.0 (build 857) to simulate the residential prototypes and CBECC-Com
2016.2.1 (build 868) for the nonresidential prototypes, in climate zone 4 (CZ4).7 TRC used five prototypes as the
basis for determining cost effectiveness, based on request by the City of Palo Alto:
2,100 ft2 single family single-story home
2,700 ft2 single family two-story home
6,960 ft2 low-rise multifamily residential building, with two stories and eight dwelling units
5,502 ft2 one-story small office building
53,600 ft2 three-story medium office building
Prototypes are based on CEC prototypes in the Residential and Nonresidential Alternate Calculation Method
Manuals, but geometry is revised in order to have equal geometry oriented facing north, east, south, and west.
Baseline prototypes characteristics are summarized in Appendix A – Prototype Details.
Electrification Measure Description and Analysis
TRC investigated the implementation of heat pump measures and associated infrastructural costs. In general,
heat pumps use a refrigeration cycle to absorb heat from one medium and reject heat to another medium.
Mediums are typically air or water. A household refrigerator is a common example of an air-to-air heat pump.8
Some heat pumps can also be run in reverse to switch the heat source and heat rejection mediums. Heat pump
equipment typically requires a larger electrical connection than an equivalent natural gas appliance due to a
higher voltage and amperage necessary to operate the equipment (discussed further in Section 2.3.3).
TRC developed measure characteristics using the following criteria:
1. The equipment must be readily available in the Palo Alto region.
2. The equipment should have a high likelihood of providing cost effective savings as compared to the Title
24 baseline.
7 More information on CBECC-Res available at: http://www.bwilcox.com/BEES/BEES.html. More information on CBECC-Com available at:
http://bees.archenergy.com/software.html
8 Or, food-to-air.
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3. Federal pre-emption is not a concern.9 TRC assumed that Palo Alto was interested in finding the most
cost effective options for a potential electrification ordinance or incentive program, which are unlikely
to trigger federal pre-emption if designed appropriately.
For example, TRC investigated NEEA (Northeast Energy Efficiency Alliance) rated HPWHs, which are readily
available on the market, save energy compared to the Title 24 baseline (in some cases), and have energy factors
that are higher than required by the Department of Energy (DOE).10
Heat pump measures are compared to the baseline systems outlined in Figure 6 and Figure 7 in Appendix A –
Prototype Details.
Heat Pump Water Heating
TRC investigated heat pump water heaters with tanks, which absorb ambient heat from the surrounding air to
heat water, and reject cold air. The supply and rejection air may be ducted if necessary. They can be located in
conditioned or unconditioned spaces, though locating a HPWH in conditioned space may create additional space
heating loads. The size and shape of the HPWH is approximately that of a natural gas storage water heater.
Condensate draining is required.
HPWHs are capable of producing similar temperatures to natural gas water heaters under typical weather
conditions, but may occasionally need to switch to a standard electric resistance mode in cold weather. HPWH
energy factors range from 2 to over 3 under rated conditions, but are just under 1 when in electric resistance
mode.
Residential
When modeling HPWHs in CBECC-Res, a user can either select NEEA-rated appliances or manually input the
energy factor, capacity, and tank volume of a generic HPWH. TRC found that NEEA rated appliances consistently
produced better energy impacts than manual inputs over a wide range of energy factors. For this reason, TRC
investigated cost effectiveness using this limited set of HPWHs, shown in Figure 2.11 These appliances are
available throughout the west coast, have energy factors ranging from 2.3 to 3.4, and volumes ranging between
50 and 80 gallons. TRC did not find a significant energy impact correlating with HPWH energy factor or location –
the garage was selected as the likely location for installation.
The HPWHs in Figure 2 are relevant for single family new construction and alterations, as well as multifamily
new construction and retrofit scenarios where the water heaters are installed at each individual dwelling unit.
Some existing multifamily buildings have a central water heater, but the current version of CBECC-Res does not
allow the simulations of a central HPWH. Because of this software limitation, TRC did not analyze central water
heaters in multifamily buildings.
9 Federal preemption occurs when a state or city mandates that a higher efficiency appliance be installed than the minimum efficien cy
required by the DOE. This is different from an energy standard, which requires a higher overall energy performance of a building
through a variety of means, not specifically a higher efficiency appliance.
10 DOE Standards are available at: http://energy.gov/eere/buildings/standards-and-test-procedures
11 Note that this does not include the Sanden HPWH, which uses CO 2 as the working fluid.
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Figure 2. Simulated Heat Pump Water Heater Models
Water Heater Energy Factor
AO Smith PHPT 60 2.33
AO Smith PHPT 80 2.33
AO Smith HPTU 50 3.24
AO Smith HPTU 66 3.17
AO Smith HPTU 80 3.24
GE 2014 50 3.39
GE 2014 80 3.26
Rheem HB 50 2.47
Stiebel 220E 3.09
TRC used the AO Smith HPTU 50 and AO Smith HPTU 66 in most analysis because of the slightly better
performance, wide availability, and moderate costs as compared to the other HPWH models. TRC also explored
the Stiebel 220E because this HPWH avoids costly electrical upgrades associated with most other HPWHs.
Because the Stiebel is more expensive and less representative of the products available on the market, this
product was only analyzed in the single family prototype and results are discussed in Appendix C – Cost
Effectiveness Tables.
Nonresidential
CBECC-Com is able to simulate HPWHs in the same way that CBECC-Res can (described above) for high-rise
multifamily residential spaces, but not in nonresidential spaces. As a workaround, TRC simulated both natural
gas water heaters and HPWHs in a hypothetical high-rise multifamily prototype, and used the relative
performance to estimate the annual energy performance of the HPWH in a nonresidential scenario. While the
true energy performance between the will certainly be different due to different load profiles in residential and
nonresidential spaces, this analysis includes a year’s worth of climate data and may serve as a good
approximation of HPWH energy performance considering the software limitations.
The high-rise multifamily HPWH TDV results were very similar to the gas water heater baseline in the high-rise
multifamily prototype, so TRC assumed a neutral TDV impact for nonresidential HPWHs to avoid influencing
results. To estimate on bill savings for the customer perspective, TRC first determined the ratio of the energy
demand for the high-rise multifamily HPWH versus that gas water heater for each month of the year.12 TRC then
multiplied these monthly ratios against the office gas water heater monthly energy demand to estimate the
potential monthly energy demand of the HPWH.
12 The ratio ranged from 0.26 in the summer to 0.31 in the winter. This is consistent the assumed efficiencies of each equipment [(gas
water heater efficiency / HPWH efficiency) ≈ (0.80 / 3) ≈ 0.27].
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The sizes of the nonresidential water heaters are similar or smaller than that required for residential
applications (about 30,000 Btu/h capacity and 25 gallons). Thus estimated equipment characteristics and costs
are assumed to be the same as in the residential scenarios.
Heat Pump Space Heating
TRC used a central split HPSH in the residential prototypes, and a packaged heat pump or a heat pump boiler in
the nonresidential prototypes. The central and packaged heat pump systems are very similar to the baseline
systems except they lack a furnace and gas connection – the heat pumps are essentially a split air conditioner
that can also run in reverse to heat the space.
Residential
TRC assumed a central ducted split system heat pump provided heating and cooling for the residential buildings.
TRC assumed one split system installed in the single story single family prototype and each multifamily dwelling
unit. Based on conversations with contractors, TRC modeled two systems in the two-story home (one for each
floor), which enables zonal control. HPSHs were assumed to have an efficiency of 8.5 HSPF and a rated heating
capacity of about 36,000 Btu/h at 47°F. Capacities at 17°F were based on equipment cut sheets and are about
20,000 Btu/hr without an electrical resistance element. Stakeholder feedback suggests that electrical residential
heat pump systems installed in Palo Alto do not require an electrical resistance backup heater, nor the
associated branch circuit upgrade. The Goodman GSZ14 and Rheem RP14 are products that meet these
characteristics.
TRC did not explore the following alternate system types:
Hydronic distribution systems such as radiant floors, radiators, or hot water coils have many benefits,
but when compared to central ducted split systems they are more expensive, less common, and unlikely
to have much higher heating energy savings in residential applications.
Combined water heater and hydronic space heating because CBECC-Res software cannot simulate this
scenario with HPWH, and because hydronic-based systems are a more expensive distribution system
than a packaged systems, as described above.
Nonresidential
TRC assumes the small office HPSH system to be five single zone packaged heat pumps (SZHPs). When compared
to the assumed baseline system of five single zone packaged air conditioners (SZACs), the heat pumps are very
similar except they lack a furnace and gas connection. As with the residential system, this system is essentially a
split air conditioner that can run in reverse. SZHPs are not as common as SZACs, and thus are slightly more
costly. The Rheem RJ and RQ series are examples of packaged heat pumps that can adequately serve the small
office.
TRC assumes the medium office HPSH system to be an air source heat pump boiler (HPB) serving a packaged
variable air volume system with reheat boxes. This system was selected based on conversations with contractors
and preliminary pricing estimates compared to a variable refrigerant flow (VRF) system. TRC found only one heat
pump boiler by Multistack that is readily available in Palo Alto. This heat pump boiler cannot supply hot water
temperatures as high as conventional gas boilers (130°F versus 180°F, respectively).13 To account for this lower
temperature in an alteration scenario, hot water coils in the reheat boxes and at the rooftop air handlers would
need to be larger to increase the heat exchanger surface and ensure that space heating loads are met. Because
13 A CO2 boiler may be able to achieve such temperatures if inlet water temperatures are low enough. The Mayekawa is one such air-to-
water heat pump, but it is not yet UL listed in the United States.
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both the alteration and the new construction scenario would require larger VAV coils and a heat pump boiler,
TRC assumed costs for both scenarios to be the same with the exception of demolition costs in the alteration
scenario.
The following alternate system types, none of which can be modeled in CBECC-Com, were not explored:
Variable refrigerant flow (VRF) paired with dedicated outside air systems proved to be more expensive
than a heat pump boiler in a new construction scenario based on two cost sources. Furthermore, though
VRF systems are not uncommon in a new construction, manufacturer representations of performance
have been inconsistent and thus tough to model.14
Ground source heat pumps involve installing heat exchange piping into the earth. While the ground can
be an acceptable and efficient heat source, the earthwork costs are very likely to outweigh the
incremental efficiency improvements compared to an air source heat pump.
Radiant heating would be a good application for a heat pump boiler because of the lower hot water
temperatures used in floors, but still require extensive commissioning and are perceived as expensive.
Furthermore, there is a wide variation in design and controls methods, making them difficult to model.
Infrastructure
Installing heat pump appliances will likely require electrical and plumbing upgrades at the building, although in
different ways and at different costs for new construction versus alteration buildings.
Electrical
The primary electrical components, shown in Figure 3, include:
Service panel. This is the utility’s connection to the building, and must be sized to provide adequate
power to the building.
Electric panel. The electric panel is downstream of the utility meter, contains the circuit breakers, and
distributes electricity to the branch circuits and potentially subpanels. Typical dwelling unit panels range
from 100 Amps (A) to 200A in capacity, while nonresidential buildings have much larger service and
capacity. In retrofit scenarios when panel capacity upgrades are necessary, TRC assumed that panels
would be replaced rather than have subpanels added.
Branch circuits. Branch circuits are composed of the wiring and conduit. Typical branch circuits are sized
for 15A. In retrofit scenarios requiring a branch circuit upgrade, TRC assumed two branch circuit upgrade
options: new conductors (which are thicker) can be pulled through existing conduit, or a new conduit
and conductors are necessary, which requires minor wall demolition. TRC assumed approximately 30’ of
branch circuit runs in residential buildings and 50’ in nonresidential.
14 ACEEE 2012 Summer Study, Variable Refrigerant Flow - Heat Recovery Performance Characterization. Available at:
http://aceee.org/files/proceedings/2012/data/papers/0193-000078.pdf
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Figure 3. Electrical Components at a Building (source: 2011 National Electric Code Handbook)
TRC assumed the electrical upgrade scenarios below. The electrical infrastructure costs for each prototype
considering the following assumptions are in Appendix B – Cost Data.
Residential
• Electric panels for new construction buildings do not need to be upgraded with the addition of heat
pump appliances; 200A is the baseline size for single family, and 125A is the baseline size for
multifamily dwellings.
• Electric panels for existing single family buildings adding a heat pump water heater are upgraded
from 100A to 200A; existing multifamily dwelling panels are upgraded from 60A to 125A.
• Service connection upgrade fees, which relate to increased conduit and conductor sizes, are
necessary for existing residential buildings that install heat pump water heaters.
Nonresidential
• Branch circuits to HPSHs are upgraded from 50A to 80A using existing conduit (small office only).
• Branch circuits to the heat pump boiler are upgraded from 20A to 80A using existing conduit
(medium office only).
• Electric panels and service connections, both existing and new construction, have adequate capacity
to accommodate all heat pump measures.
Residential and nonresidential
• Branch circuits to water heaters are upgraded to 30A using existing conduit.
Plumbing
There are two important plumbing connection impacts resulting from heat pump appliances:
Natural gas piping. In an all-electric scenario, natural gas would not be used at all. While the scope of
this study does not explicitly consider electric ranges or clothes dryers, TRC assumes these appliances to
be electric. Eliminating natural gas usage would save costs associated with horizontal drilling, plumbing
to all appliances, and utility connection fees in a new construction scenario. Retrofits would avoid
monthly connection charges of $10.32, but would have to pay the utility a one-time fee of $1,433 to
disconnect.
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Condensate drain. HPWHs, similar to air conditioners, condense water on the evaporator coil. This
water must be drained to a sewer system as per Palo Alto Utility requirements. In new construction the
natural gas water heater will likely be furnished with a nearby sewer connection in case of maintenance
or leakage, but in older buildings this may not be the case. Two local plumbers suggested that a rough
cost of $1,000 is adequate for condensate drain installation in single family alteration scenarios, though
it depends on a large variety of existing conditions that would impact cost.15 The 8-unit multifamily
condensate drain lines are estimated to be $4,000 to consider economies of scale.
In some scenarios, TRC assumed that the new construction buildings would not trench natural gas to the
building, and that alteration buildings would disconnect gas service from the building. Note that this is an
aggressive assumption given that the scope of this study does not include other appliances that typically use
natural gas.
TRC also assumed that condensate drains would need to be added in alteration scenarios. The plumbing
infrastructure costs for each prototype considering the above assumptions are in Appendix B – Cost Data.
Permits and Fees
In alteration scenarios, equipment upgrades require electrical, plumbing, and mechanical permits. If the utility
needs to upgrade the service connection, they charge the building owner a nominal fee. TRC coordinated permit
and fee costs with utility staff.
15 Includes condensate pump, P-trap, $200-$400 in materials, 3-5 hours of labor, and no sheet rock patching.
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3. COST EFFECTIVENESS RESULTS
The cost effectiveness tables in this section list the estimated cost of the measure or package, and the estimated
benefits of the measure using both the societal perspective and customer perspective. The societal perspective
uses TDV energy savings as benefits metric, while the customer perspective uses on bill energy savings benefits.
Cost effectiveness using each methodology is determined using the Net Savings (benefits minus costs). A
positive Net Savings indicates that the measure benefits are larger (or less negative) than the costs, and the
measure is cost effective. Detailed cost effectiveness results are available in Appendix C – Cost Effectiveness
Tables.
The cost effectiveness of the individual heat pump measures is summarized in Figure 4, while Figure 5 describes
the heat pump packages cost effectiveness. Cost effective measures/packages are highlighted in green, while
those measures/packages that are not cost effective are highlighted in red. The Heat Pump Packages (top half of
Figure 5) depicts cost and savings estimates associated with installing both a HPWH, HPSH, and the necessary
electrical upgrades. The All-Electric packages (bottom half of Figure 5) assume that, in addition to the Heat
Pump Package, there is no natural gas connected to the building. Note that any costs associated with switching
to electric ranges and dryers are not included in the analysis – foregoing the natural gas connection is an
aggressive assumption.
Overall Findings
The TDV Net Savings and Customer Net Savings lead to the same cost effectiveness result for 61 out of the 64
measure/packages, showing a high level of consistency. TDV Benefits were higher than Customer Benefits in
most residential scenarios, while the opposite is true in office buildings. This is due likely due to how Palo Alto’s
tiered electrical rates differ in the residential and nonresidential prototypes. Because the residential tier ranges
are smaller than the nonresidential tiers, the addition of heat pump measures are more likely to increase
residential electricity consumption predominantly into Tier 2. TRC estimates that installing one or more heat
pump measures in the residential prototypes would add two (2) electric Tier 2 months each year.
Heat Pump Water Heating
Heat pump water heaters (top half of Figure 4) cost more than conventional gas water heaters for all
prototypes. HPWH alterations in existing buildings are more expensive because of more extensive electrical
expenses – branch circuit, electric panel, and service connection upgrades as well as permits. In some cases they
provide TDV or Customer Benefits, but not enough to make the heat pump water heaters cost effective as a
standalone appliance.
TRC assumed that HPWHs in office buildings would have a neutral TDV impact, as discussed in Section 2.3.1. TRC
found that the only measure that proved cost effective (narrowly) was the medium office using the customer
perspective, due to the higher domestic hot water demand and lower electrical upgrade costs.
Heat Pump Space Heating
Residential heat pump space heating (bottom half of Figure 4) is less expensive than the baseline split ACs with
furnaces. It is important to note that TRC assumed that residential HPSHs in Palo Alto will not require an
electrical resistance element, and the associated branch circuit upgrade, keeping measure costs low. Cost
effectiveness results may shift when HPSHs with electric resistance elements are installed. Most residential
prototypes show negative TDV and Customer Benefits, but these are outweighed by the large cost savings of
heat pump equipment, and result in mostly cost effective measures.
Nonresidential heat pump space heating is more expensive than single zone packaged ACs. Although the small
office HPSHs do show TDV and Customer Benefits, they are not enough to overcome the incremental higher
costs for installation of the equipment. TRC found the medium office HPSH measures had a very low likelihood
of being cost effective in new construction, and concluded that alterations are even less likely to be cost
effective because of additional demolition costs.
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Figure 4. Cost Effectiveness Summary, Individual Heat Pump Measures
Measure Prototype Scenario Costs TDV Benefits Customer Benefits TDV Net Savings Customer Net Savings
Heat Pump Water
Heating
Single Family
New $2,681 $222 $(1,917) $(2,459) $(4,599)
Alterationi $5,338 $96 $(1,503) $(8,424) $(10,022)
Multifamily
New $21,452 $(530) $198 $(21,982) $(21,254)
Alterationi $52,468 $(1,856) $(11,146) $(54,324) $(63,614)
Small Office
New $777 $0 $435 $(777) $(342)
Alteration $3,187 $0 $435 $(3,187) $(2,752)
Medium Office
New $777 $0 $963 $(777) $186
Alteration $3,344 $0 $963 $(3,344) $(2,381)
Heat Pump Space
Heating
Single Family
New $(4,561) $619 $(2,728) $5,180 $1,833
Alteration $(4,091) $(224) $(4,775) $3,866 $(685)
Multifamily
New $(20,880) $(2,857) $(13,391) $18,023 $7,489
Alteration $(23,324) $(6,787) $21,987 $16,537 $45,311
Small Office
New $6,090 $470 $357 $(5,620) $(5,733)
Alteration $11,886 $2,042 $1,724 $(9,844) $(10,162)
Medium Office
Newii $212,429 $43,195 $49,227 $(169,234) $(163,202)
Alterationiii - - - $- $-
i Residential HPWH alteration costs are for a gas tankless water heater. TDV and customer benefits are compared to this baseline. For gas storage results see Appendix C.
ii For the medium office, dollar benefits represent entirety of annual space heating energy, assuming no increase in electricity consumption.
iii Medium office HPSH alterations will be less cost effective than new construction due to baseline system design. Detailed calculations have not been performed. See Appendix C for
discussion.
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Packages
Except in single family new construction, heat pump packages (top half of Figure 5) are more costly than the
conventional gas baselines. This is because the incremental cost of HPWHs is larger than the cost savings of a
HPSH system in most residential prototype scenarios. In nearly all cases, the TDV and Customer Benefits are
smaller than the incremental cost of the heat pump packages, and most packages are not cost effective.
All-electric packages (bottom half of Figure 5) are cost effective for all new construction prototypes because of
the significant cost savings associated with avoiding a natural gas connection, except the medium office.
Alterations are mostly not cost effective because they require more extensive electrical upgrades than new
construction.
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Figure 5. Cost Effectiveness Summary, Packages
Measure Prototype Vintage Costs TDV Benefits Customer Benefits TDV Net Savings Customer Net Savings
Heat Pump
Measures
Package
(Gas
Connection in
Place)
Single Family
New $(1,879) $760 $(4,925) $2,639 $(3,046)
Alterationi $3,579 $(158) $(5,375) $(3,737) $(8,953)
Multifamily
New $572 $(5,093) $(24,564) $(5,665) $(25,135)
Alterationi $27,984 $(8,643) $(25,622) $(36,627) $(53,606)
Small Office
New $6,867 $470 $792 $(6,397) $(6,075)
Alteration $14,946 $2,042 $2,159 $(12,904) $(12,786)
Medium Office
New $213,206 $43,195 $50,190 $(170,011) $(163,016)
Alterationiii - - - $- $-
All-Electric
Package
(No Gas
Connection)
Single Family
New $(8,292) $760 $(1,430) $9,051 $6,862
Alterationi $5,012 $(158) $(1,880) $(5,170) $(6,891)
Multifamily
New $(17,134) $(5,093) $3,398 $12,041 $20,532
Alterationi $29,417 $(8,643) $2,339 $(38,060) $(27,078)
Small Office
New $(5,471) $470 $15,375 $5,941 $20,846
Alteration $16,379 $2,042 $16,742 $(14,337) $363
Medium Office
Newii $202,728 $43,195 $64,773 $(159,533) $(137,955)
Alterationiii - - - $- $-
i Residential HPWH alteration costs are for a gas tankless water heater. TDV and customer benefits are compared to this baseline. For gas storage results see Appendix C.
ii Medium office dollar benefits include entirety of annual space heating energy, assuming no increase in electricity consumption.
iii Medium office package alterations will be less cost effective than new construction due to baseline system design. Detailed calculations have not been performed. See Appendix C for
discussion.
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4. BARRIERS AND FEASIBILITY RESULTS
This section summarizes potential code, technical, and operational barriers associated with heat pump
appliances as compared with natural gas equipment. The summary is based on interviews and survey results
with local contractors, engineers, architects, designers, and energy consultants, as well as TRC’s experience
conducting cost effectiveness analysis.
All respondents that indicated they had experience with HPSH also had experience with HPWHs. Survey
respondents primarily had HPWH and HPSH experience in residential retrofits; but one respondent indicated
experience in commercial buildings. Respondents may have suffered interview fatigue, because for most HPSH
questions, only one respondent provided responses. TRC also used the surveys as a general interview guide
when conducting interviews on barriers.
Code Barriers
TRC considered 2016 California Building, Mechanical, Electrical, Plumbing, CALGreen, and Title 24 to determine
code barriers to heat pumps and electrification. Based on TRC’s experience and feedback attained through
industry engagement, TRC determined that the majority of code barriers for heat pump appliances are
associated with Title 24. Barriers include:
Title 24 - Time Dependent Valuation. Title 24 simulation software uses TDV as the compliance metric,
which favors gas equipment to electric equipment. Achieving cost-effective TDV energy savings for all-
electric measures is challenging because TDV valuates electricity usage much higher than gas usage due
to a complex algorithm involving grid management, price of energy, and greenhouse gas emissions. Palo
Alto’s supply of 100% carbon-neutral electricity highlights the shifting energy emissions landscape and
the need to develop unique pathways for all-electric compliance.
Federal Pre-emption. The DOE regulates the minimum efficiencies required for all appliances. State or
city codes that mandate appliance efficiencies higher than the DOE’s risk litigation by manufacturer
industry organizations. Incentive programs and electrification ordinances, however, are unlikely to risk
litigation because they are not mandating high efficiency heat pump appliances.
Lack of Building Department Experience. Many survey respondents replied that they had difficulty
attaining permits due to building inspectors and plan checkers being unfamiliar with heat pump
technology. (Note that these projects may not have been in Palo Alto, but likely in the peninsula). One
respondent indicated that they needed to install a gas fired water heater as a supplemental hot water
source in order to receive a permit. Due to a lack of building department experience, permit applicants
were required to expend effort and costs beyond what would have been required for a natural gas.
Barriers specifically associated with heat pump water heaters include:
Title 24 - Compliance Software Limitations. CBECC-Res and CBECC-Com have recently added the
capability to simulate HPWHs in residential spaces. However, there are still a few barriers:
• HPWHs cannot be simulated in nonresidential spaces.
• HPWHs cannot be simulated as central water heaters in multifamily buildings or combined hydronic
systems in single family buildings.
• HPWHs are compared to a gas water heater baseline, unless gas is not available at the site. When
gas is not available, the HPWH is compared to a baseline of a propane water heater, (which has very
high associated TDV). Being compared to propane would be good for a heat pump measure, but the
CEC definition of gas availability is broad and may favor constructing gas lines where there are none:
“For newly constructed buildings, natural gas is available if a gas service line can be connected to the
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site without a gas main extension. For additions and alterations, natural gas is available if a gas
service line is connected to the existing building.”16
Condensate Drain. As described in Section 2.3.3, a condensate drain may need to be installed to drain
water collected on the evaporator coil to a local sewer line, as per Palo Alto Utility requirements.
Depending on the existing conditions, a P-trap, condensate pump, and sheet rock patching may be
necessary to conform to this requirement.
Barriers specifically associated with heat pump space heating include:
Title 24 - Compliance Software Limitations. CBECC-Res changes the baseline system to an electric heat
pump space heater when the proposed system is a heat pump space heater. This partially removes the
burden that TDV places on electric equipment. However, CBECC-Res and CBECC-Com still have the
following barriers:
• For Mini-splits, ducted or ductless systems, the CEC has been reticent to award performance credit
due to inconsistent performance data from manufacturers, although many building industry
members perceive them to have exceptional energy performance.
• Variable refrigerant flow systems, though relatively common in nonresidential new construction for
their perceived energy efficiency advantages, cannot currently be simulated in compliance software.
Title 24 - Alterations Performance Uncertainty. Palo Alto Utilities is interested in providing an incentive
for HPSH retrofits. Currently, the CEC requires that applicants provide an energy model to prove to the
local building department that a HPSH does not increase energy use. Energy modeling may add an
additional $300 to $500 to the cost of the retrofit in a single family home. The CEC has avoided
developing a prescriptive minimum efficiency for heat pump space heating retrofits as they have for
heat pump water heaters, because of the wide range of energy consumption possible from heat pumps
installed in retrofit situations. A building heat load can vary depending on the envelope, and an
undersized heat pump can consume a large amount of energy due to higher auxiliary resistance heating
runtime.
Technical Barriers
TRC reviewed the technical specifications of heat pump appliances to understand what additional work may be
necessary as compared to the natural gas baseline.
Technical barriers for heat pump appliances include:
Lack of Contractor Experience. HPWH and HPSHs are generally not as prevalent as gas equipment, thus
the majority of contractors may have a lack of experience installing these systems. The lack of
experience may mean that gas systems are often the ‘default’ equipment, and heat pump systems may
be actively discouraged. Furthermore, contractors may increase the cost of heat pump installations to
account for extra time needed to learn how to properly install the equipment and become accustomed
to locational and venting requirements.
Electrical Upgrades. As described in Section 2.3.3, a variety of electrical upgrades may be necessary to
properly serve heat pump equipment.
16 2016 Residential Alternate Calculation Method Manual. California Energy Commission. Available at:
http://energy.ca.gov/business_meetings/2016_packets/2016-06-14/Item07_ACM Ref Manuals/2016 Res ACM Ref Manual June
2016.pdf
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Barriers specifically associated with heat pump water heaters include:
Multiple Trades Necessary. A typical plumber can replace a natural gas water heater without requiring
electrical work. However, when installing a HPWH an electrician will likely need to come on-site to
perform the electrical upgrades described in Section 2.3.3. This may increase planning, installation time,
and cost for the owner.
Lower Expected Useful Life. HPWHs, along with natural gas storage water heaters, are generally
expected to have a useful life of 13 years. Tankless water heaters, on the other hand, have an expected
useful life of 20 years. A lower useful life is associated with higher equipment replacement costs.
TRC did not find many significant barriers specifically associated with the HPSH investigated as part of this study,
likely because HPSH has many of the same technical elements as traditional space cooling. Nonetheless, HPSH
may prove to be ineffective in high capacity commercial scenarios, such as restaurants or fitness centers, but the
feasibility with these building types has not been investigated as part of this study.
Operational Barriers
Operational barriers relate to the readiness of the local building industry to implement and maintain heat pump
measures. Barriers are listed below, but it’s important to note that some survey respondents chose to note
advantages associated with heat pump appliances in addition to the barriers. Five out of six respondents have
not had any issues with the HPWH since installation; three of which say they perform great. One respondent is
not pleased with the systems performance.
Barriers specifically associated with heat pump water heaters include:
Location and Space Heating Impacts. Inexperienced installers may unknowingly install heat pump
equipment in poor locations, unnecessarily increasing energy consumption. Heat pump heating
equipment rejects cold air, and if the heat pump heat rejection is located in or near conditioned space,
there is potential to increase space heating demand (although, this may reduce space cooling).
Air Filter Replacement. HPWHs require frequent evaporator filter cleaning and occasional replacement.
This is a relatively simple procedure that most homeowners can perform, but many may not be
accustomed to doing so.
Grid Interaction. Grid interactive water heaters, which are designed to reduce the peak load profiles
and flatten the demand curve to reduce the impact on the grid, are available primarily for electric
resistance water heaters. When HPWHs support this feature on the market, it may allow many
homeowners or facilities managers to reduce their energy bill by responding to demand response
events.
Barriers specifically associated with heat pump space heating include:
Refrigerant in Occupied Space. Locating refrigerant piping in occupied spaces carries some health risk if
the refrigerant is discharged. Systems installed according to ASHRAE Standard 15, which specifies the
safe design, construction, installation, and operation of refrigeration systems, reduce this risk.
Lower Supply Air Temperature. One interviewee indicated the operation of a HPSH is significantly
different than a furnace, and may require some time for the occupant to adjust expectations. Heat
pump controls are designed to maintain temperature, and thus run for longer and provide cooler air
than a furnace. Stakeholder feedback indicates that this slower response time may be acceptable for
residential space conditioning, but in commercial designs that require conditioning of high volumes of
outside air, heat pump systems may need to be drastically increased in size and may operate in electric
resistance mode more frequently.
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5. CONCLUSIONS AND RECOMMENDATIONS
While TRC found some code, technical, and operational barriers to HPWH and HPSH implementation, they are
not insurmountable. Heat pump technology is emerging and there is potential for increased adoption in Palo
Alto. Many of the code barriers are associated with Title 24 compliance software modeling, which the CEC is
working toward addressing or eliminating. Residential technical barriers predominantly relate to the lack of
experience from contractors, building departments, and owners with HPWHs. These barriers are expected to
dissipate with increased penetration of HPWHs. The commercial building industry is much more familiar with
heat pump systems, but market-ready HPSH may not yet be widely available at a competitive cost for many
high-temperature, high-capacity applications, such as heat pump boilers or providing makeup air in restaurants.
Based on current code and retail rates assumptions, the majority of scenarios for HPWH and HPSH do not prove
cost effective. However, as policies and rates change over time, electrification may become more cost effective
for Palo Alto in the future. Improved heat pump equipment that achieve similar outlet temperatures to gas
equipment, and/or avoid costly electrical upgrades in existing buildings, are emerging.17 As these products
proliferate, market forces will drive down prices and improve the cost effectiveness of electrification.
Justifying comprehensive electrification policies or programs may be challenging based on the cost effectiveness
criteria in this study. But, there may be other reasons to implement such policies, such as reducing future
greenhouse gas emissions. The following steps may help reduce barriers to electrification and/or improve cost
effectiveness outcomes:
Introduce training programs. Familiarizing the local building industry and building department with the
characteristics and requirements of heat pump appliances will streamline the installation process for
interested building owners.
Reduce code barriers. Palo Alto should continue discussions with the CEC on how address or work
around compliance software barriers related to modeling heat pump equipment. A local sewer use
ordinance requiring that condensate drains be connected to sewer lines appears costly and may
dissuade potential heat pump water heater installations in existing homes.
Incentivize heat pumps. HPWHs are currently incentivized through Palo Alto Utilities. These types of
incentives make heat pump measures more attractive and more cost effective, compensating for a
portion of the electrical upgrades necessary and lower expected useful life compared to a tankless water
heater. Offering incentives for more comprehensive electrification efforts, such as pairing with high
efficacy lighting and photovoltaic measures, may also help improve cost effectiveness from the
customer perspective.
Future Analysis
There are many assumptions built into the cost effectiveness estimates, and minor variations may lead to
significant changes in results. Further analysis can help better understand the range of outcomes possible,
including:
Adjusting Residential Electric Rates. Analysis indicates that increased electrical usage pushes many
residential customers in Palo Alto into a more expensive Tier 2 rate usage. Data from City of Palo Alto
Utilities shows that single family homes consume a median of 15.6 kWh/day, and an average of 19.6
kWh/day. TRC simulations show that an existing single family home that installs HPWH and HPSH could
17 Mayekawa and Stiebel products are good examples.
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use 10 kWh more per day in an average year. Increasing Tier 1 from the current 11 kWh/day to
compensate for increased electric loads will reduce electric bills and improve customer cost
effectiveness. Another method to electric bills would involve charging customers Tier 1 rates until the
monthly allotment for Tier 1 is exceeded, at which point every extra kWh would be charged at Tier 2
rates. However, this may require significant upgrades in Utilities’ metering and billing systems.
Imposing a Carbon Tax on Natural Gas. Natural gas prices are likely to remain low in the near future due
to domestic shale resources. Increasing the price of natural gas through a carbon tax will increase the
cost of gas space and water heating, and may improve the relative cost effectiveness of heat pump
appliances.
Expanding Scope. All-electric packages may be more cost effective than heat pump packages due to
avoiding costs associated with natural gas infrastructure. Even though HPWHs and HPSHs are among the
most readily available electrification measures, cost effectiveness outcomes can vary when accounting
for:
• Photovoltaics, battery storage, electric vehicles, and demand response
• Electrical efficiency measures, such as Energy Star appliances and high efficacy lighting
• Other commercial buildings types like restaurants and fitness centers
• Future appliance cost reductions due to increased availability, performance, or incentives
Mixing and matching combinations of assumptions are likely to lead to a variety of solutions that can be cost
effective and highlight different policy levers to encourage electrification.
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6. APPENDIX A – PROTOTYPE DETAILS
Baseline prototypes characteristics are summarized in Figure 6 and Figure 7. The air conditioning and water
heating systems represent what would be installed as the new construction and alteration baseline scenarios.
Figure 6. Residential Baseline Prototypes Summary
Building Type One-Story Two-Story Low-Rise Multifamily
Dwelling Units 1 2 8
Area (ft2) 2,100 2,700 6,960
Roof Area (ft2) 2,520 1,740 4,176
# of floors 1 2 2
Window-to-Floor Area Ratio 20% 20% 15%
HVAC System Central Ducted Split Air Conditioner with Gas Furnace*
HVAC Distribution System Ducts in Attic Ducts in Attic Ducts in Conditioned Space
Thermal Zones 1 2 4
Domestic Water Heating
(New Construction)
Natural Gas Tankless Water Heater, 0 Gallon Tank,
EF=0.82
8x Natural Gas Tankless Water
Heater, 0 Gallon Tank,
EF=0.82
Domestic Water Heating
(Alteration)
Natural Gas Small Storage, 50 Gallon Tank, EF = 0.6 8x Natural Gas Small Storage,
50 Gallon Tank, EF = 0.6, 40
MBH Input Rating, Demand
Control Recirculation
* TRC estimates that, based on 2009 Residential Appliance Saturation Survey, central gas furnaces (with and without
cooling) comprise over 50% of HVAC installations in Palo Alto.
Figure 7. Nonresidential Baseline Prototypes Summary
Building Type Medium Office Small Office
Floor Area (ft2) 53,628 5,502
# of floors 3 1
Window-to-Floor Area Ratio 33% 21%
HVAC Distribution System 3x Packaged Variable Air Volume with
VAV Hot Water Reheat
5x Packaged Single Zone Air Conditioners
Cooling System Direct Expansion, 9.8 EER, Economizer Direct Expansion, 13 SEER, No Economizer
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Heating System Boiler, 80% Thermal Efficiency
Furnace, 78% AFUE
Conditioned Thermal Zones 18 6
Domestic Water Heating Natural Gas Small Storage, EF = 0.637
Figure 8 and Figure 9 compare in detail the building characteristics for new construction and alteration
scenarios. Using property data courtesy of the City of Palo Alto, TRC determined that the average existing
building in Palo Alto was built in the early 1960’s for all building types, which was before California adopted any
building energy efficiency code. TRC simulated prototypes with “pre-code” conditions to estimate the energy
impact of alterations, particularly on space heating energy consumption.
Figure 8. Residential Pre-code and New Construction Assumptions
Component Pre-Code New Construction (2016 T24)
Envelope Attic Insulation (R-value) 13 30
Radiant Barrier No Yes
Below Roof Deck Insulation (R-
value) 0 13
Window U-Factor 0.81 0.32
Window SHGC 0.59 0.25
Infiltration ACH50 7 5
Lighting Power Adjustment Multiplier 0.9 0.63
Fraction Portable 0.5 0.22
HVAC Duct Location Attic Attic
Duct Leakage 10% 6%
HERS Verified Duct Sealing No Yes
Duct Insulation (R-value) 2.1 6
IAQ Fan W/cfm None 0.25
Whole House Fan No No
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Figure 9. Nonresidential Pre-code and New Construction Assumptions
Component Pre-Code New Construction (2016 T24)
Roof Insulation (R-Value) 8 35
Roof Solar Reflectance 0.10 0.63
Wall Insulation (R-Value) 0 14
Window U-Factor 1.23 0.36
Window SHGC 0.71 0.25
Window VT 0.42 0.60
Lighting Power Density (W/ft2) 1.2 0.75
Given the inputs in the preceding figures, the baseline energy usage for the new construction and alteration
buildings is summarized in Figure 10.
Figure 10. Baseline Prototype Total Annual Energy Usage
Prototypes
New Construction Alteration
kWh Therms kWh Therms
2100 ft2 Single Family 3,861 344 4,614 455
2700 ft2 Single Family 4,608 398 5,174 523
Low-rise
Multifamily
(8 units)
Building 21,767 1,262 23,607 1,666
Per Dwelling Unit 2,721 158 2,951 208
Small Office 55,200 440 63,200 901
Medium Office 427,700 3,665 490,000 8,161
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7. APPENDIX B – COST DATA
This Appendix provides further detail on cost assumptions and sources.
Heat Pump Measures
Heat pump water heater costs include equipment, maintenance, and overhead and profit (Figure 11). TRC
includes equipment replacement costs over a 30-year span for residential buildings, and 15 years for
nonresidential buildings (see Section 2.2.1). For example, a tankless water heater has an expected useful life
(EUL) of 20 years, so TRC assumes 1.5 replacements over 30 years in residential applications. The EULs for
tankless, storage, and heat pump water heaters are 20 years, 13 years, and 13 years, respectively.
In most cases, the AO Smith HPTU was the best performing NEEA-rated HPWH. Because TRC is using the energy
savings for this particular equipment, the incremental costs below are reflective of this particular product.
Compared to the 80 data points that TRC retrieved from online retailers, distributors, contractors, and RS
Means, the AO Smith product is slightly higher ($600) than average incremental cost for one HPWH, including
non-NEEA rated equipment.
Figure 11. Heat Pump Water Heater Incremental Cost Summary
Water Heater Cost / Unit Single Family Multifamily Nonresidential
Baseline – Gas Tankless, EF = 0.82 $5,301 $5,301 $42,413 n/a
Baseline – Gas Storage, EF = 0.60 $6,734 $6,374 $50,991 $5,276
Heat Pump Water Heater (AO Smith HPTU) $7,933 $7,933 $63,465 $5,976
Incremental Cost – Tankless Baseline $2,631 $21,052 n/a
Incremental Cost – Gas Storage Baseline $1,559 $12,473 $700
Residential heat pump space heating costs are lower than conventional air conditioners with a gas furnace
(Figure 12 and Figure 13). Costs for alterations are slightly higher because of the higher capacity equipment
needed in pre-code buildings. Costs include materials, thermostats, calibration, startup, and overhead and
profit. TRC assumes that maintenance and expected useful life of the heat pump equipment is similar to
conventional equipment. Costs and mechanical designs are derived from interviews with over ten (10)
mechanical contractors and distributors.
Figure 12. Residential New Construction Heat Pump Space Heating Incremental Cost Summary
Measure 2100 ft2 Single Family 2700 ft2 Single Family Multifamily
Baseline – Split AC and Furnace $7,997 $14,743 $48,520
Heat Pump Space Heater $4,750 $8,868 $27,640
Incremental Cost $(3,247) $(5,875)
$(20,880)
Average Incremental Cost $(4,561)
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Figure 13. Residential Alteration Heat Pump Space Heating Incremental Cost Summary
Measure 2100 ft2 Single Family 2700 ft2 Single Family Multifamily
Baseline – Split AC and Furnace $9,628 $15,557 $56,580
Heat Pump Space Heater $5,960 $11,072 $32,940
Incremental Cost $(3,938) $(4,484)
$(23,640)
Average Incremental Cost $(4,211)
TRC attained commercial space conditioning costs through discussions with a distributor, a mechanical design
firm, and RS Means.
Incremental cost data points for the small office in Figure 14 represent material costs, including overhead and
profit, for one (1) rooftop unit. The incremental cost for the building accounts for five (5) rooftop units. TRC
estimated new construction equipment capacities to be 2 tons per unit (10 tons for the entire office), while
alteration capacities to be 6 tons per unit (30 tons for the entire office).
Figure 14. Small Office Packaged Heat Pump Incremental Cost Summary
Cost Source
Baseline – Single Zone Air
Conditioner (1 unit) Packaged Heat Pump (1 unit) Incremental Cost
New
Construction Alteration New
Construction Alteration New
Construction Alteration
Cost Source #1 $3,029 $7,087 $2,994 $7,563 $(35) $476
Cost Source #2 $6,000 $9,500 $8,750 $11,500 $2,750 $2,000
RS Means $5,593 $8,031 $5,495 $9,903 $(98) $1,873
Average Incremental Cost per Rooftop Unit $872 $1,450
Average Incremental Cost per Building (5 Rooftop Units) $4,361 $7,248
TRC received costs from a distributor, mechanical design firm, and plumbing firm for the costs of installing a
heat pump boiler and larger VAV coils, compared to a baseline gas boiler system (Figure 15, Option #1). TRC also
obtained costs for a VRF system from one of the sources (Option #2). Because the cost estimate for the VRF
system was much higher than the HP boiler, TRC only investigated Option #1.
One of the cost sources provided costs for the entire baseline and heat pump system, while the other source
only provided costs for the boilers (not including upsized VAV terminal units). The total incremental cost is
obtained by averaging the cost of the heat pump boiler estimates ($106,700) and adding the cost of the larger
VAV terminal units, pipes, and pumps ($104,000).
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Figure 15. Medium Office Incremental Cost Summary
Cost Source
Incremental Cost Compared to Gas Boiler and PVAV Reheat Baseline
Option #1
Option #2 - Variable
Refrigerant Flow Heat Pump Boiler Larger VAV Terminal Units,
Pipes, and Pumps
Cost Source #1 $108,000 $104,000 $689,000
Cost Source #2 $105,400 Not provided Not Provided
Average $106,700 - -
Total Incremental Cost $210,700 $689,000
Infrastructure Upgrades
Electrical costs in Figure 16 were determined from RS Means data and assumptions for lengths of conduit and
wiring based on the geometry of the prototypes and likely paths. Service connection fees were coordinated with
the City of Palo Alto.
Figure 16. Electrical Infrastructure Costs
Building Type Upgrade Cost Component
Scenario
New Construction Alteration
Single Family
HPWH Branch Circuit (15A to 30A) $50 $640
Electrical Panel (100A to 200A) $0 $3,181
Service Connection (Utility Fee) $0 $850
Total $50 $4,671
Low-rise Multifamily
(8 dwelling units)
HPWH Branch Circuit (15A to 30A) $400 $5,120
Electrical Panel (60A to 125A) $0 $20,792
Service Connection (Utility Fee) $0 $1,160
Total $400 $35,192
Small Office
HPSH Branch Circuits (50A to 80A) (5 units) $1,729 $4,399
HPWH Branch Circuit (20A to 30A) $77 $1,365
Total $1,806 $5,764
Medium Office
HP Boiler Branch Circuit (20A to 80A) $1,828 $4,381
HPWH Branch Circuit (20A to 30A) $77 $1,365
Total $1,905 $5,746
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Figure 17 depicts cost estimates for connecting and distributing natural gas to each prototype. These costs may
be avoided in an all-electric building. TRC coordinated costs associated with the utility with Palo Alto. To attain
the indoor plumbing distribution costs, TRC developed routing schematics to estimate the length of gas piping
needed for each prototype, and multiplied pipe lengths by costs per linear foot attained through RS Means.
Figure 17. Natural Gas Plumbing New Construction Infrastructure Costs
Cost Component Single Family Low-rise
Multifamily Small Office Medium
Office
Plan review $848 $848 $2,316 $2,316
Connection Charge (1”) $4,343 $4,343 $4,343 $4,343
Meter(s) $850 $6,800 $1,886 $1,886
Meter Manifold $0 $3,703 $0 $0
Indoor Plumbing Distribution $371 $2,012 $3,793 $1,933
Total $6,412 $17,706 $12,338 $10,478
Relevant permit fees (Figure 18) are added to the cost of appliance replacements and electrical and plumbing
improvements.
Figure 18. Permit Fees
Water Heater Single Family Low-Rise
Multifamily Small Office Medium Office
Electrical $120 $212 $118 $157
Mechanical $120 $316 $117 $132
Plumbing $97 $132 $117 $117
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8. APPENDIX C – COST EFFECTIVENESS TABLES
This section provide itemized cost effectiveness tables for the summary tables in Section 3. If Net Savings (in the
far right column of each table) is positive, then the measure or package is considered cost effective.
In the following tables, package savings are attained by simulating both HPWH and HPSH simultaneously, which
produces TDV and on-bill savings that are different than the sum of their parts due to interactive effects and
Palo Alto Utilities’ tiered rate structure. Thus, the total savings are not simply the sum of the TDV and on-bill
savings columns. However, incremental costs do add up to the package cost totals in new construction tables. In
alteration tables, incremental costs are slightly inconsistent with the package cost totals, to avoid duplicating
permit costs.
Two sets of packages are developed. The first package is the total costs and savings when implementing both
heat pump measures. These results are reflected in the top half of Figure 5 in Section 3. The second package is
an all-electric package, which assumes natural gas will be not be connected to the building in new construction,
or disconnected from the building in alterations. Note, this analysis only considers the incremental costs for
electrifying water and space heating equipment, not other appliances such as stovetops or clothes driers.
Residential
TRC averaged results for the single family residential 2100 ft2 and 2700 ft2.
Single Family New Construction
Heat pump space heating and the packages are cost effective in single family new construction using the TDV
cost effectiveness methodology (Figure 19). Heat pump water heaters are not cost effective standalone, but
heat pump space heaters are cost effective because central split heat pumps are significantly cheaper than the
baseline central split air conditioner and furnace. Cost effectiveness increases when also considering the cost
savings associated with avoiding a natural gas connection.
Figure 19. Single Family New Construction TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater $222 $2,631
$(2,459)
New 30A branch circuit - $50
Heat pump space heater $619 $(4,561) $5,180
Heat pump package $760 $(1,879) $2,639
Avoided natural gas connection $- $(6,412) $6,412
All-electric package $760 $(8,292) $9,051
Using the customer cost effectiveness methodology (Figure 20), neither individual heat pump measures nor the
package achieve on-bill savings. This may be due to Palo Alto Utilities tier structure -- baseline building gas usage
falls mostly under Tier 1, while the heat pump measures increase electricity usage to Tier 2. This translates to
electricity costs higher than gas costs, and thus negative on-bill savings.
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Although no Customer Benefits are realized, the heat pump space heater and the all-electric package have Net
Savings and are cost effective because the central split heat pumps are less expensive than the baseline gas
furnace system, and avoiding a natural gas line connection results in substantial cost savings.
Figure 20. Single Family New Construction Customer Cost Effectiveness
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental Cost Customer Net
Savings
Heat pump water heater (920) 123 $(1,917) $2,631
$(4,599)
New 30A branch circuit - - - $50
Heat pump space heater (1,761) 193 $(2,728) $(4,561) $1,833
Heat pump package (2,710) 327 $(4,925) $(1,879) $(3,046)
Avoided natural gas
connection - - $3,495 $(6,412) $9,908
All-electric package (2,710) 327 $(1,430) $(8,292) $6,862
Stiebel 220E Results
The Stiebel 220E can operate with a 15A branch circuit. Thus, upgrading the branch circuit to 30A, which is
required for most HPWH products available on the market, is not necessary with the Stiebel. The Stiebel can
thus forego the branch circuit upgrade in the new construction scenario.
The Stiebel is not cost effective on its own using TDV, but both packages are cost effective (Figure 21). The
packages are not as cost effective as with the AO Smith in Figure 19 because the Stiebel has a higher incremental
cost for the water heater, and produces slightly less TDV Benefits.
Figure 21. Single Family New Construction TDV Cost Effectiveness – Stiebel 220E
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater (Stiebel) $187 $4,993 $(4,806)
Heat pump space heater $619 $(4,561) $5,180
Heat pump package $1,104 $432 $672
Avoided natural gas connection - $(6,412) $6,412
All-electric package $1,104 $(5,980) $7,084
With the customer cost methodology, the Stiebel is only cost effective in the all-electric package (Figure 22).
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Figure 22. Single Family New Construction Customer Cost Effectiveness – Stiebel 220E
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental Cost Customer Net
Savings
Heat pump water heater (978) 130 $(2,200) $4,993 $(7,193)
Heat pump space heater (1,761) 193 $(2,728) $(4,561) $1,833
Heat pump package (2,697) 327 $(6,156) $432 $(6,588)
Avoided natural gas
connection
- - $3,495 $(6,412) $9,908
All-electric package (2,710) 327 $(2,661) $(5,980) $3,320
Single Family Alterations
While single family alterations have significant TDV savings with heat pump water heaters, the TDV savings are
less than the costs associated with electrical upgrades (Figure 23). Note that the Net Savings for both of the heat
pump water heater scenarios (gas storage and gas tankless baseline) include all of the associated costs for
branch circuits, permits, condensate drain, and service connection upgrade fee.
Figure 23. Single Family Alterations TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater (gas storage baseline) $1,605 $1,559 $(5,843)
Heat pump water heater (gas tankless baseline) $96 $2,631 $(8,424)
New 30A branch circuit + permits - $857
Condensate drain - $1,000
Service connection upgrade fee - $850
Panel upgrade - $3,181
Heat pump space heater $(224) $(4,211)
$3,866
Permits - $120
Heat pump package (gas storage baseline) $1,351 $2,506 $(1,155)
Heat pump package (gas tankless baseline) $(158) $3,579 $(3,737)
Gas disconnection - $1,433 -
All-electric package (gas storage baseline) $1,351 $3,939 $(2,588)
All-electric package (gas tankless baseline) $(158) $5,012 $(5,170)
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The customer cost effectiveness approach does not show any of the package scenarios as cost effective, even
when considering $3,495 in bill savings from avoided monthly gas connection charges (Figure 24). The heat
pump measures do not generate any on bill savings and the costs of the equipment and the associated electrical
upgrades further reduce the cost effectiveness of this package.
Figure 24. Single Family Alterations Customer Cost Effectiveness
Measure
kWh
Savings
Therms
Savings Customer
Benefits
Incremental
Cost
Customer
Net
Savings
Heat pump water heater (gas storage baseline (1,046) 181 $(1,127) $1,559 $(8,604)
Heat pump water heater (gas tankless baseline) (1,046) 130 $(1,503) $2,631 $(10,022)
New 30A branch circuit + permits - - - $857
Condensate drain - - - $1,000
Service connection upgrade fee - - - $850
Panel upgrade - - - $3,181
Heat pump space heater (2,726) 260 $(4,775) $(4,211) $(685)
Permits - - - $120 -
Heat pump package (gas storage baseline) (3,680) 445 $(3,588) $2,506 $(6,094)
Heat pump package (gas tankless baseline) (3,680) 394 $(5,375) $3,579 $(8,953)
Gas disconnection - - $3,495 $1,433 $2,062
All-electric package (gas storage baseline) (3,680) 445 $(93) $3,939 $(4,032)
All-electric package (gas tankless baseline) (3,680) 394 $(1,880) $5,012 $(6,891)
Stiebel 220E Results
In alterations, the Stiebel can forego the branch circuit, panel, and service connection upgrades assumed in the
other HWPH scenarios.
Because of reduced electrical expenses associated with the Stiebel, the heat pump package heat pump package
is cost effective using TDV when compared with a gas storage baseline (Figure 25). The Stiebel does not enable
any cost effective scenarios otherwise.
Palo Alto Electrification Study
34 | TRC Energy Services
Figure 25. Single Family Alterations TDV Cost Effectiveness – Stiebel 220E
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater (gas storage baseline) $1,821 $3,921 $(3,317)
Heat pump water heater (gas tankless baseline) $312 $4,993 $(5,898)
Permits $217
Condensate drain $1,000
Heat pump space heater $(224) $(4,211)
$3,866
Permits $120
Heat pump package (gas storage baseline) $1,559 $197 $1,362
Heat pump package (gas tankless baseline) $50 $1,269 $(1,219)
Gas disconnection - $1,433 -
All-electric package (gas storage baseline) $1,559 $1,630 $(71)
All-electric package (gas tankless baseline) $50 $2,702 $(2,652)
Although the Stiebel HPWH does not have electrical upgrade costs, it does not show customer benefits and is
not cost effective, even in the all-electric package (Figure 26).
Palo Alto Electrification Study
35 | TRC Energy Services
Figure 26. Single Family Alterations Customer Cost Effectiveness – Stiebel 220E
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental
Cost
Customer
Net
Savings
Heat pump water heater (gas storage baseline) (970) 181 $(3,352) $3,921 $(8,489)
Heat pump water heater (gas tankless baseline) (970) 130 $(1,887) $4,993 $(8,097)
Permits - - - $217
Condensate drain - - - $1,000
Heat pump space heater (2,726) 260 $(4,775) $(4,211) $(685)
Permits - - $120 -
Heat pump package (gas storage baseline) (3,740) 445 $(3,880) $197 $(4,076)
Heat pump package (gas tankless baseline) (3,740) 394 $(5,667) $1,269 $(6,936)
Gas disconnection - - $3,495 $1,433 $2,062
All-electric package (gas storage baseline) (3,740) 445 $(385) $1,630 $(2,014)
All-electric package (gas tankless baseline) (3,740) 394 $(2,172) $2,702 $(4,873)
Low-Rise Multifamily New Construction
Although there are negative TDV savings for heat pump measures in multifamily new construction, the cost
savings from installing heat pump space heating and avoiding a natural gas connection make the all-electric
package cost effective (Figure 27). The package without considering avoiding a natural gas connection is not cost
effective.
Figure 27. Low Rise Multifamily New Construction TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater $(530) $21,052
$(21,982)
New 30A branch circuit - $400
Heat pump space heater $(2,857) $(20,880) $18,023
Heat pump package $(5,093) $572 $(5,665)
Avoided natural gas connection - $(17,706) $17,706
All-electric package $(5,093) $(17,134) $12,041
Palo Alto Electrification Study
36 | TRC Energy Services
HPSH produces increased energy bills that are greater than the baseline because more Tier 2 charges are
incurred, but less than the material cost savings from switching to heat pump space heating (Figure 28). The
package is only cost effective when considering cost savings from avoiding the natural gas connection.
Figure 28. Low Rise Multifamily New Construction Customer Cost Effectiveness
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental
Cost
Customer
Net Savings
Heat pump water heater (5,590) 716 $198 $21,052
$(21,254)
New 30A branch circuit - - - $400
Heat pump space heater (3,257) 258 $(13,391) $(20,880) $7,489
Heat pump package (8,847) 974 $(24,564) $572 $(25,135)
Avoided natural gas connection - - $27,961 $(17,706) $45,667
All-electric package (8,847) 974 $3,398 $(17,134) $20,532
Low Rise Multifamily Alterations
The heat pump package produces TDV savings when compared to the gas storage baseline, but not the gas
tankless baseline (Figure 29). The highest incremental costs are due to the eight (8) heat pump water heaters
and panel upgrades. None of the package scenarios are cost effective due to the high costs associated with the
equipment and electrical upgrades.
Palo Alto Electrification Study
37 | TRC Energy Services
Figure 29. Low Rise Multifamily Alterations TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater (gas storage baseline) $10,488 $12,473 $(33,402)
Heat pump water heater (gas tankless baseline) $(1,856) $21,052 $(54,324)
New 30A branch circuit + permits - $5,464
Condensate drain - $4,000
Service connection upgrade fee - $1,160
Panel upgrade - $20,792
Heat pump space heater $(6,787) $(23,640)
$16,537
New 50A branch circuit + permits - $316
Heat pump package (gas storage baseline) $3,701 $19,405 $(15,705)
Heat pump package (gas tankless baseline) $(8,643) $27,984 $(36,627)
Gas disconnection - $1,433
All-electric package (gas storage baseline) $3,701 $20,838 $(17,138)
All-electric package (gas tankless baseline) $(8,643) $29,417 $(38,060)
Multifamily alterations for HPSH show large Net Savings due to bill savings and lower materials costs (Figure 30).
The all-electric package shows NPV savings, but none of the package scenarios are cost effective due to the high
costs for equipment and electrical upgrades.
Palo Alto Electrification Study
38 | TRC Energy Services
Figure 30. Low Rise Multifamily Alterations Customer Cost Effectiveness
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental
Cost
Customer
Net Savings
Heat pump water heater (gas storage baseline) (6,378) 1,144 $(1,194) $12,473 $(45,084)
Heat pump water heater (gas tankless baseline) (6,378) 716 $(11,146) $21,052 $(63,614)
New 30A branch circuit + permits - - - $5,464
Condensate drain - - - $4,000
Service connection upgrade fee - - - $1,160
Panel upgrade - - - $20,792
Heat pump space heater (3,329) 234 $21,987 $(23,640)
$45,311
New 50A branch circuit + permits - - - $316
Heat pump package (gas storage baseline) (8,919) 1,378 $(14,757) $19,405 $(34,163)
Heat pump package (gas tankless baseline) (8,919) 949 $(25,622) $27,984 $(53,606)
Gas disconnection - - $27,961 $1,433 $26,528
All-electric package (gas storage baseline) (8,919) 1,378 $13,204 $20,838 $(7,635)
All-electric package (gas tankless baseline) (8,919) 949 $2,339 $29,417 $(27,078)
Nonresidential
As described in Section 2.3.1, high-rise multifamily simulations with HPWHs served as a proxy for nonresidential
HPWH performance. The high-rise multifamily results showed very similar TDV performance for HPWH and
natural gas storage water heaters. Because this method likely has significant error bounds, TRC assumed a
neutral TDV impact for nonresidential HPWHs to avoid influencing results. However, TRC estimated on bill
savings by determining the relative monthly energy input of a HPWH compared to the monthly input of a gas
water heater, and applying the same relationship to the office gas water heater monthly energy input.
Small Office New Construction
Packaged heat pumps show slight TDV savings, not enough to compensate for the minor increase in materials
and installation cost. The all-electric package is cost effective due to $12,338 in savings for avoiding the
installation of natural gas piping.
Palo Alto Electrification Study
39 | TRC Energy Services
Figure 31. Small Office New Construction TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater $0 $700
$(777)
30A branch circuit - $77
Packaged heat pump $470 $4,361
$(5,620)
50A branch circuit - $1,729
Heat pump package $470 $6,867 $(6,397)
Avoided natural gas connection - $(12,338) -
All-electric package $470 $(5,471) $5,941
The customer cost effectiveness method shows savings for the heat pump measures and $1,864 in avoided
monthly natural gas charges (Figure 32). As in the previous table, the all-electric package is cost effective largely
due to avoided natural gas connection charges.
Figure 32. Small Office New Construction Customer Cost Effectiveness
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental
Cost
Customer Net
Savings
Heat pump water heater (844) 99 $435 $700
$(342)
New 30A branch circuit - - - $77
Packaged heat pump (1,467) 185 $357 $4,361
$(5,733)
New 50A branch circuits - - - $1,729
Heat pump package (2,311) 285 $792 $6,867 $(6,075)
Avoided natural gas
connection - - $14,583 $(12,338) $26,921
All-electric package (2,311) 285 $15,375 $(5,471) $20,847
Small Office Alterations
Although packaged heat pumps have $2,042 in TDV savings, the equipment costs make the individual measure
and the all-electric package not cost effective (Figure 33).
Palo Alto Electrification Study
40 | TRC Energy Services
Figure 33. Small Office Alterations TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater $0 $700
$(3,187) New 30A branch circuit - $1,487
Condensate drain - $1,000
Packaged heat pump $2,042 $7,248
$(5,445)
New 50A branch circuits - $240
Heat pump package $2,042 $10,670 $(8,628)
Gas disconnection - $1,433 -
All-electric package $2,042 $11,980 $(9,938)
The only small office alteration package that is cost effective with the customer cost effectiveness methodology
is all-electric (Figure 34).
Figure 34. Small Office Alterations Customer Cost Effectiveness
Measure kWh
Savings
Therms
Savings
Customer
Benefits
Incremental
Cost
Customer Net
Savings
Heat pump water heater (844) 99 $435 $700
$(2,752) New 30A branch circuit - - - $1,487
Condensate drain - - - $1,000
Packaged heat pump (4,870) 648 $1,724 $7,248
$(10,162)
New 50A branch circuit - - - $4,639
Heat pump package (5,714) 747 $2,159 $15,068 $(12,909)
Avoided natural gas
connection - - $14,583 $1,433 $13,150
All-electric package (5,714) 747 $16,742 $16,379 $364
Medium Office
CBECC-Com is currently unable to model a heat pump boiler. However, TRC estimated cost effectiveness
through the alternative approach described below.
Palo Alto Electrification Study
41 | TRC Energy Services
TDV Cost Effectiveness
As mentioned at the beginning of Section 8.2, nonresidential heat pump water heaters were assumed to have a
neutral TDV impact. TRC received an incremental cost of nearly $160,000 for implementing a heat pump boiler,
which was determined to be the cheapest and most straightforward heat pump alternative to the baseline VAV
reheat system. The incremental cost of the heat pump boiler alone is larger than the entirety of the TDV heating
savings possible for the medium office ($43,195). In other words, if the heat pump boiler completely eliminated
natural gas heating energy, without increasing any electric consumption, the packaged would still not be cost
effective (Figure 35).
Figure 35. Medium Office New Construction TDV Cost Effectiveness
Measure TDV Benefits Incremental Cost TDV Net Savings
Heat pump water heater $0 $700
$(777)
New 30A branch circuit - $77
Heat pump boiler + Larger VAV coils $43,195i $210,700
$(169,234)
New 80A branch circuit - $1,729
Heat pump package $43,195i $213,206 $(170,011)
Avoided natural gas connection - $(10,478) -
All-electric package $43,195i $202,728 $(159,533)
i This value does not represent the simulated TDV Benefits, but the maximum possible savings.
The retrofit of the medium office presents an even more expensive situation where existing VAV coils would
need to be removed and replaced with larger coils. The incremental cost of this work would be added to the
$159,450 incremental cost of the heat pump boiler. TRC did not pursue attaining these costs because of the
extremely low chances of being cost effective, and does not believe that a cost effective electrification alteration
option exists for the medium office.
Customer Cost Effectiveness
In a similar manner as the TDV cost effectiveness method, TRC calculated a hypothetical maximum for customer
heating savings from a heat pump boiler. TRC calculated the annual heating bills associated with the natural gas
boiler to be approximately $3,169. Over the 15-year analysis period, this translates to a NPV of $49,227 (Figure
36). This is the maximum possible savings by switching to the heat pump boiler for space heating. Thus, without
even considering an increase in electric bills by switching to a heat pump boiler, the NPV does not exceed the
$159,450 in materials cost to implement the heat pump measure.
Palo Alto Electrification Study
42 | TRC Energy Services
Figure 36. Medium Office New Construction Customer Cost Effectiveness
Measure kWh Savings Therms
Savings
Customer
Benefits
Incremental
Cost
Customer Net
Savings
Heat pump water heater (5,644) 664 $963 $700
$186
New 30A branch circuit - - - $164
Heat pump boiler + Larger
VAV coils
not
simulated 3,007 $49,227i $210,700
$(163,202)
New 80A branch circuit - - - $1,729
Heat pump package (5,644) 3,671 $50,190i $213,206 $(163,016)
Avoided natural gas
connection - - $14,583 $(10,478) $25,061
All-electric package (5,644) 3,671 $64,773i $202,728 $(137,955)
i This value does not represent the simulated Customer Benefits, but a hypothetical maximum.
As described previously, the retrofit situation for the electrification package represents an even less likely cost
effective scenario. Note, however, that the heat pump water heater measure is cost effective in the medium
office, which uses more domestic hot water than the small office.
The alteration cost for a HPWH ($700), upgrading to a 30A circuit ($1,644), and adding a condensate drain
($1,000) amounts to a total incremental cost of $3,344. Compared to the $963 in savings the HPWH, the Net
Savings is $(2,381) and the HPWH is not cost effective for the medium office alteration.
Palo Alto Electrification Study
43 | TRC Energy Services
9. APPENDIX D – SURVEY INSTRUMENT
The project team distributed an online survey to local industry members to gather feedback on heat pump
water heaters (HPWH) and heat pump space heaters (HPSH) installations and experience. The survey was
distributed to about 500 industry members, including contractors, plumbers, architects, and design engineers,
and 15 responses were received.
Although the survey below references only heat pump water heaters, the same questions were also asked for
heat pump space heaters, but are not shown here to conserve space.
TRC also used the survey as a general interview guide.
Please respond to the following questions based on your experience and knowledge of heat pump water heaters (HPWH)
through specifying, installing, and/or using HPWHs. Our team may follow up with further inquiries. Please include your
name and contact information.
Name:
Profession:
Email: Phone:
1. What experience have you had with HPWHs? (choose all that apply)
• Specifying
• Installing
• Using
• Other:
2. What building type(s) was the installation for? (choose all that apply)
• Residential (single family, low-rise multifamily)
• High-rise multifamily
• Commercial (<10,000 ft2)
• Commercial (>10,000 ft2)
• Other:
3. Was the installation(s) part of a new construction or retrofit project, or both? If experienced in both new
construction and retrofit, are there different considerations for using HPWH between th e two project types?
4. Why did you choose HPWH? What are the primary benefits of HPWH?
5. What was the cost of the HPWH system? Please specify approximate components included in cost (e.g.,
capacity/size, equipment, labor, demolition, etc)?
6. Were there any challenges in getting permits to install the HPWH? If so, what were the challenges?
7. How did you overcome the challenges?
8. Were there any special considerations for installing HPWH compared to traditional water heaters (e.g., electrical
outlets)? And how did you deal with these issues?
9. Were there any physical challenges in installing the HPWH (e.g., size constraints)? How did you overcome those
challenges?
10. Were there any other barriers or challenges to installing the HPWH, such as:
cost issues?
code or regulatory issues?
Palo Alto Electrification Study
44 | TRC Energy Services
technology issues (products not market-ready, unreliable, etc.)?
maintenance or reliability issues?
contractor or installer skill or training level?
product availability?
customer preference?
11. Where is the HPWH installed?
• Garage
• Outside
• Closet
• Mechanical Room
• Other:
12. How has the HPWH system performed since installation? Have there been any issues with operating the HPWH?
Do HP systems require extra commissioning?
13. What would your recommendations be to simplify the design, installation, or operation of HPWH for future users
of these systems?
Attachment
E:
Excerpt
from
2016
California
Energy
Code
Residential
Compliance
Manual,
Chapter
9
Colleagues Memo from Commissioners Schwartz and Ballantine 2/21/2017 1
City
of
Palo
Alto
Colleagues
Memo
Date:
21
February
2017
From:
Commissioners
Schwartz
and
Ballantine
Subject:
Electrification
or
Fuel
Switching
Background
It
is
commendable
that
so
many
Palo
Alto
citizens,
representatives
on
the
UAC
and
elected
officials
on
the
City
Council
are
committed
to
reducing
our
City’s
contribution
to
CO2
emissions.
If
we
wish
to
be
a
model
for
other
cities,
however,
we
need
to
adopt
and
showcase
practices
that
are
realistic
and
practical
for
other
less
affluent
communities.
We
also
need
to
be
mindful
of
the
laws
of
physics
and
be
rigorous
in
educating
ourselves
about
the
distinctions
between
symbolic
goals
achieved
through
the
use
of
financial
instruments
(Renewable
Energy
Certificates)
and
actual
impact.
Contents:
1.Real
Impact
on
Carbon
Emissions
2.Understanding
the
Facts
of
Our
Generation
Resources
3.Fugitive
Emissions
4.Electrification
of
Transportation
Will
be
More
Effective
5.Innovating
through
the
Use
of
Solar
Thermal
Technologies
(Passive
Solar)
6.Anticipating
Consumer
Reactions
1.Real
Impact
on
Carbon
Emissions
If
building
and
water
heating
and
cooking
equipment
in
Palo
Alto
currently
powered
by
natural
gas
are
replaced
with
electric
appliances,
the
City
will
draw
more
electricity
in
the
morning
and
night
hours
when
solar
plants
are
not
operating.
With
the
widespread
adoption
sought
by
those
who
wish
to
electrify
these
applications,
the
increase
in
load
is
likely
to
exceed
what
we
have
available
from
our
hydro
contracts
(especially
during
droughts).
Those
electrons
will
come
primarily
from
gas-‐fired
plants.
(See
charts
on
pages
3-‐4).
Electric
heating
is
typically
more
expensive
too.
The
California
gas
generation
fleet
has
a
Heat
Rate
of
8513
Btu/kWh1
and
there
will
be
additional
transmission
losses
of
about
10%
so
gas
power
is
delivered
to
CPAU
at
about
9300
Btu/kWh,
or
about
36%
efficiency2.
In
contrast,
modern
condensing
gas
furnaces
and
hot
water
heaters
are
90%
to
98%
efficient
in
converting
fuel
to
heat3.
To
the
extent
that
heating
needs
in
Palo
Alto
are
not
coincident
with
renewable
generation,
it
will
be
far
less
carbon
intensive
to
burn
the
natural
gas
where
heat
is
needed.
In
other
words,
delivering
1
therm
of
heat
requires
between
1.02
and
1.11
therms
if
consumed
locally
compared
to
2.7
therms
with
local
electric
heating.
1 http://www.energy.ca.gov/2016publications/CEC-‐200-‐2016-‐002/CEC-‐200-‐2016-‐002.pdf
2 (3413 Btu/kWh)÷[(8513 Btu/kWh) * 1.10) = 36%
3 https://energy.gov/energysaver/furnaces-and-boilers
1B
Colleagues Memo from Commissioners Schwartz and Ballantine 2/21/2017 2
Air
Source
Heat
Pumps
for
Space
Heating
in
a
moderate
climate
such
as
ours
may
be
an
option
for
new
construction,
where
a
COP4
of
3
is
achievable
with
radiant
floor
heating5.
At
this
heat
pump
efficiency,
1
therm
of
heating
requires
29.3
kWh
of
electric
energy6.
If
the
Heat
Pump
is
powered
by
gas
generation,
it
will
require
2.7
therms
of
gas7.
CPAU
obtains
about
half
of
its
electric
energy
from
market
purchases,
most
of
which
coincide
with
periods
during
which
gas
generation
predominates.
Accordingly,
the
heat
pump
installation
would
consume
about
1.3
therms
of
gas,
about
25%
higher
gas
usage
than
if
a
local
gas
furnace
was
used.
This
runs
counter
to
the
emission
goals
because
the
conversion
of
thermal
energy
to
electricity
combined
with
distribution
losses
are
less
efficient
than
if
the
same
amount
of
natural
gas
is
burned
at
the
customer's
home
or
the
local
restaurant.
To
effectively
reduce
Palo
Alto’s
gas
burn,
it
will
be
necessary
to
adjust
Palo
Alto’s
green
portfolio
to
produce
power
at
the
same
time
of
day
as
the
demand.
While
heat
pumps
provide
reasonable
performance
in
our
relatively
mild
climate,
it
should
be
noted
that
during
cold
periods,
they
consume
additional
electricity
for
resistance
heating.
In
addition,
there
are
other
considerations
such
as
full
cost
of
installation,
setback
encroachment,
noise
emissions,
how
fast
the
conditioned
space
can
be
heated,
use
of
GHG
refrigerants,
etc.
Retrofits
to
forced
air
heating
may
not
be
as
efficient,
and
would
need
extra
space
on
the
exterior
of
homes,
an
additional
electrical
circuit,
and
modifications
for
power
and
plumbing.
Air
Source
Heat
Pumps
for
Water
Heating,
available
with
COP
of
3.58,
are
cost-‐effective
alternatives
to
electric
hot
water
heaters,
but
may
not
heat
fast
enough
(20
gallons
per
hour)
compared
to
gas
hot
water
heaters
(36
gallons
per
hour)
for
families.
The
ambient
operating
requirements
(37-‐145°F/3-‐43°C)
permits
installation
in
unconditioned
spaces,
but
performance
would
suffer
during
winter.
If
installed
within
the
conditioned
space,
this
system
could
provide
some
cooling
in
the
summer,
but
would
increase
space
heating
needs
during
winter
or
at
night.
Also,
these
are
two
to
three
times
more
expensive
than
gas
hot
water
heaters,
reducing
the
payback
for
retrofits.
However
for
households
without
day-‐time
hot
water
needs,
or
offices
with
sufficiently
large
storage
tanks,
Hot
Water
Heat
Pumps
could
help
mitigate
the
over-‐generation
issues
of
the
Duck
Curve,
to
help
avoid
curtailment
of
renewable
power.
4 Coefficient
of
Performance
is
the
ratio
of
Heat
Delivered
to
Power
Consumed
in
the
same
units
5 http://www.icax.co.uk/Air_Source_Heat_Pumps.html
6 [(1 therm) * (100,000 Btu/therm)]÷[(3413 Btu/kWh) * 3.0 kWhth/kWhe)] = 29.3 kWh
7 (29.3 kWh)*(9300 Btu/kWh) * (1 therm/100,000 Btu) = 2.72 therms
8 http://www.rheem.com/product/hybrid-electric-water-heater-professional-prestige-series-hybrid-electric-water-heater
Colleagues Memo from Commissioners Schwartz and Ballantine 2/21/2017 3
2.Understanding
the
Facts
of
Our
Generation
Resources
If
a
local
resident
commuted
to
Sacramento
daily
via
private
jet,
it
would
not
be
an
environmentally
virtuous
way
to
travel
simply
because
the
person
purchased
offsets.
With
our
constant
refrain
of
being
100%
carbon
neutral
(via
RECs),
we
fear
the
City
is
misleading
the
public
as
to
the
true
impact
on
the
GHG
emissions
by
the
proposed
policy
of
electrification.
Natural
gas
is
a
critical
part
of
the
national
energy
supply
providing
a
third
of
the
nation’s
generation
and
more
than
half
of
California’s.
GHG
emissions
are
going
down
in
the
US
because
gas-‐fired
plants
are
replacing
coal
and
oil
in
many
jurisdictions
due
to
cost
advantages.
Continuing
investment
in
wind
and
solar
power
will
bring
California’s
renewable
portfolio
to
50%
by
2030,
but
the
balance
will
be
provided
primarily
by
natural
gas.
New
challenges,
such
as
the
planned
closing
of
the
Diablo
Canyon
nuclear
(carbon
free)
facility
and
the
Duck
Curve
(https://en.wikipedia.org/wiki/Duck_curve),
demonstrate
the
unintended
consequences
when
intermittent
and
variable
energy
sources
do
not
match
real-‐time
demand
on
the
grid.
Palo
Alto
obtains
almost
all
its
electric
power
from
the
grid,
having
no
significant
generation
inside
the
city
limits.
CPAU
may
contract
for
transmission
of
renewable
power,
but
electricity
is
fungible,
and
once
put
on
the
grid,
it
becomes
part
of
the
overall
generation
mix,
and
is
NOT
specifically
delivered
to
Palo
Alto.
Accordingly,
we
must
consider
the
carbon
content
of
California's
electricity.
Of
course,
the
California
energy
mix
is
changing,
and
at
some
point
in
the
future,
we
would
be
indifferent,
from
a
CO2
perspective.
But
that
point
may
still
be
30
or
40
years
from
now,
and
until
then,
we
don't
want
our
city
policies
to
make
climate
change
worse.
http://www.caiso.com/informed/Pages/CleanGrid/default.aspx
Colleagues Memo from Commissioners Schwartz and Ballantine 2/21/2017 4
CAISO
Renewables
Watch
for
February
20,
2017
Note
the
amount
of
Imports
and
Thermal
(natural
gas)
generation
used,
particularly
during
the
early
morning
and
evening
hours.
Imports
are
primarily
natural
gas
or
coal.
If
Palo
Alto
wishes
to
support
renewables
during
those
hours,
we
could
invest
in
geothermal
which
can
run
as
base
load
instead
of
putting
all
new
investments
into
solar.
CPAU
2015
Residential
Power
Content
Label*
California
State
legislation
(SB
1305)
requires
all
energy
service
providers,
such
as
the
City
of
Palo
Alto
Utilities
(CPAU),
to
periodically
inform
their
customers
of
the
source
of
power
they
are
being
sold.
Such
information
is
provided
in
the
form
of
a
Power
Content
Label.
This
is
very
much
like
a
nutrition
label
on
food
and
is
designed
to
help
consumers
make
informed
decisions
when
selecting
an
energy
service
provider
or
energy
product.
http://www.cityofpaloalto.org/gov/depts/utl/residents/
resources/pcm/power_content_label.asp
(*latest
one
available
on
the
City’s
website.)
3.Fugitive
Emissions
Another
issue
that
comes
up
in
discussions
about
fuel
switching
is
the
worry
about
leaks
and
fugitive
emissions
from
natural
gas
pipelines.
Emissions
in
CPAU
territory
are
insignificant,
and
would
NOT
be
changed
by
electrification,
because
the
gas
transmission
and
distribution
system,
from
which
methane
might
leak,
will
still
be
in
place
and
pressurized.
Given
that
these
pipelines
are
going
to
continue
to
run
through
Colleagues Memo from Commissioners Schwartz and Ballantine 2/21/2017 5
Palo
Alto
for
the
foreseeable
future,
we
submit
it
makes
more
sense
to
work
with
those
innovating
around
methane
leak
detection
and
make
sure
that
our
infrastructure
is
properly
maintained.
Attached
is
an
article
that
highlights
how
Google
Street
View
mapping
cars
are
being
used
to
assess
leaks
in
other
communities.
4.Electrification
of
Transportation
Will
be
More
Effective
We
are
already
seeing
high
adoption
rates
of
EVs
in
town
and
beginning
to
see
the
installation
of
solar
parking
canopies
by
local
corporations.
Given
that
transportation
comprises
38%
of
our
outstanding
GHG
footprint,
it
seems
that
this
application
of
fuel
switching
would
be
a
more
promising
direction
to
demonstrate
thought
leadership,
allow
for
manageable
upgrades
to
our
electrical
infrastructure,
and
have
a
true
impact.
We
note,
however,
that
even
as
the
UAC
might
embrace
this
initiative
with
enthusiasm,
we
need
to
avoid
demonizing
those
residents
who
cannot
afford
to
make
the
immediate
switch
to
hybrids
or
all-‐electric
vehicles.
We
could
as
a
City
choose
to
convert
our
vehicle
fleet
to
electric
fairly
rapidly
and
provide
incentives
and
purchase
participation
to
companies
and
small
businesses
who
are
also
willing
to
make
that
transition.
The
scale
of
solar
parking/charging
canopies
on
city
lots
for
use
during
times
of
peak
production
is
more
practical
than
trying
to
power
the
city’s
operations
for
general
electrical
use.
5.Innovating
through
the
Use
of
Solar
Thermal
Technologies
(Passive
Solar)
In
countries
such
as
Israel,
most
homes
have
rooftop
solar
water
heaters.
While
this
equipment
has
been
slower
to
find
widespread
adoption
in
the
US,
mature
technology
exists
and
could
be
used
to
heat
or
pre-‐heat
water
in
commercial
buildings,
homes,
swimming
pools,
and
for
space
heating.
For
example,
there
is
a
vibrant
solar
thermal
market
in
Montana
where
the
idea
has
gained
traction.
Our
local
creativity
and
willingness
to
invest
in
building
markets
could
have
a
greater
impact
here,
especially
as
part
of
any
microgrid
and
storage
initiatives.
6. Anticipating
Consumer
Reactions
During
early
smart
meter
rollouts,
the
utility
industry
learned
the
hard
way
that
people
do
not
like
to
feel
coerced
by
their
utility,
even
for
a
good
cause.
Telling
people
they
can't
have
gas
ranges
may
provoke
unnecessary
anger
or
resistance.
Imagine
requiring
that
everyone
in
Palo
Alto
MUST
rip
up
their
lawns
or
become
vegans
because
of
the
environmental
impact.
While
people
who
support
these
efforts
are
sincere
in
their
beliefs,
they
do
not
speak
for
all
individuals
in
the
community.
This
is
the
kind
of
issue
that
could
cause
residents
with
other
priorities
to
organize
against
the
sustainability
initiatives
and
aspirational
goals
of
the
City.
It
was
troubling
for
us,
in
the
discussions
around
the
Palo
Alto
Green
Gas
program,
to
hear
members
of
the
community
state
that
people
who
would
not
get
rid
of
their
gas
stoves
or
replace
their
heating
systems
were
selfish
and
unwilling
to
do
their
part
for
saving
the
planet.
This
type
of
misinformed
shaming
is
counter-‐productive
as
we
try
to
build
a
groundswell
of
support
for
true
carbon
reduction.
December 20, 2016
Mary B. Powers
Google, Environmentalists and University Push
Methane-Leak Detection
Specially fitted Google Street View mapping cars assessed N.J. pipes for replacement.
PHOTO COURTESY OF ENVIRONMENTAL DEFENSE FUND
National Grid, which serves New York, Massachusetts and Rhode Island, is set
to be the second U.S. natural-gas utility to use technology advanced by
Google Earth, the Environmental Defense Fund (EDF) and Colorado State
University to boost large-scale methane-leak detection. It is launching a
Google, Environmentalists and University Push Methane-Leak De...http://www.enr.com/articles/41140-google-environmentalists-and-...
1 of 3 1/3/17, 7:56 PM
Recent Articles By Mary B. Powers
Foreman in Fatal NYC Trench Collapse Gets Jail
Sentence
US Approves $2 Billion of Canada Cross-Border
Transmission
$3-billion effort to replace gas pipelines in New York. The technology uses cutting-edge spatial analytics
methods and methane sensors, specially fitted to Google Street View cars, to identify leaks and accurately
measure the amount of methane escaping.
Under a Dec. 16 agreement approved by the New York Public Service Commission, National Grid will work
with EDF and Google to use flow-rate data to prioritize leak repairs in select state service areas, and it has
integrated the approach into its ongoing operations.
Public Service Electric and Gas—New Jersey’s largest gas utility, now in the second year of its pipe
replacement effort— has used the technology to replace 35% fewer miles of pipe and cut methane
emissions by 83%. The utility has replaced about 170 miles in a planned 510-mile, $905-million
replacement program. “We looked for areas to get the most safety benefits using company algorithms and
applied a secondary formula to identify how much methane was leaking,” says Wade Miller, PSE&G
director of gas transmission and distribution engineering. By prioritizing replacement based on emission
rates, the company was able to reduce the amount of methane emissions earlier, he says.
With “millions of readings over hundreds of miles of roadway,” the technology found that 37% of PSE&G
emissions came from 9% of the pipeline miles tested, says Virginia Palacios, a senior research analyst for
EDF’s U.S. climate and energy program. A few large leaks are a major part of the emissions. EDF is most
interested in reducing methane releases. “Methane is 84 times more potent than carbon dioxide as a
climate forcer 20 years after it is released into the atmosphere,” says Palacios. “The instant it is released, it
is about 120 times as powerful as CO .” Carbon dioxide “controls how high global temperatures
eventually get, but methane controls how fast we get there,” she adds.
The technology team began using the detection approach in 2014. PSE&G asked to collaborate. “Reducing
methane is a serious challenge for utilities,” says Ralph A. LaRossa, PSE&G president and CEO. The utility
is replacing old cast-iron and unprotected steel pipe, more prone to leaks, with high-density polyethylene,
using its own workforce and contractors. Online publication NJ Spotlight says PSE&G has more cast-iron
pipes, the type most prone to leaks, in its system than any other U.S. utility—that is, about 3,900 miles of a
18,000-mile system.
Waltham, Mass.-based National Grid also has been an enthusiastic partner, says Mark Brownstein, chief of
EDF’s oil-and-gas program. “By tackling these leaks faster, they will achieve a lot more environmental
benefit for their infrastructure dollars,” he points out.
2 of 3 1/3/17, 7:56 PM
For Operating Day:
Renewable
Resources
Peak
Production
Time
M
a
x
.
Peak Production
(MW)
Daily Production
(MWh)
Solar Thermal 16:07 285 500
Solar 12:44 6,350 47,170
Wind 1:06 2,146 32,769
Small Hydro 18:50 482 9,653
Biogas 13:18 202 4,700
Biomass 16:12 219 4,961
Geothermal 17:48 903 21,501
Total
Renewables 121,254
Total 24-Hour System Demand (MWh):563,228
28,333
Time:18:23
Previous Renewables Watch reports and data are available at http://www.caiso.com/green/renewableswatch.html
Page 1 of 2
Monday, February 20, 2017
Renewables Production
24-Hour Renewables Production
This table gives numeric values related to the production from the various types of renewable resources for the reporting day. All values are hourly average unless otherwise stated. Peak Production is
an average over one minute. The total renewable production in megawatt-hours is compared to the total energy demand for the ISO system for the day. Solar PV and Solar thermal generators that are
GLUHFWO\FRQQHFWHGWRWKHSRZHUJULG³6RODU39´LVGHILQHGDVVRODUJHQHUDWLQJXQLWVWKDWXWLOL]HVRODUSDQHOVFRQWDLQLQJDSKRWRYROWDLFPDWHULDO³6RODU7KHUPDO´LVGHILQHGDVVRODUJHQHUDWLQJXQLWVWKDW
convert sunlight into heat and utilize fossil fuel or storage for production which may occur after sunset.
This table gives numeric values related to the production from the various types of
renewable resources for the reporting day. All values are hourly average unless
otherwise stated. Peak Production is an average over one minute. The total
renewable production in megawatt-hours is compared to the total energy demand
for the ISO system for the day.
System Peak Demand (MW)
*one minute average
Renewables
Nuclear
Thermal
Imports
Hydro
0
5,000
10,000
15,000
20,000
25,000
30,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hourly Average Breakdown of Total Production By Resource Type
Time of Day
This graph depicts the production of various generating resources across the day.
Me
g
a
w
a
t
t
s
Geothermal
BiomassBiogasSmall Hydro
Wind
Solar PV
Solar Thermal
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hourly Average Breakdown of Renewable
Resources
This graph shows the production of various types of renewable
generation across the day.
Time of Day
Me
g
a
w
a
t
t
s
The Renewables Watch provides important information about actual renewable production within the ISO grid as California moves toward a 33 percent
renewable generation portfolio. The information provided is as accurate as can be delivered in a daily format. It is unverif ied raw data and is not
intended to be used as the basis for operational or financial decisions.
For Operating Day:
Comparison to Load
Page 2 of 2
The information contained in this report is preliminary and subject to change without notice. No inference, decision or conclusion should be made based on the information in this report or any series of
these reports. All values are hourly average unless otherwise stated. Questions about this report should be directed to Jessica Garidel at jgaridel@caiso.com.
The first graph provided on this page shows how much energy renewable resources are contributing to the grid, and when thos e resources are producing their daily
maximum and how that production correlates to the maximum energy demand.
16,000
18,000
20,000
22,000
24,000
26,000
28,000
30,000
Lo
a
d
(
M
W
)
Load vs. Renewables
0
2,000
4,000
6,000
8,000
10,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Time of Day
у
14,000
16,000
18,000
20,000
22,000
24,000
26,000
28,000
30,000
Lo
a
d
(
M
W
)
Hourly Average Net Load
Total Load Total Load, less Wind and Solarу
0
2,000
4,000
6,000
8,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Wind and Solar
Total Wind Total Solar
Time of Day
2
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILTIES DEPARTMENT
DATE: MARCH 1, 2017
SUBJECT: Utilities Advisory Commission Recommendation That Council Approve an
Update to the City of Palo Alto’s Ten-Year Gas Energy Efficiency Goals (2018 to
2027)
______________________________________________________________________________
RECOMMENDATION
Staff requests that the Utilities Advisory Commission (UAC) recommend that the City Council
approve the proposed annual and cumulative gas efficiency goals for the period 2018 to 2027
as shown in the table below.,.
Summary Table: Annual Gas Efficiency Goals
% City load therms
2018 1.0% 287,000
2019 1.05% 301,000
2020 1.1% 316,000
2021 1.1% 314,000
2022 1.15% 327,000
2023 1.2% 342,000
2024 1.2% 342,000
2025 1.2% 343,000
2026 1.2% 346,000
2027 1.2% 350,000
Cumulative
ten-year EE Goal
5.1% 1,491,000
EXECUTIVE SUMMARY
Palo Alto adopted its first set of ten-year energy efficiency (EE) goals in 2007 to meet the state
mandate on EE goal-setting and adhere to Council’s policy directive to include cost-effective
energy efficiency as the highest priority energy resource.
Since 2007, the City has updated both the electric and gas EE goals in 2010 and 2012. In
February 2017 staff presented a revised set of aggressive electric EE goals for the period from
2018 to 2027 to the UAC for consideration and recommendation for Council adoption. In this
current report, staff proposes a similarly aggressive set of gas EE goals for 2018 to 2027, with an
2
annual gas efficiency target of 1% in 2018, increasing to 1.2% in 2027, and a cumulative ten-
year gas efficiency savings of 5.1% of the City’s projected gas load. These proposed targets are
approximately double the gas efficiency targets in 2012.
BACKGROUND
Council adopted the City’s first ten-year gas EE goals in April 2007, which were to reduce the
City’s gas usage by 3.5% by 2017. Gas efficiency has been recognized by Council as an important
strategy to meet the City’s greenhouse gas reduction (GHG) targets, initially in the 2007 Climate
Protection Plan (CMR: 435:07), and subsequently in the 2016 Draft Sustainability and Climate
Action Plan (Staff Report #6754). Also, gas efficiency is a key part of the City’s Gas Utility Long-
term Plan (GULP), which sets out the objective of deploying all feasible, cost -effective energy
efficiency measures. In April 2011 Council adopted an updated set of gas EE goals for the period
from 2011 to 2020. The most recent set of gas EE goals were adopted by Council in December
2012, in conjunction with an updated set of electric EE goals . The City traditionally updates gas
EE goals around the same time it updates electric EE goals, every four years.1
Figure 1 provides a summary of the annual gas EE goals and achievements since Fiscal Year (FY)
2008. The figure shows that actual EE achievements have exceeded goals for most years. The
cumulative gas efficiency savings over the period from 2008 to 2016 is around 3.6%.
1 AB 2021 (2006) required publicly owned electric utilities to adopt annual energy efficiency savings goals over a
ten-year period, with the first set of goals due by June 1, 2007 and every three years thereafter. AB 2227 (2012)
changed the triennial electric EE target-setting schedule to a quadrennial schedule, beginning March 15, 2013 and
every fourth year thereafter.
3
Figure 1. Gas EE Goals and Achievements for 2018-2016
DISCUSSION
Overview of Gas EE Goal Setting Process
The first step in establishing gas EE goals is to determine the potential gas savings in the City.
This step was completed using a gas EE potential model developed by Navigant Consulting,
which is similar to the electric EE potential model used by publicly owned electric utilities
statewide in setting their 2018-2027 electric EE goals. The model uses a bottom-up approach to
estimate the total economic potential of market-ready gas efficiency technologies as well as
emerging technologies. The proposed gas EE goals are based on the market potential, which
applies an adoption curve to the economic potential to reflect customers’ awareness and
willingness to adopt energy efficient technologies. The market potential assumes continuation
of existing EE programs, addition of new EE programs, and calibrates the potential savings
based on the historical EE program achievements.
In addition to the existing gas EE programs, which includes traditional rebate programs, direct
installation assistance programs, and residential behavioral program (i.e. Home Energy Report),
the 2016 gas EE potential model added a key new program area to the gas EE portfolio. This
new program area is the Green Building Code. Since 2015, Council has adopted an energy reach
code within the City’s Green Building Ordinance that requires additional energy savings beyond
California’s Title 24 Building Energy Standards for residential and non -residential new
4
construction projects2. As an energy reach code specific only to the City of Palo Alto, energy
savings from the Green Building Ordinance are included in the market potential and therefore
the proposed EE goals. By contrast, energy savings captured under the state’s building energy
standards and the federal appliance standards are excluded from the City’s market potential
and the proposed EE goals.
Appendix A gives a more detailed description of the EE potential model .
Proposed Gas Efficiency Goals
Staff proposes new annual gas EE targets at 1% of forecasted gas load beginning in FY 2018,
increasing to 1.2% by FY 2023, and remaining at 1.2% through FY 2027. These proposed goals
are approximately twice the annual gas EE targets adopted in 2012 (see Figure 2).
Figure 2. Proposed versus Current Annual Gas EE targets
Figure 3 shows the actual historic gas EE savings, and the proposed 2018 to 2027 EE goals on a
therm basis, which starts off in 2018 at the same level as the gas EE savings achieved in 2016 .
Nevertheless, assuming relatively low gas prices over the next decade (which make EE less cost
effective), and assuming no new cost breakthroughs in gas EE technologies, the proposed gas
EE goals are ambitious.
2 For building permit applications submitted between September 2015 and December 2016, Palo Alto’s Energy
Reach Code requires 15% energy efficiency savings beyond the 2013 Title 24 Building E nergy Standard for all
residential and non-residential new construction projects. For building permit applications submitted between
January 2017 and December 2019, Palo Alto’s Energy Reach Code requires 10% energy efficiency savings beyond
the 2016 Title 24 Building Energy Standard for all residential and non -residential new construction projects if the
proposed project does not include a photovoltaic system; a different set of requirements apply to projects that
includes a photovoltaic system and all-electric new construction projects.
5
Figure 3. Historic gas EE savings vs Proposed gas EE goals
As shown in Figure 4, the cumulative ten-year gas savings based on the proposed gas EE goals is
projected to be 5.1% of the gas load in 2027.3 For context, Figure 4 also shows savings due to
the State’s Title 24 Energy Code requirements and Department of Energy appliance standards.
These “Codes and Standards” (C&S) savings are not counted in utility gas EE savings. If gas
savings C&S standards are included, the cumulative ten-year gas savings from all EE is projected
to be 10.8% of the gas load in 2027.
3 Note that the cumulative EE impact over the ten-year period is not equal to the sum of the annual EE goals
because some measures expire before the ten year period is over. As an example, while replacing a gas boiler can
generate savings over 20 years, savings due to behavioral programs have a much shorter life unless regularly
reinforced.
6
Figure 4. Cumulative EE savings based on Proposed Gas EE Goals
Estimated GHG Reductions based on Proposed Gas EE goals
Gas efficiency is a key strategy to meeting the City’s aggressive GHG reduction targets in 2030.
The total GHG emissions reduction based on the cumulative gas savings of the proposed gas EE
targets is estimated at 7,800 metric tons in 2027, a 5% reduction from current levels.
Projected Gas EE Program Costs
The City has historically recovered the cost of gas EE programs through gas rates.4 Gas EE
program expenditures have been steadily growing, from around $500,000 in 2009 to nearly
$700,000 in 2016. Expressed as a percentage of gas utility revenues, gas EE program
expenditures were 1.1% and 2.4% in 2009 and 2016 respectively. Gas revenues have been
steadily declining since 2009 due to depressed natural gas prices and lower gas consumption.
To meet the proposed EE goals, staff estimates that the annual gas EE budget will grow from
about $600,000 in 2018 to just over $900,000 by 2024. Figure 7 shows the actual gas EE
program expenditures for 2008 through 2016 and the estimated annual program budget
needed to achieve the proposed EE targets. Staff will continue to evaluate the cost
effectiveness and customer appeal of various gas efficiency programs and adjust the gas EE
portfolio as necessary to control costs. In addition to the current mechanism of recovering the
cost of gas EE programs through gas rates, funding for future gas EE programs can also come
from the cap-and-trade auction revenue for the allocated allowances to the City’s gas utility.
4 In 1996, Council proactively adopted a funding target of between 0.75% and 1.25% of natural gas revenues for
Demand Side Management programs (CMR:209:96).
7
The annual cap-and-trade revenue is projected to grow from $700,000 in 2017 to $1.2 million in
2020.
Figure 7. Actual and Projected Gas EE Program Costs
Retail Rate Impact of the Proposed Gas EE Goals and EE Budget
EE programs impact retail rates in two ways. First, the gas EE budget increases the revenue
requirements for the gas utility. Second, lower gas load means that fixed costs (capital and
operating costs to run the gas utility) must be distributed over a lower gas sales volume,
thereby increasing the average retail rate.
Based on the proposed 2018 to 2027 gas EE goals and estimated annual program costs, the
retail gas rate in 2027 under the proposed ten-year goals is estimated to be about 5% to 6%
higher compared to a scenario with no EE programs. The net average bill impact of the
proposed goals and budget is estimated to be neutral over the lifetime of the EE savings. This is
because customer use is lower due to EE even though rates are higher, with the two trends
offsetting each other.
RESOURCE IMPACT
Although this report contains preliminary estimates of the costs of achieving the proposed gas
EE goals, the detailed budget plan and staffing needs to meet the annual EE goals will be
developed as part of the annual City budgeting process. The annual budg et will present the
costs for both internally administered, as well as contractor supported, efficiency programs.
POLICY IMPLICATIONS
The proposed gas EE goals conform to the Council-approved Gas Utility Long term Plan (GULP)
Guideline, which calls for the deployment of all feasible, reliable, and cost-effective energy
efficiency measures. The proposed goals will replace the existing gas EE goals adopted by
Council in 2012 and will be integrated into the City's Sustainability Implementation Plans. They
are an integral part of achieving the goals laid out in the City's Sustainability and Climate Action
Plan (S/CAP).
ENVIRONMENTAL REVIEW
Approval of the proposed gas EE goals does not constitute a project under Section 21065 of the
California Environmental Quality Act (CEQA) and the CEQA Guidelines, and therefore, no
environmental review is required.
ATTACHMENT I
A. Overview of Gas EE Potential Model
PREPARED BY: CHRISTINE TAM, Senior Resource Planner
REVIEWED BY: SHIVA SWAMINATHAN, Senior Resource Planner
BRUCE LESCH, Manager, Utilities Program Services
J"-J~AN ABENDSCHEIN, Assistant Director, Resource Management
DEPARTMENT HEAD: _t___: __ -~----· -------
EDWARD SHIKADA
General Manager of Utilities
8
APPENDIX A: Overview of Gas Energy Efficiency Potential Model
The first step in establishing gas EE goals is to model the potential for energy savings within the
City. This step was completed using an EE potential model developed by Navigant Consulting.
The 2016 gas EE potential model is similar to the electric EE potential model used by staff to
update the City’s 2018-2027 electric EE targets. The model estimates the technical, economic
and market potential for energy efficiency measures for residential and non-residential
customers, defined as follows:
• Technical potential is the energy savings that would result from installation of the most
energy efficient measures that are commercially available, regardless of cost-
effectiveness.
• Economic potential includes only savings from the installation of cost-effective EE
measures.
• Maximum Market potential is a subset of the economic potential that reflects
customers’ awareness and willingness to adopt energy efficient equipment over time.
• Market potential is the achievable portion of the maximum market potential calculated
by the model, given: 1) the calibration of the model based on actual EE savings for a
specific utility, and 2) the programs the utility chooses to include.
The model is calibrated based on the achieved EE savings by end use, and uses a 3-year average
from 2013 to 2015 as the base year. The model also takes into account past EE program
achievements as well as Palo Alto-specific input such as projected gas supply costs, natural gas
retail rates, a discount rate, and the building stock. Efficiency measures included in the analysis
cover both current and emerging gas efficiency measures. For each year starting in 2015, the
model steps through the calculation of the technical potential, then filters out the non-cost
effective measures to determine the economic potential, then estimates the maximum market
potential based on customers’ awareness and willingness to adopt and, finally, computes the
market potential by applying a diffusion curve function to the maximum market potential for
the portfolio of EE programs. The calculated market potential forms the basis of the proposed
EE goals for 2018 to 2027. Figure A-1 shows the model’s sequential narrowing from technical
potential to market potential.
Figure A-1. EE Potential Modeling Schematic
Limitations of the EE Potential Model
The 2016 gas EE potential model has some intrinsic limitations. One source of uncertainty is the
values for “willingness and awareness” factors used within the model, which attempt to
approximate customer awareness of individual technology measures and their willingness to
install the measure. The 2016 EE potential model applies generic values adopted from the IOUs’
EE potential model. Given the unique demographics of Palo Alto, the “willingness and
awareness” numbers for Palo Alto may be different from the IOUs’.
Also, the 2016 gas EE potential model assumes avoided gas costs based on the natural price
forward price curve as of September 2016 and projected Cap and Trade compliance cost as of
November 2016. Given the uncertainty of future natural gas prices and California’s Cap and
Trade program, future avoided gas costs could be different from the assumed values, and which
in turn would affect the cost effectiveness of the various gas efficiency measures and therefore
the overall market potential.
More broadly, this model cannot predict future disruptive technologies, or calculate savings
from programs with completely new and different structures. The model incorporated two
new programs in the overall potential analysis: the Green Building Code, which counts energy
savings attributed to Palo Alto’s Green Building Ordinance that are beyond the state’s building
energy standards, and the Building Operation Certification program, which offers training to
facility managers to operate buildings more efficiently. The savings assumptions behind these
two programs, however, are based on the IOUs’ model since Palo Alto-specific numbers are not
available.
Model Results
For Palo Alto, the 2016 EE potential model estimates an annual incremental market potential of
1% of the forecasted load in 2018, increasing to 1.2% by 2023 and beyond. This assumes an
expanded EE portfolio by offering early retirement incentives to customers to replace older,
inefficient equipment with efficient alternatives, counting energy savings from the Green
Building Code, and offering the Building Operator Certification program. If the City relies solely
on a business as usual approach, the model projects gas savings that are 16% lower in 2018,
and 23% lower in 2023.
The 2016 EE Potential model also projects future market potential by end use. Figure A-2
shows that the 65% of the 2018 energy savings are expected from the residential sector, with
residential behavioral savings accounting for half of the total gas savings. Gas savings
attributed to the Green Building Code accounts for 13% of the savings. Retrocommissioning
(RCx) activities such as resetting temperatures and schedules of the building HVAC systems
account for another 8% of the savings.
Figure A-2. Composition of Gas EE Market Potential in 2018
Page 1 of 8
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: March 1, 2017
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt: (1) a Resolution Approving the Fiscal Year 2018
Water Utility Financial Plan; and (2) a Resolution Increasing Water Rates by
Amending Rate Schedules W-1 (General Residential Water Service), W-2
(Water Service from Fire Hydrants), W-4 (Residential Master-Metered and
General Non-Residential Water Service), and W-7 (Non-Residential Irrigation
Water Service) and Removing the Drought Surcharge
RECOMMENDATION
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Water Utility
Financial Plan (Attachment B); and
2. Transfer $1.877 million from the Rate Stabilization Reserve to the Operations Reserve.
3. Adopt a resolution (Attachment C) increasing water rates by amending Rate Schedules
W-1 (General Residential Water Service), W-2 (Water Service from Fire Hydrants), W-4
(Residential Master-Metered and General Non-Residential Water Service), and W-7
(Non-Residential Irrigation Water Service) and removing the drought surcharge;
EXECUTIVE SUMMARY
The FY 2018 Water Utility Financial Plan includes projections of the utility’s costs and revenues
for FY 2018 through FY 2027. Costs are projected to rise by about 3% per year over the next
several years, primarily due to increasing water supply costs. As a result, staff projects the need
for a 4% water rate increase on July 1, 2017 and 6% rate increases in FY 2019 through FY 2023.
Uncertainty about the persistence of lower water usage achieved during the recent drought
makes these rate projections uncertain. The 4% increase for 2017 is needed to bring the unit
cost of water in line with the San Francisco Public Utilities Commission (SFPUC)’s preliminary
estimates of FY 2018 wholesale water costs ($4.37/CCF).
Page 2 of 8
In addition, as discussed in last year’s financial plan, staff still recommends the transfer of
$1.877 million from the Rate Stabilization Reserve to the Operations Reserve in FY 2017. This
action will reduce the Rate Stabilization Reserve to zero.
BACKGROUND
Every year staff presents the UAC with Financial Plans for its Electric, Gas, Water, and
Wastewater Collection Utilities and recommends any rate adjustments required to maintain
their financial health. These Financial Plans include a comprehensive overview of the utility’s
operations, both retrospective and prospective, and are intended to be a reference for UAC and
Council members as they review the budget and staff’s rate recommendations. Each Financial
Plan also contains a set of Reserves Management Practices describing the reserves for each
utility and the management practices for those reserves.
The UAC reviewed preliminary financial forecasts at its February 1, 2017 meeting. Staff has
revised the preliminary projections presented at that meeting.
DISCUSSION
Staff’s annual assessment of the financial position of the City’s water utility is completed to
ensure adequate revenue to fund operations, in compliance with the cost of service
requirements set forth in the California Constitution (Proposition 218). This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. The
current rate proposals are also based on the cost of service methodology described in the 2012
Palo Alto Water Cost of Service & Rate Study, the 2015 Study update, and the 2015 Drought
Rate memorandum completed by Raftelis Financial Consultants.
Staff proposes to adjust water rates to the levels shown in Tables 1 and 2, below, effective July
1, 2017, to recover projected increases in the wholesale cost of water the City purchases from
the San Francisco Public Utilities Commission. These changes are projected to increase the
system average water rate by roughly 4%. These rate changes are included in the proposed
amended rate schedules in Attachment D. Prices are increasing by the same amount across all
rates as the underlying commodity cost is the same for all customers.
Page 3 of 8
Table 1: Water Consumption Charges in $/CCF (Current and Proposed)
Current
(7/1/16)
Proposed
(7/1/17)
Change*
$/CCF %
W-1 (Residential) Volumetric Rates ($/CCF)
Tier 1 Rates 6.30 6.66 0.36 6%
Tier 2 Rates 8.82 9.18 0.36 4%
W-2 (Construction) Volumetric Rates ($/CCF)
Uniform Rate 7.32 7.68 0.36 5%
W-4 (Commercial) Volumetric Rates ($/CCF)
Uniform Rate 7.32 7.68 0.36 5%
W-7 (Irrigation) Volumetric Rates ($/CCF)
Uniform Rate 8.72 9.08 0.36 4%
Table 2: Current and Proposed Monthly Service Charge
Meter
Size
Monthly Service Charge
($/month based on meter size)
Residential (W-1)
Commercial (W-4)
Irrigation (W-7)
Fire Services
(W-3)
5/8” $16.77 N/A
3/4” $22.60 N/A
1” $34.26 N/A
1 ½” $63.40 N/A
2” $98.37 $3.79
3” $209.11 N/A
4” $372.31 $23.42
6” $762.81 $68.03
8” $1,403.94 $144.97
10” $2,219.92 $260.70
12” $2,919.34 $421.11
Bill Impact of Proposed Rate Changes
Table 5 shows the impact of the proposed July 1, 2017 rate changes on residential bills. The
average increase is projected to be about four percent, which is related to commodity cost
increases. The increase represents the difference between what was projected by staff during
the FY 2017 forecasting process ($4.01/ccf) to the current estimate of what the FY 2018 SFPUC
W-25 (Wholesale Use with Long-Term Contract) rate will be. While staff forecast $4.01/ccf
based on preliminary figures provided by the SFPUC, the final rat e adopted for FY2017 was
$4.10/ccf, with reserves used to cover the difference in cost vs. revenues.
Page 4 of 8
In early January, the SFPUC provided a preliminary range for their FY 2018 increase to the W -25
wholesale rate ($4.10 to $4.37/ccf). The SFPUC will not determine the final rate until May or
June. However, in order to have rates in place for July 1, staff must notice customers by the end
of April. Staff has chosen to conservatively forecast at the high end of the SFPUC estimate.
To calculate the rate increase needed as a result of the City’s increased commodity costs, staff ,
in coordination with the City’s cost of service consultant, applied the per unit commodity cost
to the volumetric component of the rates, based on the analysis and methodology from the
cost of service study. The per-unit commodity cost is the same for all classes of customers and
across all usage levels. As this proposed increase only reflects changes to commodity cost s,
volumetric rates will increase by the same amount per ccf, regardless of customer type or usage
tier.
Table 5 shows the impact of the proposed changes. As the State has removed mandatory usage
restrictions for California agencies, the SFPUC has adequate water supplies, and as the Water
Fund’s reserves are within guideline levels, staff is recommending that Council deactivate the
drought surcharge at this time. The bill comparison below assumes the deactivation of the
drought surcharge.
Table 5: Impact of Proposed Rate Changes on Residential Bills (no drought surcharge)
Usage
(CCF/month)
Bill under
Existing Rates
(7/1/16)
Bill under
Proposed Rates
(7/1/17)
Change
$/mo. %
4 $41.97 $43.41 $1.44 3.4%
(Winter median) 7 63.39 65.91 2.52 4.0%
(Annual median) 9 81.03 84.27 3.24 4.0%
(Summer median) 14 125.13 130.17 5.04 4.0%
25 222.15 231.15 9.00 4.1%
Table 6 shows the impact of the proposed July 1, 201 7 rate changes on various representative
commercial customer bills. As with residential rates, this comparison assumes the
discontinuation of the drought surcharge.
Page 5 of 8
Table 6: Impact of Proposed Rate Changes on Commercial Bills
Usage
(CCF/month)
Bill under
Current Rates
(7/1/16)
Bill under
Proposed Rates
(7/1/17)
Change
$/mo. %
Commercial (W-4) (5/8” meters)
(Annual median) 12 $104.61 $108.93 $4.32 4%
(Annual average) 64 485.25 508.29 23.04 5%
Irrigation (W-7) (1 ½” meters)
(Winter median) 9 142 145 3 2%
(Summer median) 37 386 399 13 3%
(Winter average) 56 552 572 20 4%
(Summer average) 199 1,799 1,870 72 4%
FY 2018 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 7 shows the projected rate adjustments over the next five years and their impact on the
annual median residential water bill.
Table 7: Projected Rate Adjustments, FY 2018 to FY 2022
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Water Utility 4% 6% 6% 6% 6%
Estimated Bill Impact ($/mo)* $3.24 $5.06 $5.36 $5.68 $6.02
* estimated impact on median residential water bill, which is currently $81.03.
The main driver for the increase in the water utility’s costs (and therefore rates) over the next
several years is the cost of water. Wholesale water costs are adopted by the SFPUC, and
generally change on an annual basis. Last year the SFPUC’s wholesale rate rose by 9%, and
current projections range from 0% to 7%. Over the forecast period, though, it is projected to
rise by two to three percent per year. If lower usage persists from the drought, the magnitude
of future increases will be difficult to predict. What is certain is that the SFPUC’s costs to
operate the Regional Water System are primarily fixed costs, so the water rate charged to
wholesale customers like the City of Palo Alto is highly dependent on usage by users of the
Regional Water System. The City’s FY 2018 Water Utility Financial Plan assumes that, while the
drought has ended and usage has started to increase, based on CPAU’s experience,
consumption is not anticipated to return to pre-drought levels.
The Water Utility may also see a $1 million increase in operating costs for a capital lease for
emergency generators for wells and pump stations. Aside from that, operating and CIP costs
are projected to rise roughly 2% to 4% annually over that time.
There remains some uncertainty in the forecasts of capital costs for the water utility in coming
years. Water main replacement costs have risen substantially in recent years, and it is possible
higher CIP expenditures will be required in the future. Higher bid costs and delays in project
schedules have resulted in a projected deferment of main replacement projects by two years,
Page 6 of 8
starting in FY 2017, meaning that capital investment costs will be lower for those two years.
This delay in main replacement, along with the proposed rate trajectory, should allow for the
Operations Reserve to remain well within the reserve guidelines throughout the forecast
period.
Water Bill Comparison with Surrounding Cities
Table 8 compares water bills for residential customers to those in surrounding communities as
of February 1, 2017 (under current the City’s current water rates). Palo Alto customers have the
highest monthly bills of the group, although bills for smaller water users are lower than in some
surrounding communities. It is unclear at this time what water rate changes may be
implemented in these communities for FY 2018.
Table 8: Residential Monthly Water Bill Comparison
Usage
(CCF/month)
Residential monthly bill comparison ($/month)*
As of February 2016
Palo
Alto
Menlo
Park
Mountain
View Hayward
Redwood
City
Santa
Clara
4 43.69 44.46 46.47 34.63 33.37 19.80
(Winter median) 7 67.18 63.03 65.43 53.68 45.20 34.65
(Annual median) 9 87.24 75.43 78.07 66.38 53.09 44.55
(Summer median) 14 137.39 107.95 119.47 98.13 73.81 69.30
25 247.72 180.33 229.94 206.08 119.91 123.75
Based on the FY 2013 BAWSCA survey, the fraction of SFPUC as the source of potable
water supply was 100% for Palo Alto, 95% for Menlo Park, 100% for Redwood City, 87%
for Mountain View, 10% for Santa Clara and 100% for Hayward.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 1, 2017, staff re-
evaluated reserve and cost positions and determined a commodity-only increase could be
performed without negatively impacting the financial health of the utility. The final SFPUC
wholesale rate is not determined until May or June, well after Palo Alto needs to propose and
notice its rate changes to the public under Proposition 218. In the future, staff may
recommend that the SFPUC Schedule W-25 (Wholesale Cost with Long-Term Contract)
commodity cost to Palo Alto be automatically passed -through to ratepayers, similar to how gas
commodity costs are passed through on a monthly basis. Allowing commodity costs to
automatically adjust via a pass-through charge would better match revenues to the City’s
wholesale costs and avoid having to reconcile SFPUC’s commodity cost changes many months
after they are imposed.
California law implementing Prop. 218 (Government Code 53766) allows for automatic
adjustments that pass-through increases or decreases in the City’s wholesale water costs, so
long as customers are informed of the rate adjustment at least 30 days in advance of each rate
adjustment. Customers would be informed of the City’s initial intent to automatically adjust
Page 7 of 8
these costs via the standard Proposition 218 notice and hearing process. If no majority protest
occurred and Council adopted the proposed rates, future changes to the wholesale rate could
be passed through to customers upon 30 days’ notice to customers, and such notice is typically
included on the utility bill. The automatic pass-through adjustment would need to be
reapproved, via a new Prop. 218 notice and public hearing process, every five years.
Changes from Last Year’s Financial Forecast
Table 9 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2018 rate projections are somewhat lower than projected last year.
The cumulative projected increase in rates through FY 2026 is similar to last year’s projections.
In this year’s projection, however, higher reserves allo w rates to be increased gradually over
the entire forecast period, rather than increased quickly in FY 2018, FY 2019, and FY 2020, as in
last year’s projection. The overall rate increase over the forecast period is higher than projected
in the FY 2016 Financial Plan, however, and this is due to the high likelihood of some of the
water conservation habits established during the drought persisting long term, leading to lower
consumption.
Table 9: Projected Water Rate Trajectory for FY 2018 to FY 2027
Projection FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Current
(FY 2018 Financial Plan) 4% 6% 6% 6% 6% 6% 2% 2% 2% 1%
Last year
(FY 2017 Financial Plan) 9% 9% 6% 2% 2% 2% 3% 5% 3% N/A
Two years ago
(FY 2016 Financial Plan) 8% 8% 3% 1% 2% 3% N/A N/A N/A N/A
NEXT STEPS
The Finance Committee is scheduled to review the FY 2018 Water Financial Plan on April 4,
2017. Assuming the Finance Committee supports staff’s recommendation , notification of the
rate increases will be sent to customers as required by Article XIIID of the State Constitution
(added by Proposition 218). The Financial Plans and rate schedules will then go to the City
Council with the FY 2018 budget for adoption, at which time the public hearing required by
Article XIIID of the State Constitution will be held . Assuming the rate changes are approved,
they will become effective July 1, 2017.
RESOURCE IMPACT
Normal year sales revenues for the Water Utility are projected to increase by roughly 4% ($1
million) as a result of these rate increases. See the attached FY 2018 Water Financial Plan for a
more comprehensive overview of projected cost and revenue changes for the next ten years.
POLICY IMPLICATIONS
The proposed water rate adjustments are consistent with Council-adopted Reserve
Management Practices that are part of the Financial Plans, and were developed using a cost of
service study and methodology consistent with the cost of service requirements of Proposition
218.
ENVIRONMENTAL REVIEW
The UAC's review and recommendation to Council on the FY 2018 Water Financial Plans and
rate adjustments does not meet the definition of a project requiring California
Environmental Quality Act (CEQA) review, under Public Resources Code Section 21065 and
is exempt from CEQA review under Public Resources Code Section 21080(b)(8) as an adoption
of rates to meet operating expenses, purchase supplies, meet reserve needs and obtain
capital improvement funds).
ATTACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2018 Water Utility
Financial Plan
B. Proposed FY 2018 Water Utility Financial Plan
C. Resolution of the Council of the City of Palo Alto Adopting a Water Rate Increase and
Amending Rate Schedules W-1, W-2, W-4, and W-7
D. Amended Rate Schedules W-1, W-2, W-4, and W-7
PREPARED BY:
REVIEWED BY:
APPROVED BY:
ERIC KENISTON, Acting Rates Manager C . e ~-9< ~.
JONATHAN ABENDSCHEIN, Assistant Director, Resource Mgmt '
L:?~
ED SHIKADA
General Manager of Utilities
Page 8of8
Attachment A
* NOT YET APPROVED *
170216 jb 6053918
Resolution No. ______
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 Water Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of its
utilities with the goal of ensuring adequate revenue to fund operations. This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. It does
this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other aspects
of its operations, and regularly assesses the adequacy of these reserves and the management
practices governing their operation. The status of utility reserves and their management
practices are included in Reserves Management Practices attached to and made part of the
Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby adopts the FY 2018 Water Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of $1.877 million in FY 2018 from
the Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2018 Water
Utility Financial Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
definition of a project requiring California Environmental Quality Act (CEQA) review, under
/ /
/ /
/ /
/ /
/ /
Attachment A
* NOT YET APPROVED *
170216 jb 6053918
California Public Resources Code 21065 and CEQA Guidelines Section 15378(b)(5), because it is
an administrative governmental activity which will not cause a direct or indirect physical change
in the environment.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2018 WATER
UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
WATER UTILITY FINANCIAL PLAN
F e b r u a r y 2 0 1 6 2 | P a g e
FY 2018 WATER UTILITY
FINANCIAL PLAN
FY 201 8 TO FY 20 2 7
TABLE OF C ONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 4
Section 2A: Overview of Financial Position .................................................................................. 4
Section 2B: Summary of Proposed Actions .................................................................................. 5
Section 3: Detail of FY 2018 Rate and Reserves Proposals ....................................................... 5
Section 3A: Rate Design ............................................................................................................... 5
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3C: Bill Impact of Proposed Rate Changes ...................................................................... 8
Section 3D: Proposed Reserve Transfers ................................................................................... 10
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Water Utility History ............................................................................................... 10
Section 4B: Customer Base ........................................................................................................ 11
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 11
Section 4E: Reserves Structure ................................................................................................... 12
Section 4F: Competitiveness ...................................................................................................... 13
Section 5: Utility Financial Projections ................................................................................. 13
Section 5A: Load Forecast .......................................................................................................... 13
Section 5B: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 15
Section 5C: FY 2016 Results ....................................................................................................... 16
Section 5D: FY 2017 Projections ................................................................................................ 16
Section 5E: FY 2018 – FY 2027 Projections ................................................................................ 16
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 18
Section 5G: Alternate ScenarIOS ................................................................................................ 19
WATER UTILITY FINANCIAL PLAN
F e b r u a r y 2 0 1 6 3 | P a g e
Section 5H: Long-Term Outlook ................................................................................................. 19
Section 6: Details and Assumptions ..................................................................................... 20
Section 6A: Water Purchase Costs ............................................................................................. 20
Section 6B: Operations .............................................................................................................. 21
Section 6C: Capital Improvement Program (CIP) ....................................................................... 22
Section 6D: Debt Service ............................................................................................................ 24
Section 6E: Other Revenues ....................................................................................................... 26
Section 6F: Sales Revenues ........................................................................................................ 26
Section 7: Communications Plan .......................................................................................... 26
Appendices ......................................................................................................................... 28
Appendix A: Water Utility Financial Forecast Detail ................................................................. 29
Appendix B: Water Utility Capital Improvement Program (CIP) Detail ..................................... 31
Appendix C: Water Utility Reserves Management Practices ..................................................... 33
Appendix D: Description of Water Utility Operational Activities ............................................... 36
Appendix E: Sample of Water Utility Outreach Communications ............................................. 37
WATER UTILITY FINANCIAL PLAN
F e b r u a r y 2 0 1 6 4 | P a g e
SECTION 1 : DEFINITIONS AND ABBR EVIATIONS
BAWSCA Bay Area Water Supply and Conservation Agency
CCF The standard unit of measurement for water delivered to water customers, equal to
one hundred cubic feet, or roughly 748 gallons.
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
O&M Operations and Maintenance
RFC Raftelis Financial Consultants, Inc.
SFPUC San Francisco Public Utilities Commission
SFWD San Francisco Water Department
UAC Utilities Advisory Commission
WSIP The SFPUC’s Water System Improvement Program to seismically strengthen the
transmission lines of the Hetch Hetchy regional water system.
SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Water Utility for the next ten years. This
Financial Plan provides revenues to cover the costs of operating the utility safely over that time
while adequately investing for the future. It also addresses the financial risks facing the utility
over the short term and long term, and includes measures to mitigate and manage those risks.
SECTION 2 A : OVERVIEW OF FINANC IAL POSITION
Overall costs in the Water Utility are expected to rise by about 3% per year from fiscal year (FY)
2017 to 2027. Excluding FY 2018 (which, unlike a normal year, does not include a water main
replacement project), most costs are projected to rise by two to three percent annually through
the projection period. The costs for the Water Utility are shown in Table 1 below.
Table 1: Expenses for FY 2016 to FY 2027 (Thousand $’s)
Expenses
($000)
FY
2016
(act.)
FY
2017
(est.)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Water
Purchases
17,626
19,246
21,347
22,756
22,850
22,933
23,016
23,120
23,367
23,625
23,890
24,495
Operations
15,895
17,601
18,064
18,535
19,023
19,475
19,905
20,349
20,798
21,260
21,734
22,220
Capital
Projects
9,082
4,110
4,082
10,314
10,067
10,364
10,671
10,986
11,310
11,645
11,989
12,343
TOTAL
42,603
40,610
43,494
51,605
51,940
52,773
53,591
54,455
55,475
56,529
57,613
59,059
This proposed financial plan projects that the rate increases shown in Table 2 are needed to
ensure that revenues cover rising costs and reserves remain healthy. The table also shows rate
projections from last year’s Financial Plan. Last year’s plan projected earlier, more aggressive
rate increases. However, the delay of the planned FY 2017 and FY 2018 water main
replacement projects resulted in an increase in reserves, which enabled the more gradual
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increases projected in the current plan. This also means that the Rate Stabilization Reserve will
be drawn down over a longer time frame than projected in last year’s financial plan.
Table 2: Projected Water Rate Trajectory for FY 2018 to FY 2027
Projection FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Current 4% 6% 6% 6% 6% 6% 2% 2% 2% 1%
Last year 9% 9% 6% 2% 2% 2% 3% 5% 3% N/A
2 years 8% 8% 3% 1% 2% 3% N/A N/A N/A N/A
The Water Utility has a Rate Stabilization Reserve that can be used to smooth rate increases
over several years. This Financial Plan projects that these reserves will be exhausted by the end
of FY 2017. The Water Utility also has a Capital Improvement Program (CIP) Reserve that can be
used to offset one-time unanticipated capital costs. This Financial Plan assumes that the CIP
Reserve will be used for unanticipated capital expenses or returned to the Operations Reserve
by the end of FY 2020. Table 3 shows the projected reserve transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2017 to FY 2027 ($000)
Reserve FY 2017 FY 2018 FY 2019 to FY 2027
Capital Improvement - (2,726)
Rate Stabilization (1,877) - -
Operations 1,867 - 2,726
SECTION 2 B : SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Water Utility in FY 201 8:
1. Increase rates by 4%, reflecting proposed increases to SFPUC wholesale rates. This is
described in more detail in Section 3B: Current and Proposed Rates.
2. Transfer $1.877 million from the Rate Stabilization Reserve to the Operations Reserve.
See Section 3D: Proposed Reserve Transfers for more details.
SECTION 3 : DETAIL OF FY 201 8 RATE AND RESERVES PR OPOSALS
SECTION 3 A : RATE DESIGN
The Water Utility’s rates are evaluated and implemented in compliance with the cost of service
requirements and procedural rules set forth in the California Constitution under Article 13 (per
Proposition 218). Current rates were structured based on staff’s assessment of the financial
position of the Water Utility, and updated using the methodology from the March 2012 Palo
Alto Water Cost of Service & Rate Study by Raftelis Financial Consultants, Inc. (Staff Report
2676), as well as Raftelis’ 2015 Memorandum: Proposed Water Rates updating the 2012 Study
and analyzing drought rates (Staff Report 5951). Staff plans to review and update this cost of
service study in 2 to 3 years, unless any major changes occur to the utility’s operations or
customer base that would necessitate an earlier study. Before conducting any new cost of
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service study, staff will review current rates and the scope of the study with the Utilities
Advisory Commission (UAC) and Council to determine the City’s policy priorities.
In 2015 Council adopted a drought surcharge to assist the water utility in recovering its costs
due to decreased revenue due to lower water consumption resulting from conservation
measures. Recent rains have dramatically improved the water supply outlook for the Hetch
Hetchy system, eliminating local drought impacts. Mandatory usage restrictions have been
lifted by the State of California, and while voluntary measures may still remain in place ,
customers’ usage of water has started to increase. The increasing usage, the end of the
drought, and the healthy level of Operations reserves indicate to staff that the drought
surcharge can be removed at this time.
SECTION 3 B : CURRENT AND PROPOSED RATES
The current rates and surcharges were effective on July 1, 2016. Rates were adjusted in
accordance with the results of an updated cost of service study performed by Raftelis Financial
Consultants, Inc. (RFC) in 2015. The 2015 study both developed the drought surcharges and
validated the City’s water rate methodology and structure in light of court decisions
interpreting provisions of the State Constitution applicable to water rates . RFC recommended
only minor adjustments to ensure that peaking costs were equitably allocated to each customer
class and residential rate tier.
CPAU has five rate schedules: one for separately metered residential customers (W-1), one for
commercial and master-metered multi-family residential customers (W-4), and specific
schedules for irrigation-only services (W-7), services to fire sprinkler systems in buildings and
private hydrants (W-3), and for service to fire hydrant rental meters used for construction (W-
2). All customers pay a monthly service charge based on the size of their inlet meter. This
charge represents meter reading, billing, and other customer service costs, but also the cost of
maintaining the capability to deliver a peak flow for that customer corresponding to their meter
size. All customers are also charged for each CCF (one hundred cubic feet) of water used.
Separately metered residential customers are charged on a tiered basis, with the first 0.2 CCF
per day (6 CCF for a 30 day billing period) charged at the base price per CCF, and all additional
units charged a higher price per CCF. Commercial customers pay a uniform price for each CCF
used, and a higher price for separately metered irrigation service.
Table 4 shows the current and proposed consumption charges.
The average increase is projected to be about four percent, which is related to commodity cost
increases. The increase represents the difference between what was projected by staff during
the FY 2017 forecasting process ($4.01/ccf) to the current estimate of what the FY 2018 SFPUC
W-25 (Wholesale Use with Long-Term Contract) rate will be. While staff forecast $4.01/ccf
based on preliminary figures provided by the SFPUC, the final rate adopted for FY2017 was
$4.10/ccf, with reserves used to cover the difference in cost vs. revenues.
In early January, the SFPUC provided a preliminary range for their FY 2018 increase to the W -25
wholesale rate ($4.10 to $4.37/ccf). The SFPUC will not determine the final rate until May or
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June. However, in order to have rates in place for July 1, staff must notice customers by the end
of April. Staff has chosen to conservatively forecast at the high end of the SFPUC estimate.
The SFPUC does not typically provide it’s final, annual change to its wholesale rate until the
City’s retail rate is already proposed to Council for adoption. To meet Palo Alto’s timeline to
increase rates by July 1, staff has historically set retail rates based on early estimates from the
SFPUC, which are subject to change.
Changes in the SFPUC’s wholesale rate require staff to reconcile costs and revenues well after
the fact. To calculate the rate increase needed as a result of the City’s increased commodity
costs, staff, in coordination with the City’s cost of service consultant, applied the per-unit
commodity cost to the volumetric component of the rates, based on the analysis and
methodology from the cost of service study. The per-unit commodity cost is the same for all
classes of customers and across all usage levels. As this proposed increase only reflects changes
to commodity costs, volumetric rates will increase by the same amount per ccf, regardless of
customer type or usage tier.
California law implementing Prop. 218 (Government Code 53766) allows for autom atic
adjustments that pass-through increases or decreases in the City’s wholesale water costs, so
long as customers are informed of the rate adjustment at least 30 days in advance of each rate
adjustment. Customers would be informed of the City’s initial intent to automatically adjust
these costs via the standard Proposition 218 notice and hearing process. If no majority protest
occurred and Council adopted the proposed rates, future changes to the wholesale rate could
be passed through to customers upon 30 days’ notice, which is typically included on the utility
bill. The automatic pass-through adjustment would need to be reapproved, via a new Prop.
218 notice and public hearing process, every five years.
Table 4: Current and Proposed Water Consumption Charges
Current
(7/1/16)
Proposed
(7/1/17)
Change*
$/CCF %
W-1 (Residential) Volumetric Rates ($/CCF)
Tier 1 Rates 6.30 6.66 0.36 6%
Tier 2 Rates 8.82 9.18 0.36 4%
W-2 (Construction) Volumetric Rates ($/CCF)
Uniform Rate 7.32 7.68 0.36 5%
W-4 (Commercial) Volumetric Rates ($/CCF)
Uniform Rate 7.32 7.68 0.36 5%
W-7 (Irrigation) Volumetric Rates ($/CCF)
Uniform Rate 8.72 9.08 0.36 4%
Table 5 shows the current monthly service charges for all rate schedules. Staff is not
recommending a change to the monthly service charge schedule at this time , as they are not
affected by the SFPUC’s wholesale water rate changes.
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Table 5: Current Monthly Service Charges
Meter
Size
Monthly Service Charge
($/month based on meter size)
Residential (W-1)
Commercial (W-4)
Irrigation (W-7)
Fire Services
(W-3)
5/8” $16.77 N/A
3/4” $22.60 N/A
1” $34.26 N/A
1 ½” $63.40 N/A
2” $98.37 $3.79
3” $209.11 N/A
4” $372.31 $23.42
6” $762.81 $68.03
8” $1,403.94 $144.97
10” $2,219.92 $260.70
12” $2,919.34 $421.11
SECTION 3 C : BILL IMPACT OF PRO POSED RATE CHANGES
Table 6 shows the impact of the estimated July 1, 2017 rate changes on the median residential
bill. The average increase is projected to be about four percent, but some customers may see
slightly higher or lower increases due to slight changes in the composition of the utility’s costs.
To allow for effective comparison, the sample bills shown in Table 6 do not include the
temporary drought surcharge, since this would make the bills based on the July 1, 2016 rates
appear artificially high and obscure the effects of the increases to long-term rates effective July
1, 2017. In reality, though, many customers will see a decrease in their bills due to the removal
of the drought surcharge. This is shown in Table 7.
Table 6: Impact of Proposed Water Rate Changes on Residential Bills (no surcharge)
Usage
(CCF/month)
Bill under
Current Rates
(7/1/16)
Bill under
Proposed
Rates (7/1/17)
Change
$/mo. %
4 $41.97 $43.41 $1.44 3.4%
(Winter median) 7 63.39 65.91 2.52 4.0%
(Annual median) 9 81.03 84.27 3.24 4.0%
(Summer median) 14 125.13 130.17 5.04 4.0%
25 222.15 231.15 9.00 4.1%
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Table 7: Impact of Proposed Water Rate Changes on Residential Bills (with 20% drought
surcharge)
Usage
(CCF/month)
Bill under
Current Rates
(7/1/16)
Bill under
Proposed
Rates (7/1/17)
Change
$/mo. %
4 $43.69 $43.41 ($0.28) -0.6%
(Winter median) 7 67.18 65.91 (1.27) -1.9%
(Annual median) 9 87.24 84.27 (2.97) -3.4%
(Summer median) 14 137.39 130.17 (7.22) -5.3%
25 247.72 231.15 (16.57) -6.7%
Error! Reference source not found. shows the impact of the proposed July 1, 2017 rate changes
on various representative commercial customer bills. As for the residential comparison in Table
6 above, this comparison does not include the drought surcharge. A comparison with the
existing 20% surcharge is shown in Table 9.
Table 8: Impact of Proposed Water Rate Changes on Commercial Bills (no surcharge)
Usage
(CCF/month)
Bill under
Current Rates
(7/1/16)
Bill under
Proposed Rates
(7/1/17)
Change
$/mo. %
Commercial (W-4) (5/8” meters)
(Annual median) 12 $104.61 $108.93 $4.32 4%
(Annual average) 64 485.25 508.29 23.04 5%
Irrigation (W-7) (1 ½” meters)
(Winter median) 9 142 145 3 2%
(Summer median) 37 386 399 13 3%
(Winter average) 56 552 572 20 4%
(Summer average) 199 1,799 1,870 72 4%
Table 9: Impact of Proposed Water Rate Changes on Commercial Bills (with 20% drought
surcharge)
Usage
(CCF/month)
Bill under
Current Rates
(7/1/16)
Bill under
Proposed Rates
(7/1/17)
Change
$/mo. %
Commercial (W-4) (5/8” meters)
(Annual median) 12 $110.97 $108.93 ($2.04) -2%
(Annual average) 64 519.17 508.29 (10.88) -2%
Irrigation (W-7) (1 ½” meters)
(Winter median) 9 153 145 (8) -5%
(Summer median) 37 432 399 (33) -8%
(Winter average) 56 622 572 (50) -8%
(Summer average) 199 2,047 1,870 (177) -9%
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SECTION 3 D : PROPOSED RESERVE TRA NSFERS
In the FY 2017 Financial Plan, staff proposed transferring $1.87 million from the Rate
Stabilization Reserve to the Operations Reserve in FY 2017. This transfer will exhaust the Rate
Stabilization Reserve, as planned for and discussed in Section 4E: Reserves Structure, and is
included in the financial projections in this Financial Plan. It will enable CPAU to maintain
adequate Operations Reserve levels while moderating the pace of increase in water rates.
However, a proposed $4 million transfer from the CIP Reserve to the Operations Reserve was
also discussed in the FY 2016 Financial Plan. As the Operations reserve is projected to end the
year at its maximum allowed level, this transfer is no longer required at this time. These funds
will be retained for unexpected CIP expenses. The impact of these transfers on reserves levels
can be seen in Section 4E: Reserves Structure and Appendix A: Water Utility Financial Forecast
Detail.
SECTION 4 : UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in Section 5:
Utility Financial Projections and Section 6: Details and Assumptions.
SECTION 4 A : WATER UTILITY HIST ORY
The Water Utility was established on May 9, 1896, two years after the city was incorporated.
Voters of the 750 person community approved a $40,000 bond to buy local, private water
companies who operated one or more shallow wells to serve the nearby residents. The city
grew and the well system expanded until nine wells were in operation in 1932. Palo Alto began
receiving water from the San Francisco Water Department (SFWD) in 1937 to supplement these
sources.
A 1950 engineering report noted, “the capricious alternation of well waters and the San
Francisco Water Department water…has made satisfactory service to the average customer
practically impossible”. By 1950, only eight wells were still in operation. Despite this,
groundwater production increased in the 1950’s leading to lower groundwater tables and water
quality concerns. In 1962, a survey of water softening costs to CPAU customers determ ined that
CPAU should purchase 100% of its water supply needs from the SFWD. A 20 -year contract was
signed with San Francisco, and CPAU’s wells were placed in standby condition. The SFWD later
became known as the SFPUC. Since 1962 (except for some very short periods) CPAU’s entire
supply of potable water has come from the SFPUC.
As the city grew, so did the number of mains in the water system. The system of mains
expanded along with the town, while existing sections of the system continued to age. In the
mid-1980s, the number of breaks in cast iron mains installed during the 1940s and earlier
started to accelerate. In FY 1994, to combat deterioration of older sections of the system, an
analysis of cost effective system improvements was performed and the rate of main
replacement was increased from one mile per year to three. A plan to replace 75 miles of
deficient mains within 25 years was begun.
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Figure 1: Cost Structure (FY 2016)
42%
37%
21%
Water Purchases
Operations
Capital
In 1999, a study of system reliability concluded that major upgrades were needed to the
distribution system to provide adequate water supply during a natural disaster. This ultimately
resulted in the $40 million Emergency Water Supply and Storage Project, completed in 2013,
which involved a new underground reservoir in El Camino Park, the siting and construction of
several emergency supply wells, and the upgrade of several existing wells and the Mayfield
pump station. Upon completion, the City began to focus its reliability efforts on its system of
water storage reservoirs and transmission lines in the Foothills.
At the same time that CPAU was evaluating the reliability of its own system, the SFPUC, in
consultation with BAWSCA members, was evaluating the reliability of the Hetch Hetchy water
system, which crosses two major fault lines between the Sierras and the Ba y Area. That
evaluation concluded that major upgrades to the system were required. This planning process
culminated in the SFPUC’s $4.8 billion Water System Improvement Project (WSIP), which is
ongoing. The SFPUC continues to evaluate its aging system for other needed infrastructure
improvements.
SECTION 4 B : CUSTOMER BASE
CPAU’s Water Utility provides water service to the residents and businesses of Palo Alto, plus a
handful of residential customers not in Palo Alto (Los Altos Hills, primarily). Nearly 20,300
customers are connected to the water system, approximately 16,500 (81%) of which are
separately metered residential customers and 3,800 (19%) of which are commercial, master-
metered residential, irrigation and fire service customers.
Judging from seasonal consumption patterns, between 35% and 50% of Palo Alto’s water is
used for irrigation, and that consumption is heav ily weather dependent. It also varies
significantly by season. As a result of these two factors , there is significant variability in the
amount of water that is demanded from the system month to month and year to year.
SECTION 4 C : DISTRIBUTION SYSTEM
To deliver water to its customers, the utility owns roughly 233 miles of mains (which transport
the water from the SFPUC meters at the city’s borders to the customer’s service laterals and
meters), eight wells (to be used in emergencies), five water storage reservoirs (also for
emergency purposes) and several tanks used to moderate pressure and deal with peaks in flow
and demand (due to fire suppression, heavy usage times, etc.). These represent the vast
majority of the infrastructure used to distribute water in Palo Alto.
SECTION 4 D : COST STRUCTURE AND R EVENUE SOURCES
As shown in Figure 1, water purchase
costs accounted for roughly 42% of the
Water Utility’s costs in FY 2016.
Operational costs represented roughly
37%, and capital investment was
responsible for the remaining 21%. These
percentage distributions are projected to
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Figure 2: Revenue Structure (FY 2016)
99%
1%
Sales of Water
Other Revenue
remain roughly the same over the forecast period.
The Water Utility receives nearly all of its revenue from sales of water and the remainder from
capacity and connection fees, interest on reserves, and other sources. As rates increase over
the next several years, the percentage of revenue from sales of water is expected to increase as
well. Appendix A: Water Utility Financial
Forecast Detail shows more detail on the
utility’s cost and revenue structures.
Roughly 15% of the utility’s revenues
come from fixed service charges, though
most of its costs are fixed. This is typical
for California water utilities, and
conforms to the Best Management
Practices (BMPs) of the California Urban
Water Conservation Council (CUWCC), a
statewide conservation council of
environmental groups, state agencies,
and water utilities to which the City is a
signatory. One of CUWCC’s BMPs is that a utility’s revenue from fixed service charges
constitutes at most 30% of the utility’s total revenue from all charges1.
SEC TION 4 E : RESERVES STRUCTURE
CPAU maintains six reserves for its Water Utility to manage various types of contingencies.
These are summarized below, but see Appendix C: Water Utility Reserves Management
Practices for more detailed definitions and guidelines for reserve management:
Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
Reserve for Reappropriations: A reserve for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve.
Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects and is anticipated to be empty
unless a major one-time CIP expenditure is expected in future years. This CIP can also
act as a contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, Gas, and Wastewater Collection) as well.
Rate Stabilization Reserve: This reserve is intended to be empty unless one or more
large rate increases are anticipated in the forecast period. In that case, funds can be
accumulated to spread the impact of those future rate increases across multiple years.
1 See http://www.cuwcc.org/Resources/Memorandum-of-Understanding/Exhibit-1-BMP-Definitions-Schedules-
and-Requirements/BMP-1-Utility-Operations-Programs
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This type of reserve is used in other utility funds (Electric, Gas, and Wastewater
Collection) as well.
Operations Reserve: This is the primary contingency reserve for the Water Utility, and is
used to manage yearly variances from budget for operational water supply costs. This
type of reserve is used in other utility funds (Electric, Gas, and Wastewater Collection)
as well.
Unassigned Reserve: This reserve is for any funds not assigned to the other reserves
and is normally empty.
SECTION 4 F : COMPET ITIVENESS
Table 10 shows the current water bills for residential customers compared to what they would
be under surrounding communities’ rate schedules. CPAU has the highest monthly bills of the
group, although bills for smaller water users are less than in some surrounding communities .
Note that Palo Alto’s rates include the Level 2 (20%) drought surcharge currently in effect.2
Table 10: Residential Monthly Water Bill Comparison
Usage
(CCF/month)
Residential monthly bill comparison ($/month)*
As of February 2017
Palo
Alto
Menlo
Park
Mountain
View Hayward
Redwood
City
Santa
Clara
4 43.69 44.46 46.47 34.63 33.37 19.80
(Winter median) 7 67.18 63.03 65.43 53.68 45.20 34.65
(Annual median) 9 87.24 75.43 78.07 66.38 53.09 44.55
(Summer median) 14 137.39 107.95 119.47 98.13 73.81 69.30
25 247.72 180.33 229.94 206.08 119.91 123.75
* All comparisons use the 5/8” meter size.
SECTION 5 : UTILITY FINANCIAL PROJECTIONS
SECTION 5 A : LOAD FORECAST
Figure 3 shows 40 years of water consumption history. Average water use has trended
downward over time even as Palo Alto’s population has grown. Significant water use reductions
over the 40-year history were in response to requests to reduce water use in the 1976-77 and
1988-92 drought periods. During these periods, customers invested in efficient equipment and
modified behavior to achieve the water reduction goals. More recently, water sales decreased
substantially during the 2007-2009 recession and during the current drought. Water use is
down by similar amounts among both commercial and residential customers. Both summertime
and wintertime use have decreased for all customer classes.
2 The City’s water rate schedules allow for drought surcharges to be activated by Council at Level One
(10%-15% water use reduction level), Level Two (20%), or Level Three (25%)
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Figure 3: Historical Water Consumption
Figure 4 shows the forecast of water consumption through FY 2027, as denoted by the dotted
line.
Figure 4: Forecast Water Consumption
California has until recently been experiencing drought conditions, and the State had mandated
a 24% water use restriction for Palo Alto up until May 2016. Customers continue to conserve,
but water usage has been increasing. Based on patterns experienced in previous droughts and
in recognition of continued state-level calls for conservation, this forecast assumes
consumption will only return to 50% of its pre-drought levels, then resume with the previous
trend of decreasing usage over time.
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SECTION 5 B : FY 20 1 2 TO FY 2016 COST AND REVENUE TRE NDS
Figure 5 and the tables in Appendix A: Water Utility Financial Forecast Detail show how costs
have changed during the last five years as well as how they are projected to change over the
next decade.
The annual expenses for the water utility rose substantially between 20 12 and 2016. The
increases were primarily related to water purchase costs, which increased 18% from $14.9
million in FY 2012 to $17.6 million in FY 2016. A more in-depth discussion of water purchase
costs will be found in Section 6A: Water Purchase Costs. Operations cost increased by about 3%
annually, while CIP costs stayed relatively flat, except in FY 2013 when water main replacement
projects were delayed to permit completion of a backlog of projects budgeted in prior years.
Figure 5: Water Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2016 and Projections through FY 2027
Actual Projected
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SECTION 5 C : FY 201 6 RESULTS
Forecasted revenues for FY 2016 were only slightly lower than projected ($39.4 million vs.
$39.6 million) due to customers conserving more than requested during the drought. Savings in
CIP spending as well as operations and maintenance expenses were the main drivers. Table 11
summarizes the variances from forecast.
Table 11: FY 2016, Actual Results vs. Financial Plan Forecast
Net Cost/
(Benefit)
Type of
change
Lower sales revenues $175,000 Revenue decrease
Capital improvement costs lower than expected ($1,957,000) Cost savings
Admin and general costs lower than expected ($715,000) Cost savings
Operations and maintenance costs lower than expected (852,000) Cost savings
Net Cost / (Benefit) of Variances ($3,349,000)
SECTION 5 D : FY 2017 PROJECTIONS
The most notable change from the FY 2017 budget identified at this time is the deferral of
Water Main Replacement Project 27. Originally budgeted at $6.2 million, this project is now
anticipated to start in FY 2019. Also deferred to FY 2019 will be the des ign phase of Project 28,
budgeted at $585,000. Table 12 summarizes the changes from last year’s forecast.
Table 12: FY 2016 Change in Projected Results, 2016 Forecast vs 2017 Forecast
Net Cost/
(Benefit)
Type of
Change
Higher purchase costs $343,000 Cost increase
Higher sales and misc. revenues (interest
income, fees)
($327,000) Revenue increase
Capital project deferments ($6,106,000) Cost decrease
Higher Operations budgets $536,000 Cost increase
Net Cost / (Benefit) of Variances ($5,553,000)
SECTION 5 E : FY 201 8 – FY 202 7 PROJECTIONS
As can be seen in Figure 5 above, costs for the Water Utility are not projected to change
significantly through the rest of the forecast period. Water supply costs are the largest
component, but generally projected to grow steadily by two to three percent over the coming
years. Operations and capital investment costs are also expected to increase at the same rate of
inflation used in the City’s long-term financial plans (2.5% to 3.0% per year), though there is still
uncertainty with regard to the utility’s future costs for main replacement. See Section 6: Details
and Assumptions for more detail on the costs that make up these projections, as well as the
various assumptions underlying the projections.
As shown in Figure 5, above, revenues are currently below normal year expenses. Revenues
match expenses in FY 2017 and FY 2018 due to delays in water main replacement projects,
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leading to much lower annual CIP spending in those years. As main replacement resumes,
revenues are projected to be below expenses in the future and will require annual rate
increases of around 6% per year through FY 2023 to bring revenues up to match annual
expenses. This forecast assumes the use of the Rate Stabilization Reserve to spread the
increases over multiple years.
Reserves trends based on these revenue projections are shown in Figure 6 below. The Rate
Stabilization Reserve is projected to have a zero balance by the end of FY 2017, and the CIP
Reserve is projected to decrease by $2.7 million by the end of FY 2019. Assuming these
increases in revenue, the Operations Reserve, the main contingency reserve, is expected to
remain above the minimum reserve level and will be adequate to meet all identified risks, as
discussed in Section 5F: Risk Assessment and Reserves Adequacy.
These projections assume that drought restrictions are not re-imposed by the State. The
forecast also assumes that water main projects can be resized such that costs do not increase
by more than inflation.
Figure 6: Water Utility Reserves
Actual Reserve Levels for FY 2016 and Projections through FY 2027
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SECTION 5 F : RISK ASSESSMENT AND RE SERVES ADEQUACY
The Water Utility currently has one contingency reserve, the Operations Reserve, and this
Financial Plan maintains reserves within the approved reserve maximum and minimum
guidelines throughout the forecast period, as shown in Figure 7. Reserve levels also exceed the
short term risk assessment for the utility.
Figure 7: Operations Reserve Adequacy
Table 13 summarizes the risk assessment calculation for the Water Utility through FY 2022. The
same methodology is used for FY 202 3 through FY 2027 as well. The risk assessment includes
the revenue shortfall that could accrue due to:
1. Lower than forecasted sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget
year.
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Table 13: Water Risk Assessment ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total non-commodity revenue $18,406 $18,239 $19,829 $21,415 $23,129
Max. revenue variance, previous ten years 13% 13% 13% 13% 13%
Risk of revenue loss $1,819 $1,802 $1,959 $2,116 $2,285
CIP Budget $4,110 $4,082 $10,314 $10,067 $10,364
CIP Contingency @10% $411 $408 $1,031 $1,007 $1,036
Total Risk Assessment value $2,230 $2,210 $2,991 $3,123 $3,322
SECTION 5 G : ALTERNATE SCENAR IOS
At its February 2017 meeting, staff presented an earlier scenario with a 6% rate increase in FY
2018 followed by 6% rate increases in outer years. However, with the Operations reserve
projected to be above the target level and well within the guideline levels adopted by Council,
staff feels that a lower rate increase would be feasible, and is only proposing to increase City
retail rates to match the increase in SFPUC wholesale water rates.
SECTION 5 H : LONG -TERM OUTLOOK
CPAU has put its Water Utility on strong footing by investing in its distribution system
infrastructure and emergency water facilities over the last 20 years. The Water System Master
Plan, recently completed and under review, will give CPAU a better picture of the long-term
outlook for its infrastructure and will result in a plan for an appropriate schedule for
infrastructure replacement and upgrades. In addition, CPAU’s water supplier, the SFPUC, has
replaced and seismically strengthened its water transmission infrastructure , which will benefit
Palo Alto and all Hetch Hetchy customers over the long term.
The opportunities for CPAU’s Water Utility over the long term may be in alternative water
supplies such as recycled water, groundwater, and water from the Santa Clara Valley Water
District. These alternatives have been analyzed in the past, and will be analyzed again in an
upcoming update to the Water Integrated Resource Plan. Some of these alternatives may
provide cost savings or increased drought protection.
Climate change may begin to present challenges for the Water Utility over the next 20 to 40
years. Availability of water from SFPUC’s Regional Water System may change with changing
seasonal precipitation patterns. Water consumption patterns may change. Consumption could
increase due to drier weather or decrease as customers become even more focused on water
conservation. Droughts may become more frequent. The risk of wildfire in the foothills could
increase, possibly threatening utility infrastructure or placing greater demands on it. Sea level
rise could result in greater exposure of utility infrastructure to saltwater intrusion or the need
to protect infrastructure from inundation, possibly resulting in higher maintenance and
replacement costs. It could also affect the groundwater aquifer that the utility relies on in
emergencies. Any of these could result in increases to the costs of operating the Water Utility.
As part of the Sustainability/Climate Action Plan, CPAU is currently working on a Climate
Change Adaptation Roadmap that will begin to assess some of these risks.
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SECTION 6 : DETAILS AND ASSUMPTI ONS
SECTION 6 A : WATER P URCHASE COSTS
CPAU purchases all of the potable water supplies from the SFPUC, which owns and operates the
Hetch Hetchy Regional Water System. CPAU is one of several agencies that purchase water
from the SFPUC, all of whom are members of the Bay Area Water Supply and Conservation
Agency (BAWSCA). Palo Alto uses roughly 7% of the water delivered by the SFPUC to BAWSCA
member agencies.
The Hetch Hetchy Regional Water System begins with a system of reservoirs and tunnels in the
high Sierra in Yosemite County and is transported by a gravity-fed pipeline to the Bay Area.
Currently, the SFPUC is in the midst of a $4.8 billion bond-financed capital improvement
program (the Water System Improvement Program, or WSIP) to seismically retrofit the facilities
that transport water to the Bay Area. As of December 2016, nearly 60% of the program (by
dollar value) had been completed, while 40% was under construction.3 This has resulted in large
increases in the annual debt service costs assigned to wholesale customers like Palo Alto. The
wholesale customer debt service share of the WSIP is increasing from $53 million in FY 2010 to
over $200 million in FY 2020. As a result, the SFPUC’s wholesale water rate has already
increased from $1.43 per CCF in FY 2009 to $4.10 per CCF in FY 2017, and is forecasted to
increase to over $5.00 per CCF by FY 2025. Figure 8 shows the SFPUC’s actual wholesale water
rate since FY 2009 and a projection through FY 2027. Note that the wholesale water rate
decreased in FY 2014, but the apparent rate decrease is due to a part of the debt being directly
paid by the BAWSCA agencies. This cost is paid in addition to the wholesale water rate and
adds about $0.35 to $0.45 per CCF to the wholesale rate.
The SFPUC’s water rate projections show a less steeply increasing rate trajectory after all of the
debt for the WSIP has been issued. Parts of SFPUC’s system not included in the WSIP also may
need rehabilitation. Some of these projects are already included in the SFPUC’s rate
projections, but the SFPUC is conducting condition assessments of other “up-country” facilities,
located in the Sierras in the coming years. If the these assessments identify other facilities that
need replacement, it may result in additional rate increases beyond FY 2020 as new debt is
issued to finance the projects.
In January 2016, the SFPUC provided an early estimate for FY 2018 wholesale water rates of
$4.37 per CCF. Staff has yet to receive a new estimate, but there is much uncertainty
surrounding continued lower water usage by the BAWSCA agencies. While drought restrictions
ended in May 2016, customers’ behavior changes and wet weather may keep water usage low.
SFPUC’s rates will invariably need to increase since its costs are almost entirely fixed with no
relation to the quantity of water that delivered by the system .
As shown in Figure 8, this year’s projection of SFPUC wholesale rates has increased from the
previous year’s projection. As the drought ostensibly ended in FY 2017 and sales have started
3 Second Quarter FY 2017 WSIP Regional Quarterly Report, http://www.sfwater.org/index.aspx?page=307
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increasing, rate projections are projected to level out. However, if snow and rain do not
materialize in future years, current calls for restricted usage may continue or even be increased.
Figure 8: Historical and Projected SFPUC Wholesale Water Rate
SECTION 6 B : OPERATIONS
CPAU’s Water Utility operations include the following activities:
Administration, a category that includes charges allocated to the Water Utility for
administrative services provided by the General Fund and for Utilities Department
administration, as well as debt service and other transfers. Additional detail on Water
Utility debt service is provided in Section 6D: Debt Service
Customer Service
Engineering work for maintenance activities (as opposed to capital activities)
Operations and Maintenance of the distribution system; and
Resource Management
Appendix D: Description of Water Utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2012 to FY 2016 Operations costs (excluding debt service, rent, and transfers)
increased 3.5% per year on average (see Figure 9). The increases were driven by allocated
charges, which increased by 6% per year on average and increases in other Operations costs,
which increased by roughly 4% per year. Debt service costs increased by $2.4 million per year as
a result of a bond issued to finance the Emergency Water Supply and Storage Project. Transfers
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have varied from year to year, but are expected to remain relatively low and stable through the
forecast period.
In FY 2017 Operations costs are projected to increase by $1 million for a capital lease of
emergency generators for various wells and pump stations. This is a new ongoing cost. Aside
from that, only inflationary increases are projected for Operations costs. Underlying these
projections are assumptions for salary and benefit costs, consumer price index, and other cost
projections that match the City’s long-range financial forecast.
Figure 9: Historical and Projected Operational Costs
SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
The Water Utility’s CIP consists of the following types of projects:
Customer connections, which represents the cost when the Water Utility installs new
services or upgrades existing services at a customer’s request in response to
development or redevelopment. CPAU charges a fee to these customers to cover the
cost of these projects.
Ongoing projects, which represent the cost of replacing aging and under-recording
meters and degraded boxes and covers, minor replacements of various types of
distribution system equipment, and the cost of capitalized tools and equipment.
Actual
Regio
nal
Water
Syste
m
Projected
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One time projects, or large, non-recurring replacement of system assets (such as
reservoir rehabilitation)
Water main replacement, which represents the ongoing replacement of aging water
mains, and sometimes the services associated with those mains.
Table 14 shows the FY 2017 projected budget and the five year CIP spending plan, although
these figures are preliminary pending budget discussions starting in May. The ‘committed’
column represents funds committed to contracts for which work has not yet been completed or
invoices paid.
Table 14: Budgeted Water Utility CIP Spending ($000)
The water main replacement program funds the replacement of deteriorating water mains. The
water system consists of over 236 miles of mains, approximately 2000 fire hydrants, and over
20,000 metered service connections spanning 9 pressure zones ove r a 26 square mile service
area. CPAU utilizes an asset management database in conjunction with hydraulic modeling
software to prioritize capital improvements. Mains are selected by researching the
maintenance history of the system and identifying those that are undersized, corroded, and
subject to recurring breaks. CPAU uses a scoring system based on criticality in order to
prioritize which mains to replace first, and coordinates with the Public Works street
maintenance program to avoid cutting into newly repaved streets. CPAU replaces
approximately 3 miles of main per year, or 1.3% of the system.
Costs for the water main replacement program are increasing for a variety of reasons:
Fire Code regulations now mandate fire sprinklers for n ew residential units. To
accommodate increased fire flows, new main replacement projects require larger
diameter pipe.
CPAU has switched to high-density polyethylene (HDPE) for its mains. Installation costs
for this material are slightly higher, though lifecycle costs are lower, and the material
performs better. Joints in distribution mains are the most likely place for failure, and
sections of HDPE pipe can be fused together rather than connected with fittings. In the
long run, this will reduce losses and maintenance costs.
To take full advantage of HDPE’s fusibility, CPAU is now replacing the services along
with the water mains with new HDPE services. In the past, the existing services were
reconnected, regardless of the material. This new practice costs more in the short run,
but will provide long term benefits.
Lastly, costs have escalated after the recession.
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These factors have created some uncertainty in future water main replacement costs. If the
cost of water main replacement continues at its current levels, water main repla cement
budgets will need to be increased by $1M to $2M per year to keep up the current pace of main
replacement. However, CPAU is nearing the end of a long term water main replacement
program initiated in 1993 to replace the oldest and most degraded parts of the system. Roughly
25% of the system has been replaced, and the rate of water leaks has decreased 50%. CPAU
initiated a master planning process in FY 2015 to evaluate the current state of the distribution
system and determine the necessary rate of main replacement in future years, and it was
completed in 2016. Currently the utility replaces about 1.3% of the system each year, which is
an 80-year replacement cycle.
Increases in CIP cost are a partial reason for the projected two year delay in projects. The most
recent project, when put out for bid, resulted in very few contractors competing, and project
bids were larger than budgeted. Staff will redesign this and future projects into smaller
segments to keep budgets lower, while not compromising on overa ll system integrity. The
other reason for delay is the University Avenue Business District project, and getting
coordination amongst all departments is taking more time than expected. Finally, there has
been an ongoing issue with keeping and maintaining qu alified staff to design and work on
projects.
One project not included in this forecast is the seismic strengthening of a large water
transmission line in the foothills. Staff has engaged a consultant to investigate alternatives for
this project. The consultant is analyzing an alternative that involves installing a valve and hose
system that could be used to bypass breaks in the line while they are repaired after an
earthquake. This is a relatively low cost alternative that would not substantially affect the
financial forecast. The study is not finalized yet, however, and if it is determined that the entire
pipeline needs to be replaced, it could cost between $15 million and $20 million, which would
likely require bond financing and would substantially affect the financial forecast.
Ongoing Projects and Customer Connections are projected to cost approximately $2.5 million in
FY 2018 and increase by 3.5% per year through the end of the forecast period. Actual expenses
for these projects fluctuate annually depending on how many defective meters are discovered
and replaced during routine maintenance, as well as how much development and
redevelopment is going on that prompts the replacement or upgrade of water services. It is
worth noting that property owners pay a fee for water service replacement or expansion during
redevelopment, so when the number of projects go up (meaning higher costs for thi s activity),
so does fee revenue.
Aside from customer connections, the CIP plan for FY 2017 to FY 2022 is funded by utility rates
and capacity fees. The details of the plan are shown in Appendix B: Water Utility Capital
Improvement Program (CIP) Detail.
SECTION 6 D : DEBT SERVICE
The Water Utility’s annual debt service is roughly $3.2 million per year. This is related to two
bond issuances, one requiring payments through 2026, the other through 2035. CPAU is in
compliance with all covenants on both bonds.
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The first bond is the 2009 Water Revenue Bond, Series A, issued for $35 million to finance
construction of the Emergency Water Supply and Storage project (the El Camino Reservoir, new
wells, rehabilitation of existing wells and tanks, etc.) and to be retired by 2035. As part of the
‘Build America’ bond program, there is an interest payment subsidy from the Federal
Government of 35%. There is always the possibility that the federal government will choose to
stop payment on this subsidy. The automatic federal spending cuts under the Budget Control
Act (BCA) of 2011 have already reduced the subsidy by $50,000 per year, and if planned cuts
through 2021 proceed without amendment, staff estimates that the subsidy would be reduced
by over $200,000 per year by 2021. The Bipartisan Budget Act of 2013, which relieved some of
the discretionary spending cuts in the 2011 BCA, did not affect automatic cuts to the subsidy,
and actually extended the automatic cuts through 2023.
The second bond issuance is the 2011 Utility Revenue Refunding Bond, Series A, which is to be
retired in 2026. This $17.2 million issuance refinanced an earlier Water and Gas Utility bond
issuance, the 2002 Utility Revenue Bonds, Series A, which was issued to finance various capital
improvements for both systems. The Water Utility’s share of the issuance was roughly $7.8
million.
The cost of debt service for the Water Utility’s share of these bond issuances for the financial
forecast period is shown in Table 15:
Table 15: Water Utility Debt Service ($000)
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
2009 Water Revenue Bonds,
Series A (net of grants) 2,012 2,031 2,046 2,064 2,079 2,101 2,151 2,151
2011 Utility Revenue Bonds,
Series A 657 656 654 656 657 657 657 658
Both the 2009 and 2011 Bonds include the following covenants: 1) net revenues plus Available
Reserves shall at least equal 125% of the maximum annual debt service, and 2) Available
Reserves shall be at least 5 times the maximum annual debt service. Note that “Available
Reserves,” as defined for both bonds, include the reserves for the Gas and Electric systems, not
just the Water system. This Financial Plan maintains compliance with these covenants
throughout the forecast period, as shown in Appendix A: Water Utility Financial Forecast Detail.
The net revenues (but not the reserves) of the Water Utility are also pledged for one other
bond as shown in Table 16 below, even though the Water Utility is not responsible for the debt
service payments. The Water Utility’s reserves or net revenues would only be called upon if the
responsible utilities are unable to make their debt service payments. Staff does not currently
foresee this occurring. Requirements of the California Constitution require that any amounts
advanced from one utility to pay debt service for another utility must be repaid by the
borrowing fund.
Table 16: Other Issuances Secured by the Water Utility’s Revenues or Reserves
Bond Issuance Responsible
Utilities
Annual Debt
Service ($000)
Secured by Water Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
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SECTION 6 E : OTHER REVENUES
The Water Utility receives most of its revenues from sales of water. The next largest source is
connection and capacity fees, which in FY 2016 represented 51% of revenue from sources other
than water sales. The remainder consisted of a variety of miscellaneous charges, transfers and
interest income.
Revenues from connection and capacity fees have more than doubled since FY 2009.
Connection fees are charged to new developments that need new or replacement service
connections, while capacity fees are charged to development that put additional demands on
the water distribution system. Revenue from these sources decreased slightly during the
recession, but has increased substantially since then. Staff is forecasting lower revenue from
these sources in subsequent years, but has increased connection fees that are expected to
offset these reductions to some extent.
Other revenue sources are projected to stay stable through the forecast period, though interest
income always fluctuates depending on changes in interest rates. Some uncertainty also exists
related to the Federal government’s commitment to continuing to pay the interest subsidy on
the Build America Bonds.
SECTION 6 F : SALES REVENUES
Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the
projected rate changes shown in Figure 5. Except where stated otherwise, these load forecasts
are based on normal precipitation. Precipitation can vary substantially, however, even in non -
drought years, and this can affect revenues substantially. In dry years customers use more
water, increasing revenues, and in wet years they use less. These variations happen in the
winter, since summers have virtually no local precipitation regardless of whether it is a dry or
wet year. The variations are most likely related to winter irrigation demand.
SECTION 7 : COMMUNICATIONS PLAN
In FY 2018, communications will continue to focus on water utility rate increases, including the
reasons why and how rates may change contingent upon continued drought conditions. The
City will also communicate how infrastructure costs and rising rates from our wholesale water
supplier, the San Francisco Public Utilities Commission, increases CPAU costs and must be
recovered through rate increases. Rates communications will include a substantial update to
information on a webpage dedicated to Utilities rates, “breaking news” on the Utility home
webpage, discussion in the Proposition 218 rate adjustment notice, bill inserts, print ads, videos
for web and television, social media posts and frequent educational updates to internal and
external stakeholders (customer service, marketing, City Manager’s Office, UAC, City Council,
business and residential customers). Other communications vehicles will include financial plans,
presentations to UAC, Finance Committee, City Council and any media coverage as a result of
the rate increases. CPAU will continue its outreach about drought conditions and importance of
water use efficiency, tying in the message that although rates are increasing, effic ient usage
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should mean that a customer should not see a significant increase in water utility costs on their
bills.
Water conservation outreach will include bill inserts, web updates, email newsletters, videos
for the web and television, presentations to customer groups and the use of social media. To
keep customers apprised of the status and accomplishments of CIP projects, a network of
project web pages are maintained. Traffic is driven to the website via ads in publications,
newspaper inserts, and through the comprehensive portfolio of outreach strategies as outlined
above. Safety topics are also emphasized year-round. For all utility outreach, while print
materials and website pages still feature prominently, CPAU is placing more emphasis on digital
advertising content, direct mail, community safety/emergency preparation events and
presentations.
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APPENDICES
Appendix A: Water Utility Financial Forecast Detail
Appendix B: Water Utility Capital Improvement Program (CIP) Detail
Appendix C: Water Utility Reserves Management Practices
Appendix D: Description of Water Utility Operational Activities
Appendix E: Sample of Water Utility Outreach Communications
APPENDIX A : WATER UTILITY FINANCIAL FORECAST D ETAIL
1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 WATER SUPPLY
4 Purchases 5,538,305 5,532,947 5,507,153 4,671,433 4,127,085 4,164,524 4,388,840 4,618,793 4,548,794 4,477,618 4,407,222 4,342,411 4,307,346 4,274,401 4,242,367 4,274,975
5 Sales 5,062,873 5,097,392 5,047,148 4,433,016 3,858,825 3,852,185 4,037,731 4,318,572 4,253,123 4,186,573 4,120,753 4,060,155 4,027,369 3,996,565 3,966,613 3,997,101
6
7 BILL AND RATE CHANGES
8 Variable Charge (Supply)38%11%-16%25%22%9%7%2%2%2%2%2%2%2%2%2%
9 Variable Charge (Distribution)-12%17%30%-16%10%5%0%9%9%9%9%8%2%1%1%0%
10 Service Charge (Distribution)72%75%9%0%-10%3%0%7%8%8%8%7%1%1%1%1%
11 Change in System Average Rate 12%22%8%0%11%7%3%6%6%6%6%6%2%2%2%1%
12 Change in Average Residential Bill 12%21%7%-1%17%4%-3%5%5%5%5%4%1%1%1%1%
13
14 STARTING RESERVES
15 Reappropriations (Non-CIP)20,000 - - - - - - - - - - - - - - -
16 Commitments (Non-CIP)765,000 714,000 2,000 347,000 347,000 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273
17 Restricted for Debt Service 3,348,000 3,225,000 3,225,000 3,331,000 3,316,000 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194
18 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - -
19 Capital Reserve - - - - 4,000,000 2,726,096 2,726,096 2,726,096 2,726,096 - - - - - - -
20 Rate Stabilization Reserve 10,639,000 7,996,000 17,272,000 20,133,000 6,567,000 1,877,437 - - - - - - - - - -
21 Operations Reserve - - - - 11,663,836 14,606,828 12,734,948 13,741,252 11,719,450 11,584,505 10,055,718 10,036,283 11,372,030 12,259,805 12,625,012 12,452,508
22 Unassigned - - - - - - 4,645,111 2,536,339 - - - - - - - -
23 TOTAL STARTING RESERVES 15,772,000 12,935,000 21,499,000 24,811,000 25,893,836 22,686,828 23,582,622 22,480,154 17,922,013 15,060,972 13,532,185 13,512,750 14,848,497 15,736,272 16,101,479 15,928,975
24
25 REVENUES
26 Net Sales 30,673,882 36,647,924 39,029,262 33,654,549 36,136,644 38,472,811 38,957,254 43,554,523 45,527,612 47,631,527 49,893,912 52,045,952 52,530,594 52,972,178 53,425,127 54,321,702
27 Other Revenues and Transfers In 5,892,133 6,811,461 4,053,920 7,504,848 3,258,936 3,376,354 3,433,864 3,492,074 3,550,893 3,611,902 3,677,134 3,743,736 3,831,586 3,921,772 4,014,356 4,109,403
28 TOTAL REVENUES 36,566,015 43,459,385 43,083,182 41,159,397 39,395,579 41,849,165 42,391,118 47,046,597 49,078,505 51,243,429 53,571,045 55,789,688 56,362,180 56,893,950 57,439,483 58,431,104
29
30 EXPENSES
31 Water Purchases 14,889,399 16,605,351 15,705,288 15,669,935 17,626,020 19,242,650 21,347,331 22,755,908 22,849,411 22,932,958 23,015,268 23,119,511 23,365,972 23,624,549 23,889,660 24,494,388
32 Operating Expenses
33 Administration
34 Allocated Charges 2,003,116 2,422,880 2,366,077 2,342,985 2,953,291 2,278,910 2,336,257 2,395,035 2,455,296 2,516,847 2,579,804 2,644,346 2,710,515 2,778,341 2,847,864 2,919,126
35 Rent 2,156,887 1,911,963 2,192,454 2,249,457 1,803,087 2,876,500 2,962,795 3,051,679 3,143,229 3,237,526 3,334,652 3,434,691 3,537,732 3,643,864 3,753,180 3,865,775
36 Debt Service 3,385,986 3,219,165 3,220,208 3,218,869 3,222,606 3,219,316 3,222,669 3,220,858 3,220,638 3,222,843 3,223,563 3,224,553 3,224,553 3,224,553 3,224,553 3,224,553
37 Transfers and Other Adjustments 301,963 2,241,793 335,808 63,612 (74,782) 383,630 391,302 399,129 407,111 415,253 423,558 432,030 432,030 432,030 432,030 432,030
38 Subtotal, Administration 7,847,952 9,795,801 8,114,546 7,874,923 7,904,202 8,758,356 8,913,023 9,066,700 9,226,274 9,392,469 9,561,576 9,735,619 9,904,830 10,078,787 10,257,626 10,441,484
39 Resource Management 552,972 557,910 570,040 488,331 592,744 955,380 987,746 1,020,939 1,055,358 1,085,650 1,113,619 1,142,552 1,172,547 1,203,329 1,234,919 1,267,339
40 Operations and Mtc 4,900,606 4,944,064 4,986,274 5,283,426 5,038,570 5,835,064 6,037,842 6,245,861 6,461,794 6,649,627 6,821,437 6,999,319 7,183,933 7,373,416 7,567,897 7,767,508
41 Engineering (Operating)301,278 338,659 381,502 358,128 282,472 372,459 385,617 399,118 413,142 425,250 436,259 447,663 459,507 471,664 484,143 496,952
42 Customer Service 1,544,608 1,584,759 1,677,926 1,821,447 2,076,559 2,106,862 2,181,487 2,258,058 2,337,605 2,406,207 2,468,516 2,533,069 2,600,120 2,668,946 2,739,594 2,812,112
43 Allowance for Unspent Budget - - - - - (427,532) (441,610) (456,050) (471,013) (484,354) (496,795) (509,652) (522,968) (536,631) (550,651) (565,038)
44 Subtotal, Operating Expenses 15,147,415 17,221,192 15,730,288 15,826,254 15,894,546 17,600,589 18,064,105 18,534,625 19,023,161 19,474,849 19,904,612 20,348,569 20,797,968 21,259,512 21,733,529 22,220,358
45 Capital Program Contribution 9,366,201 1,068,841 8,335,605 8,580,372 9,082,021 4,110,131 4,082,150 10,314,204 10,066,974 10,364,408 10,670,600 10,985,862 11,310,465 11,644,682 11,988,797 12,343,106
46 TOTAL EXPENSES 39,403,015 34,895,385 39,771,182 40,076,561 42,602,588 40,953,371 43,493,586 51,604,738 51,939,546 52,772,216 53,590,481 54,453,941 55,474,405 56,528,743 57,611,987 59,057,851
47 9.04 11.04
48 ENDING RESERVES
49 Reappropriations (Non-CIP)- - - - - - - - - - - - - - - -
50 Commitments (Non-CIP)714,000 2,000 347,000 347,000 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273 177,273
51 Restricted for Debt Service 3,225,000 3,225,000 3,331,000 3,316,000 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194 3,299,194
52 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
53 Capital Reserve - - - 4,000,000 2,726,096 2,726,096 2,726,096 2,726,096 - - - - - - - -
54 Rate Stabilization Reserve 7,996,000 17,272,000 20,133,000 6,567,000 1,877,437 - - - - - - - - - - -
55 Operations Reserve - - - 11,663,836 14,606,828 12,734,948 13,741,252 11,719,450 11,584,505 10,055,718 10,036,283 11,372,030 12,259,805 12,625,012 12,452,508 11,825,761
56 Unassigned - - - - - 4,645,111 2,536,339 - - - - - - - - -
57 TOTAL ENDING RESERVES 12,935,000 21,499,000 24,811,000 25,893,836 22,686,828 23,582,622 22,480,154 17,922,013 15,060,972 13,532,185 13,512,750 14,848,497 15,736,272 16,101,479 15,928,975 15,302,228
58
59 OPERATIONS RESERVE
60 Min (60 days of non-capital expenses)- - - 5,230,611 5,447,741 6,320,551 6,805,571 7,121,003 7,223,351 7,318,139 7,409,255 7,506,449 7,620,837 7,739,213 7,860,713 8,040,147
61 Target (90 days of non-capital expenses)- - - 9,395,240 8,849,765 9,527,750 10,273,411 10,734,869 10,891,793 11,037,461 11,177,725 11,327,238 11,511,321 11,701,700 11,897,086 12,179,700
62 Max (120 days of non-capital expenses)- - - 13,559,870 12,251,790 12,734,948 13,741,252 14,348,735 14,560,236 14,756,784 14,946,195 15,148,027 15,401,806 15,664,187 15,933,458 16,319,253
63 Risk Assessment Value 2,481,768 2,677,436 2,229,786 2,210,426 2,990,773 3,122,798 3,321,829 3,535,280 3,739,581 3,798,452 3,858,547 3,919,900 3,982,541
64
65 DEBT SERVICE COVERAGE RATIO
66 Net Revenues (125% of Debt Service)787%951%876%878%940%1044%1123%1182%1200%1216%1231%1248%1270%1292%1315%1349%
67 Available Reserves (5x Debt Service)*2.7 5.7 6.6 6.9 6.0 6.2 5.9 4.5 3.6 3.1 3.1 3.5 3.8 3.9 3.9 3.7
*For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
Appendix A (continued)
1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 REVENUES
4 Net Sales 84%84%91%82%92%92%92%93%93%93%93%93%93%93%93%93%
5 Other Revenues and Transfers In 16%16%9%18%8%8%8%7%7%7%7%7%7%7%7%7%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Water Purchases 38%48%39%39%41%47%49%44%44%43%43%42%42%42%41%41%
10 Operating Expenses
11 Administration
12 Allocated Charges 5%7%6%6%7%6%5%5%5%5%5%5%5%5%5%5%
13 Rent 5%5%6%6%4%7%7%6%6%6%6%6%6%6%7%7%
14 Debt Service 9%9%8%8%8%8%7%6%6%6%6%6%6%6%6%5%
15 Transfers and Other Adjustments 1%6%1%0%0%1%1%1%1%1%1%1%1%1%1%1%
16 Subtotal, Administration 20%28%20%20%19%21%20%18%18%18%18%18%18%18%18%18%
17 Resource Management 1%2%1%1%1%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 12%14%13%13%12%14%14%12%12%13%13%13%13%13%13%13%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 4%5%4%5%5%5%5%4%5%5%5%5%5%5%5%5%
21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%-1%
22 Subtotal, Operating Expenses 38%49%40%39%37%43%42%36%37%37%37%37%37%38%38%38%
23 Capital Program Contribution 24%3%21%21%21%10%9%20%19%20%20%20%20%21%21%21%
24 TOTAL EXPENSES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
25
26 RISK ASSESSMENT DETAIL
27 Distribution Revenue Variance 1,623,731 1,769,234 1,818,772 1,802,211 1,959,352 2,116,101 2,285,389 2,468,220 2,640,995 2,667,405 2,694,079 2,721,020 2,748,230
28 10% CIP Program Contingency 858,037 908,202 411,013 408,215 1,031,420 1,006,697 1,036,441 1,067,060 1,098,586 1,131,047 1,164,468 1,198,880 1,234,311
29 Total Risk Asssessment Value 2,481,768 2,677,436 2,229,786 2,210,426 2,990,773 3,122,798 3,321,829 3,535,280 3,739,581 3,798,452 3,858,547 3,919,900 3,982,541
30 Projected Operations Reserve 11,663,836 14,606,828 12,734,948 13,741,252 11,719,450 11,584,505 10,055,718 10,036,283 11,372,030 12,259,805 12,625,012 12,452,508 11,825,761
31 Operations Reserve, % of Risk Value 470%546%571%622%392%371%303%284%304%323%327%318%297%
32
33 OPERATIONS RESERVE
34 Min (60 days of non-capital expenses)- - - 5,230,611 5,447,741 6,320,551 6,805,571 7,121,003 7,223,351 7,318,139 7,409,255 7,506,449 7,620,837 7,739,213 7,860,713 8,040,147
35 Target (90 days of non-capital expenses)- - - 9,395,240 8,849,765 9,527,750 10,273,411 10,734,869 10,891,793 11,037,461 11,177,725 11,327,238 11,511,321 11,701,700 11,897,086 12,179,700
36 Max (120 days of non-capital expenses)- - - 13,559,870 12,251,790 12,734,948 13,741,252 14,348,735 14,560,236 14,756,784 14,946,195 15,148,027 15,401,806 15,664,187 15,933,458 16,319,253
37 Risk Assessment Value 2,481,768 2,677,436 2,229,786 2,210,426 2,990,773 3,122,798 3,321,829 3,535,280 3,739,581 3,798,452 3,858,547 3,919,900 3,982,541
38
39 DEBT SERVICE COVERAGE RATIO
40 Net Revenues (125% of Debt Service)787%951%876%878%940%1044%1123%1182%1200%1216%1231%1248%1270%1292%1315%1349%
41 Available Reserves (5x Debt Service)*2.7 5.7 6.6 6.9 6.0 6.2 5.9 4.5 3.6 3.1 3.1 3.5 3.8 3.9 3.9 3.7
42 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants.
WATER UTILITY FINANCIAL PLAN
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APPENDIX B : WATER UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated / Carried
Forward from Previous
Years
Current Year
Funding
Proposed Budget
Amendments
Spending, Current
Year
Remaining in CIP
Reserve Fund Commitments FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
ONE TIME PROJECTS
WS-07000 Regulation Station Imp.1,092,430 - (135,541) (136,529) 820,360 624,149 - - - - -
WS-07001 Water Recycling Facilities 193,358 200,000 2,291 - 395,649 - - - - - -
WS-08001 Water Reservoir Coating 1,919,605 - (304,403) (823,254) 791,948 1,088,707 - - - - -
WS-09000 Seismic Water System 4,452,355 - (317,178) (431,985) 3,703,192 2,213,969 - - - - -
WS-13003 GPS Equipment Upgrade - - - - - - - - - - -
WS-13004 Asset Mgmt. Mobile Sys.- - - - - - - - - - -
WS-13006 Meter Shop Renovations - - - - - - - - - - -
WS-15004 Water System Master Plan 202,469 - (681) (358) 201,430 46,592 - - - - -
WS-08002 Emergency Water Supply 601,701 - - - 601,701 330,493 - - - - -
Subtotal, One-time Projects 8,461,919 200,000 (755,513) (1,392,126) 6,514,280 4,303,910 - - - - -
WATER MAIN REPLACEMENT PROGRAM
WS-20000 WMR - Project 32 - - - - - - - - - - -
WS-11000 WMR-Project 25 1,165,085 - (725,386) (270,754) 168,945 - - - - - -
WS-12001 WMR- Project 26 5,904,489 - (18,731) (51,224) 5,834,534 1 - - - - -
WS-13001 WMR - Project 27 568,065 5,680,651 (6,206,216) (42,500) - - - 6,216,841 - - -
WS-14001 WMR - Project 28 - 585,107 (585,107) - - - - 585,107 5,851,070 - -
WS-15002 WMR - Project 29 - - - - - - - - 602,660 6,026,602 -
WS-16001 WMR - Project 30 - - - - - - - - - 620,740 6,207,400
WS-19001 WMR - Project 31 - - - - - - - - - - 639,362
Subtotal, Water Main Replacement Prog.7,637,639 6,265,758 (7,535,440) (364,478) 6,003,479 1 - 6,801,948 6,453,730 6,647,342 6,846,762
WATER UTILITY FINANCIAL PLAN
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Appendix B: Water Utility Capital Improvement Program (CIP) Detail (Continued)
Project #Project Name
Reappropriated / Carried
Forward from Previous
Years
Current Year
Funding
Budget
Amendments
Spending, Current
Year
Remaining in CIP
Reserve Fund Commitments FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
ONGOING PROJECTS
WS-80014 Services/Hydrants - 400,000 - (171,657) 228,343 50,533 412,000 424,360 437,091 450,204 463,710
WS-80015 Water Meters 252,092 565,000 - (26,213) 790,879 - 565,000 500,000 515,000 530,450 546,364
WS-02014 W-G-W Utility GIS Data 82,817 366,025 (0) (87,607) 361,235 295,211 402,628 442,890 456,177 469,862 483,958
WS-13002 Equipment/Tools 20,685 50,000 - - 70,685 - - - - - -
WS-11003 Dist. Sys. Improvements 131,508 739,000 (602) (5,000) 864,906 163,985 247,000 254,000 261,620 269,469 277,553
WS-11004 Supply Sys. Improvements 95,884 239,000 (190) (73,156) 261,538 8,136 247,000 254,000 261,620 269,469 277,553
Subtotal, Ongoing Projects 582,986 2,359,025 (792) (363,633) 2,577,586 517,865 1,873,628 1,875,250 1,931,508 1,989,454 2,049,138
CUSTOMER CONNECTIONS (FEE FUNDED)
WS-80013 Water System Extensions 18,736 690,000 - (320,117) 388,619 112,897 710,700 732,021 753,981 776,601 799,899
Subtotal, Customer Connections 18,736 690,000 - (320,117) 388,619 112,897 710,700 732,021 753,981 776,601 799,899
GRAND TOTAL 16,701,281 9,514,783 (8,291,745) (2,440,354)15,483,964 4,934,673 2,584,328 9,409,219 9,139,219 9,413,397 9,695,799
Funding Sources
Connection/Capacity Fees 690,000 - 902,280 929,348 957,228 985,946 1,015,524
Other Utility Funds (Asset Mgmt, GIS Systems)244,109 - 268,418 295,260 304,118 313,242 322,640
Utility Rates 9,514,783 (8,291,745) 1,413,630 8,184,611 7,877,873 8,114,209 8,357,635
CIP-RELATED RESERVES DETAIL
6/30/2016
(Actual)
6/30/2017
(Unaudited)
Reappropriations (excl. Bond Funded)10,529,905 10,549,291
Commitments (excl. Bond Funded)6,171,376 4,934,673
WATER UTILITY FINANCIAL PLAN
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APPENDIX C : WATER UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the W ater Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, for the Water Utility Financial Plan
delivered in conjunction with the FY 2015 budget, FY 2015 to FY 2021 is the Financial
Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Reserves
The Water Utility’s Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 3 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 4 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Water Utility’s Capital
Improvement Program (CIP), as described in Section 5 (CIP Reserve)
d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 7 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 8 (Unassigned Reserves).
Section 3. Reserve for Commitments
At the end of each fiscal year the Reserve for Commitments will be set to an amount equal
to the total remaining spending authority for all contracts in f orce for the Water Utility at
that time.
Section 4. Reserve for Re-appropriations
At the end of each fiscal year the Reserve for Re-appropriations will be set to an amount
equal to the amount of all remaining capital and non-capital budgets, if any, that will be re-
appropriated to the following fiscal year in accordance with Palo Alto Municipal Code
Section 2.28.090.
WATER UTILITY FINANCIAL PLAN
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Section 5. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 12 months of budgeted CIP expense
Maximum Level 24 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added or removed fr om to that reserve
as a result of a change in contractual commitments related to CIP projects. Any other
additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are he ld for
a specific future purpose related to the CIP.
Section 6. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and
held to manage the trajectory of future year rate increases. Withdrawal of funds from
the Rate Stabilization Reserve requires Council action. If there are funds in the Rate
Stabilization Reserve at the end of any fiscal year, any subsequent Water Utility
Financial Plan must result in the withdrawal of all funds from this Reserve by the end of
the next Financial Planning Period.
WATER UTILITY FINANCIAL PLAN
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Section 7. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Water Utility’s Fund Balance not included in the reserves
described in Section 3-Section 6 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 7(d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Water Utility shall be designed
to return the Operations Reserve to its target level within four years.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Water Utility’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
8, below.
Section 8. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Water
Utility’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in the
Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the
City Council must include a plan to assign them to a specific purpose or return them to the
Water Utility ratepayers by the end of the first fiscal year of the next Financial Planning
Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2015,
and the next Financial Planning Period is FY 2016 through FY 2021, the Financial Plan shall
include a plan to return or assign any funds in the Unassigned Reserve by the end of
FY 2016. Staff may present an alternative plan that retains these funds or returns them over
a longer period of time.
WATER UTILITY FINANCIAL PLAN
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APPENDIX D : DESCRIPTION OF WATER UTILITY OPERATIONAL ACTIVITI ES
This appendix describes the activities associated with the various operational activities referred
to in Section 6B: Operations of this Financial Plan.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, CPAU administrative
overhead, and billing system maintenance costs. This category also includes Water Utility debt
service and rent paid to the General Fund for the land associated with reservoirs and various
other facilities.
Customer Service: This category includes the Water Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process. It
does not include maintenance of the billing system itself, which is included in Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their water s ervices.
Engineering (Operating): The Water Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
investigating reports of damaged mains or services and performing emergency repairs;
testing and operating valves;
monitoring water quality and reservoir levels;
monitoring the status of the different pressure zones;
flushing water at hydrants and other closed end points of the system;
building and replacing water services for new or redeveloped buildings; and
testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
the Field Services team (which does field research of various customer service issues);
the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal tanks and reservoirs); and
the General Services team (which manages and maintains equipment, paves and
restores streets after gas, water, or sewer main replacements, and provides welding
services)
Resource Management: This category includes water procurement, contract management,
water resource planning, interaction with BAWSCA, the SFPUC, and the SCVWD, and tracking of
legislation and regulation related to the water industry.
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APPENDIX E : SAMPLE OF WATER UTILITY OUTREACH COMMUNICATI ONS
Attachment C
* NOT YET APPROVED *
170216 jb 6053919
Resolution No. _________
Resolution of the Council of the City of Palo Alto Increasing Water
Rates by Amending Rate Schedules W-1 (General Residential Water
Service), W-2 (Water Service from Fire Hydrants), W-4 (Residential
Master-Metered and General Non-Residential Water Service), and
W-7 (Non-Residential Irrigation Water Service) and Repealing
Resolution No. 9542 to Deactivate the Level 2 Drought Surcharges
R E C I T A L S
A. On January 17, 2014 the Governor of the State of California proclaimed a State of
Emergency due to severe drought conditions. On April 1, 2015 the Governor issued an
Executive Order proclaiming that severe drought conditions continued to exist, and ordering
the State Water Resources Control Board to adopt regulations imposing mandatory water use
restrictions on water suppliers to achieve a 20% reduction in statewide potable water use
through February 28, 2016, or as continued or modified by the Governor.
B. On May 5, 2015, the State Water Resources Control Board adopted regulations
imposing upon Palo Alto a mandatory 24% reduction in potable water consumption from
Jun 1, 2015 through February 28, 2016. This action by the Board triggered the City Council’s
authority to activate one of the three drought surcharges available in its water rate schedules.
C. On August 17, 2015, Council adopted Resolution 9542 which established that the
Level 2 (20%) drought surcharges set forth on the City's schedule of water rates would be
collected on all City of Palo Alto Utilities water customer bills as of September 1, 2015, and
declared that the surcharge would remain in effect until rescinded or modified by the City
Council.
D. On May 9, 2016 Governor Brown issued an Executive Order calling for the State
Water Resources Control Board to adjust emergency water conservation regulations through
the end of January 2017, in recognition of the different water supply conditions across the
state. The State Board subsequently revised its regulations allowing suppliers to self-certify
that there would be no supply shortfall, assuming 3 additional dry years. . The San Francisco
Regional Water System (RWS) supply availability enabled the City of Palo Alto to self-certify a
conservation standard of zero which remains in effect.
E. While the State’s emergency regulation remains in effect, hydrological conditions as
of February 2017 indicate that the State will be largely out of drought conditions, and customer
demand has started to rise from peak conservation levels. Water storage in the RWS is at
maximum capacity.
F. Staff therefore recommends the deactivation of the level 2 drought surcharge at this
time, via the repeal of Resolution No. 9542.
Attachment C
* NOT YET APPROVED *
170216 jb 6053919
G. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the
City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees
and charges.
H. On ____, 2017, the City Council held a full and fair public hearing regarding the
proposed rate increase and considered all protests against the proposals.
I. As required by Article XIII D, Section 6 of the California Constitution and applicable
law, notice of the ________ 2017 public hearing was mailed to all City of Palo Alto Utilities
water customers by _______, 2017.
J. The City Clerk has tabulated the total number of written protests presented by the
close of the public hearing, and determined that it was less than fifty percent (50%) of the total
number of customers and property owners subject to the proposed water rate amendments,
therefore a majority protest does not exist against the proposal.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule W-1 (General Residential Water Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule W-1, as amended, shall become effective July 1, 2017.
SECTION 2. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule W-2 (Water Service from Fire Hydrants) is hereby amended to read as attached
and incorporated. Utility Rate Schedule W-2, as amended, shall become effective July 1, 2017.
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule W-4 (Residential Master-Metered and General Non-Residential Water Service) is
hereby amended to read as attached and incorporated. Utility Rate Schedule W-4, as amended,
shall become effective July 1, 2017.
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule W-7 (Non-Residential Irrigation Water Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule W-7, as amended, shall become effective
July 1, 2017.
SECTION 5. The City Council finds as follows:
a. Revenues derived from the water rates approved by this resolution do not exceed
the funds required to provide water service.
b. Revenues derived from the water rates approved by this resolution shall not be used
for any purpose other than providing water service, and the purposes set forth in
Article VII, Section 2, of the Charter of the City of Palo Alto.
Attachment C
* NOT YET APPROVED *
170216 jb 6053919
c. The amount of the water rates imposed upon any parcel or person as an incident of
property ownership shall not exceed the proportional cost of the water service
attributable to the parcel.
SECTION 6. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 7. Each of the rate schedules adopted by this resolution includes a structure
of drought surcharges that correspond to different levels of water use reduction in the City.
Effective July 1, 2017, each of the drought surcharges in the water rate schedules adopted by
this resolution are deactivated and shall not be added to applicable water rates, unless and
until such time as Council again approves both their use and the appropriate reduction level.
SECTION 8. The Council finds that the adoption of this resolution changing water
rates to meet operating expenses, purchase supplies and materials, meet financial reserve
needs and obtain funds for capital improvements necessary to maintain service is not subject to
the California Environmental Quality Act (CEQA), pursuant to California Public Resources Code
Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec. 15273(a). After
reviewing the staff report and all attachments presented to Council, the Council incorporates
these documents herein and finds that sufficient evidence has been presented setting forth
with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
__________________________
Director of Administrative Services
GENERAL RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-1-1 Effective 7-1-20176
dated 97-1-20165 Sheet No W-1-1
A. APPLICABILITY:
This schedule applies to all separately metered single family residential water services.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides water services.
C. RATES:
Per Meter
Monthly Service Charge: Per Month
For 5/8-inch meter ..................................................................................................... $ 16.77
For 3/4 inch meter ..................................................................................................... 22.60
For 1 inch meter ........................................................................................................ 34.26
For 1 1/2 inch meter .................................................................................................. 63.40
For 2-inch meter ........................................................................................................ 98.37
For 3-inch meter ........................................................................................................ 209.11
For 4-inch meter ........................................................................................................ 372.31
For 6-inch meter ........................................................................................................ 762.81
For 8-inch meter ........................................................................................................ 1,403.94
For 10-inch meter ...................................................................................................... 2,219.92
For 12-inch meter ....................................................................................................... 2,919.34
Commodity Rate: (To be added to Service Charge and applicable to all pressure zones.)
Per Hundred Cubic Feet (ccf)
Per Month All Pressure Zones
Tier 1 usage ........................................................................................................................$6.6630
Tier 2 usage (All usage over 100% of Tier 1) ........................................................................ 89.182
ATTACHMENT D
GENERAL RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-1-2 Effective 7-1-20176
dated 97-1-20165 Sheet No W-1-2
Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable Commodity Rate for Tier 1 and Tier
2 water usage when the City Council has determined that a water reduction level is in effect for the
City as described in Section D.3. The drought surcharges in the table below are measured in dollars
per hundred cubic feet (ccf).
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Tier 1 0.20 0.43 0.64
Tier 2 0.58 1.21 1.85
Temporary unmetered service to residential
subdivision developers, per connection ........................................................................ $6.00
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Calculation of Usage Tiers
Tier 1 water usage shall be calculated and billed based upon a level of 0.2 ccf per day
rounded to the nearest whole ccf, based on meter reading days of service. As an example,
for a 30 day bill, the Tier 1 level would be 0 through 6 ccf. For further discussion of bill
calculation and proration, refer to Rule and Regulation 11.
GENERAL RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-1-3 Effective 7-1-20176
dated 97-1-20165 Sheet No W-1-3
3.Drought Surcharge
During period of water shortage or restrictions on local water use, the City Council may,
by resolution, declare the need for citywide water conservation at the 10/15%, 20% or
25% level. While such a resolution is in effect, a drought surcharge will apply. The
purpose of the Drought Surcharge is to recover revenues lost as a result of reduced
consumption.
{End}
WATER SERVICE FROM FIRE HYDRANTS
UTILITY RATE SCHEDULE W-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-2-1 Effective 7-1-20176
dated 97-1-20165 Sheet No W-2-1
A. APPLICABILITY:
This schedule applies to all water taken from fire hydrants for construction, maintenance, and
other uses in conformance with provisions of a Hydrant Meter Permit.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides water services.
C. RATES:
1. Monthly Service Charge.
METER SIZE
5/8 inch ........................................................................................................................... 50.00
3 inch ........................................................................................................................... 125.00
2.Commodity Rate: (per hundred cubic feet) ................................................................ $7.6832
3. Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable Commodity Rate when the
City Council has determined that a water reduction level is in effect for the City as described in
Section D.5. The drought surcharges in the table below are measured in dollars per hundred
cubic feet (ccf).
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Surcharge 0.26 0.53 0.77
D. SPECIAL NOTES:
1.Monthly charges shall include the applicable monthly service charge in addition to usage billed at
the commodity rate.
2.Any applicant using a hydrant without obtaining a Hydrant Meter Permit or any permittee using a
hydrant without a Hydrant Meter Permit shall pay a fee of $50.00 for each day of such use in
WATER SERVICE FROM FIRE HYDRANTS
UTILITY RATE SCHEDULE W-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-2-2 Effective 7-1-20176
dated 97-1-20165 Sheet No W-2-2
addition to all other costs and fees provided in this schedule. A hydrant permit may be denied or
revoked for failure to pay such fee.
3.A meter deposit of $750.00 may be charged any applicant for a Hydrant Meter Permit as a
prerequisite to the issuance of a permit and meter(s). A charge of $50.00 per day will be added for
delinquent return of hydrant meters. A fee will be charged for any meter returned with missing or
damaged parts.
4. Any person or company using a fire hydrant improperly or without a permit, or who draws water
from a hydrant without a meter installed and properly recording usage shall, in addition to all other
applicable charges be subject to criminal prosecution pursuant to the Palo Alto Municipal Code.
5.During period of water shortage or restrictions on local water use, the City Council may, by
resolution, declare the need for citywide water conservation at the 10/15%, 20% or 25% level.
While such a resolution is in effect, a drought surcharge will apply. The purpose of the Drought
Surcharge is to recover revenues lost as a result of reduced consumption.
{End}
RESIDENTIAL MASTER-METERED AND
GENERAL NON-RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-4-1 Effective 7-1-20176
dated 97-1-20165 Sheet No W-4-1
A. APPLICABILITY:
This schedule applies to non-residential water service in the City of Palo Alto and its distribution
area. This schedule is also applicable to multi-family residential customers served through a master
meter.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides water services.
C. RATES:
Per Meter
Monthly Service Charge Per Month
For 5/8-inch meter .................................................................................... $ 16.77
For 3/4-inch meter .................................................................................... 22.60
For 1-inch meter .................................................................................... 34.26
For 1 ½-inch meter .................................................................................... 63.40
For 2-inch meter .................................................................................... 98.37
For 3-inch meter .................................................................................... 209.11
For 4-inch meter .................................................................................... 372.31
For 6-inch meter .................................................................................... 762.81
For 8-inch meter .................................................................................... 1,403.94
For 10-inch meter .................................................................................... 2,219.92
For 12-inch meter .................................................................................... 2,919.34
Commodity Rates: (to be added to Service Charge)
Per Hundred Cubic Feet (ccf)
Per Month All Pressure Zones
Per ccf ............................................................................................................ $ 7.6832
RESIDENTIAL MASTER-METERED AND
GENERAL NON-RESIDENTIAL WATER SERVICE
UTILITY RATE SCHEDULE W-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-4-2 Effective 7-1-20176
dated 97-1-20165 Sheet No W-4-2
Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable Commodity Rate when the City
Council has determined that a water reduction level is in effect for the City as described in Section
D.2. The drought surcharges in the table below are measured in dollars per hundred cubic feet
(ccf).
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Surcharge 0.26 0.53 0.77
D. SPECIAL NOTES:
1.Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2.Drought Surcharge
During period of water shortage or restrictions on local water use, the City Council may,
by resolution, declare the need for citywide water conservation at the 10/15%, 20% or
25% level. While such a resolution is in effect, a drought surcharge will apply. The
purpose of the Drought Surcharge is to recover revenues lost as a result of reduced
consumption.
{End}
NON-RESIDENTIAL IRRIGATION WATER SERVICE
UTILITY RATE SCHEDULE W-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-7-1 Effective 7-1-20167
dated 97-1-20165 Sheet No W-7-1
A. APPLICABILITY:
This schedule applies to non-residential water service supplying dedicated irrigation meters in the
City of Palo Alto and its distribution area.
B. TERRITORY:
This schedule applies everywhere the City of Palo Alto provides water services.
C. RATES:
Per Meter
Monthly Service Charge Per Month
For 5/8-inch meter .................................................................................... $ 16.77
For 3/4-inch meter .................................................................................... 22.60
For 1-inch meter .................................................................................... 34.26
For 1 1/2 inch meter .................................................................................... 63.40
For 2-inch meter .................................................................................... 98.37
For 3-inch meter .................................................................................... 209.11
For 4-inch meter .................................................................................... 372.31
For 6-inch meter .................................................................................... 762.81
For 8-inch meter .................................................................................... 1,403.94
For 10-inch meter .................................................................................... 2,219.92
For 12-inch meter .................................................................................... 2,919.34
Commodity Rates: (to be added to Service Charge)
Per Hundred Cubic Feet (ccf)
Per Month All Pressure Zones
Per ccf ............................................................................................................ $ 89.0872
Drought Surcharges (deactivated):
A drought surcharge will be added to the Customer’s applicable Commodity Rate when the City
Council has determined that a water reduction level is in effect for the City as described in Section
D.2. The drought surcharges in the table below are measured in dollars per hundred cubic feet (ccf).
NON-RESIDENTIAL IRRIGATION WATER SERVICE
UTILITY RATE SCHEDULE W-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No W-7-2 Effective 7-1-20167
dated 97-1-20165 Sheet No W-7-2
Water Usage
Reduction level Level 1 (10/15%) Level 2 (20%) Level 3 (25%)
Surcharge 0.53 1.25 2.02
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
2. Drought Surcharge
During period of water shortage or restrictions on local water use, the City Council may,
by resolution, declare the need for citywide water conservation at the 10/15%, 20% or
25% level. While such a resolution is in effect, a drought surcharge will apply. The
purpose of the Drought Surcharge is to recover revenues lost as a result of reduced
consumption.
{End}
Page 1 of 5
4
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: March 1, 2017
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt: (1) a Resolution Approving the Fiscal Year 2018
Wastewater Collection Financial Plan
RECCOMENDATION
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Wastewater
Collection Financial Plan (Attachment B); and
EXECUTIVE SUMMARY
The FY 2018 Wastewater Collection Utility Financial Plan includes projections of the utility’s
costs and revenues through FY 2027. Treatment costs are projected to rise substantially over
the forecast period due to increasing operating costs and capital replacement needs at the
Regional Water Quality Control Plant, as well as gradually increasing capital and operating cost
increases for the wastewater collection system. However, this utility’s Operating Reserves are
higher than required by the reserve guidelines due to a one-time savings resulting from delays
in the utility’s annual main replacement program. As a result, staff projects the need for no
wastewater rate increase in FY 2018. Rate increases of 7% are projected for FY 2019 through FY
2023. Rates for FY 2024 and beyond are projected to increase by 3 to 5%.
BACKGROUND
Every year staff presents the UAC with Financial Plans for its Electric, Gas, Water, and
Wastewater Collection Utilities and recommends any rate adjustments required to maintain
their financial health. These Financial Plans include a comprehensive overview of the utility’s
operations, both retrospective and prospective, and are intended to be a reference for UAC and
Council members as they review the budget and staff’s rate recommendations. Each Financial
Plan also contains a set of Reserves Management Practices describing the reserves for each
utility and the management practices for those reserves.
Page 2 of 5
The UAC reviewed preliminary financial forecasts at its February 1, 2017 meeting. Staff has
revised the preliminary projections presented at that meeting.
DISCUSSION
Staff’s annual assessment of the financial position of the City’s wastewater collection utility is
completed to ensure adequate revenue to fund operations, in compliance with the cost of
service requirements set forth in the California Constitution (Proposition 218). This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs.
The current rates are based on the methodology described in the 2011 Wastewater Collection
Utility Cost of Service and Rate Study completed by Utility Financial Solutions (Staff Report
1399).
Proposed Actions for FY 2018
1. No rate increase
These proposed actions are described in more detail in the FY 2018 Wastewater Collection
Financial Plan (Attachment B).
Staff proposes no adjustments to wastewater rates at this time. Current rates are shown in
Table 1 below.
Table 1: Current Wastewater Collection Charges
Current
(7/1/2016)
Monthly Service and Minimum Charges
($/month)
S-1 (Residential) Service
charge
$34.83
S-2 (Commercial),
S-6 (Restaurant)
Minimum 34.83
Quantity Rates
S-1 (Residential) $/CCF N/A
S-2 (Commercial) $/CCF 6.71
S-6 (Restaurant) $/CCF 10.38
S-7 (Industrial) $/CCF 3.08
(1) Monthly charges for S-1 are fixed monthly charges, and those for S-2 and S-6 are
minimum monthly charges.
(2) Currently there are no customers on the S7 rate schedule, however, CPAU continues
to maintain it in case there is a need for the rate schedule in the future.
Page 3 of 5
FY 2018 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 2 shows the projected rate adjustments included in the Wastewater Collection Utility
Financial Plans and their impact on a residential wastewater bill.
Table 2: Projected Rate Adjustments and Residential Bill Impact, FY 2018 to FY 2022
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Wa stewater Utility 0% 7% 7% 7% 7%
Estimated Bill Impact for
Residential Customers ($/mo) $- $2.44 $2.61 $2.79 $2.99
The main drivers for the increase in the Wastewater Collection Utility’s costs (and therefore
rates) over the next several years are the costs for wastewater treatment, which are projected
to go up by 5 to 6% per year as the Regional Water Quality Control Plant makes several
upgrades to their facilities, as well as capital improvement costs for the wastewater collection
system. Operating and CIP costs are projected to rise roughly 2%-4% annually.
As mentioned above, staff is not proposing a rate increase for FY 2018 because the Wastewater
Collection Utility’s Operations Reserve is well above the target level set forth in the Reserve
Guidelines. The Operations Reserve is projected to be $5.3 million, as compared to the reserve
target of $4.6 million. Wastewater main replacement projects are temporarily delayed for a
variety of reasons: The University Avenue Business District project is taking longer to coordinate
than planned; fewer, more expensive competitive bidders on proposed projects have required
staff to re-plan those projects; and hiring and retention of qualified staff has been an issue.
There is uncertainty related to capital costs for the Wastewater Collection Utility in coming
years. Wastewater main replacement costs have risen substantially in recent years, and it is
possible higher CIP expenditures will be required in the future.
Wastewater Bill Comparison with Surrounding Cities
The annual sewer bill for a Palo Alto resident is $418 under current rates, 31% lower than the
average neighboring community. Table 3 shows the monthly sewer bills for residential
customers compared to what they would be in surrounding communities.
Table 3: Residential Monthly Sewer Bill Comparison (based on rates as of January 1, 2017)
Palo Alto
Neighboring Communities Neighboring
Community
Average
Menlo
Park
Redwood
City
Mountain
View Los Altos
Santa
Clara Hayward
34.83 85.91 75.11 34.30 33.93 41.65 29.80 50.12
Staff has no information at this time as to whether or when the surrounding communities are
planning wastewater rate changes.
Page 4 of 5
Changes from Prior Financial Forecasts
Staff has projected the need for wastewater rate increases for several years. Table 4 compares
current rate projections to those projected in the last two year’s Financial Plans.
Table 4: Projected Wastewater Rate Trajectory for FY 2018 to FY 2027
Projection FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Current
(FY 2018 Financial Plan) 0% 7% 7% 7% 7% 7% 5% 5% 4% 3%
Last Year
(FY 2017 Financial Plan) 10% 9% 7% 6% 4% 4% 4% 4% 4% N/A
Two years ago
(FY 2016 Financial Plan) 9% 9% 6% 6% N/A N/A N/A N/A N/A N/A
NEXT STEPS
The Finance Committee will consider the recommended wastewater rate changes on April 4,
2017. The proposed Financial Plan will be considered by the City Council with the FY 2018
budget.
RESOURCE IMPACT
See the FY 2018 Wastewater Collection Utility Financial Plan (Attachment B) for a more
comprehensive overview of projected cost and revenue changes for the next five years.
POLICY IMPLICATIONS
The proposed Wastewater Collection Financial Plan is consistent with Council-adopted Reserve
Management Practices.
ENVIRONMENTAL REVIEW
The UAC’s review and recommendation to Council on the proposed FY 2018 Wastewater
Collection Financial Plan does not meet the definition of a project requiring California
Environmental Quality Act (CEQA) review, under California Public Resources
Code 21065 and CEQA 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.
ATTACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2018 Wastewater
Collection Utility Financial Plan
B. Proposed FY 2018 Wastewater Collection Utility Financial Plan
PREPARED BY: ERIC KENISTON, Acting Rates Manager CE .. ~
J~~EIN, Assistant Director, Resource Mgmt;,k( REVIEWED BY:
APPROVED BY:
ED SHIKADA
General Manager of Utilities
Page 5of5
Attachment A
*NOT YET APPROVED *
170216 jb 6053915
Resolution No. ____
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 Wastewater Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) assesses the financial position of its utilities
with the goal of ensuring adequate revenue to fund operations. This includes making long-term
projections of market conditions, the physical condition of the system, and other factors that
could affect utility costs, and setting rates adequate to recover these costs. It does this with the
goal of providing safe, reliable, and sustainable utility services at competitive rates. The City
adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other aspects
of its operations, and regularly assesses the adequacy of these reserves and the management
practices governing their operation. The status of utility reserves and their management
practices are included in Reserves Management Practices attached to and made a part of the
Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2018 Wastewater Utility Financial Plan.
SECTION 2. The Council finds that the adoption of this resolution does not meet the
definition of a project requiring California Environmental Quality Act (CEQA) review, under
/ /
/ /
/ /
/ /
/ /
/ /
/ /
Attachment A
*NOT YET APPROVED *
170216 jb 6053915
California Public Resources Code 21065 and CEQA Guidelines Section 15378(b)(5), because it is
an administrative governmental activity which will not cause a direct or indirect physical change
in the environment.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Senior Deputy City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 2018 WASTEWATER
COLLECTION UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 2 | Page
FY 2018 WASTEWATER COLLECTION
UTILITY FINANCIAL PLAN
FY 2018 TO FY 202 7
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 4
Section 2A: Overview of Financial Position .................................................................................. 4
Section 2B: Summary of Proposed Actions .................................................................................. 5
Section 3: Detail of FY 2018 Rate and Reserves Proposals ....................................................... 5
Section 3A: Rate Design ............................................................................................................... 5
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3D: Proposed Reserve Transfers ..................................................................................... 6
Section 4: Utility Overview .................................................................................................... 7
Section 4A: Wastewater Utility History ....................................................................................... 7
Section 4B: customer base ........................................................................................................... 8
Section 4C: Collection System ...................................................................................................... 8
Section 4D: Cost Structure and Revenue Sources ........................................................................ 9
Section 4E: Reserves Structure ..................................................................................................... 9
Section 4F: Competitiveness ...................................................................................................... 10
Section 5: Utility Financial Projections ................................................................................. 11
Section 5A: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 11
Section 5B: FY 2016 Results ....................................................................................................... 12
Section 5C: FY 2017 Projections ................................................................................................. 13
Section 5D: FY 2018 – FY 2027 Projections ................................................................................ 13
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 14
Section 5F: Alternate Scenarios ................................................................................................. 16
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 3 | Page
Section 5G: Long-Term Outlook ................................................................................................. 16
Section 6: Details and Assumptions ..................................................................................... 16
Section 6A: Wastewater Treatment Costs ................................................................................. 16
Section 6B: Operations .............................................................................................................. 17
Section 6C: Capital Improvement Program (CIP) ....................................................................... 17
Section 6D: Debt Service ............................................................................................................ 19
Section 6E: Other Revenues ....................................................................................................... 20
Section 7: Communications Plan .......................................................................................... 20
Appendices ......................................................................................................................... 22
Appendix A: Wastewater Collection Financial Forecast Detail .................................................. 23
Appendix B: Wastewater Collection Utility Capital Improvement Program (CIP) Detail .......... 24
Appendix C: Wastewater Collection Utility Reserves Management Practices .......................... 25
Appendix D: Sample of Wastewater Collection Outreach Materials......................................... 28
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 4 | Page
SECTION 1 : DEFINITIONS AND ABBREVIATIONS
CCF The standard unit of measurement for water delivered to water customers, equal to
one hundred cubic feet, or roughly 748 gallons. When water usage is used to assess
wastewater charges for commercial customers, it is measured in CCF.
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
FOG Fats, oils, and grease. When flushed into the sewer system, these materials
accumulate in parts of the sewer system and create blockages.
O&M Operations and Maintenance
RWQCP Regional Water Quality Control Plant, the wastewater treatment plant owned and
operated by the City of Palo Alto that serves Palo Alto and several surrounding
communities.
UAC Utilities Advisory Commission
SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City of Palo Alto’s Wastewater Collection Utility
for the next ten years. The Financial Plan provides revenues to cover the costs of operating the
utility safely over that time while adequately investing for the future. It also addresses the
financial risks facing the utility over the short term and long term, and includes measures to
mitigate and manage those risks.
SECTION 2 A : OVERVIEW OF FINANCIAL POSITION
Overall costs in the Wastewater Collection Utility are expected to rise by about 6% per year
from fiscal year (FY) 2017 to FY 2027. Excluding FY 2018 (which, unlike a normal year, does not
include a sewer main replacement project), wastewater treatment and CIP costs are projected
to rise by five to six percent annually through the projection period, with other costs rising at
roughly three percent per year. The costs for the Wastewater Collection Utility are shown in
Table 1 below.
Table 1: Expenses for FY 2016 to FY 2027
Expenses
($000)
FY
2016
(act.)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Treatment
Costs 8,770 9,855 9,932 10,298 11,088 11,885 12,293 13,001 14,056 14,928 15,407 15,901
Operations 5,429 6,142 6,342 6,142 6,349 6,561 6,779 7,250 7,354 7,594 7,842 8,099
Capital
Projects 4,985 971 1,338 5,218 5,033 5,207 5,336 5,495 5,658 5,827 6,000 6,178
TOTAL 19,184 16,968 17,613 21,659 22,470 23,652 24,408 25,746 27,069 28,348 29,249 30,178
The short term reduction in CIP expenses will result in higher revenues than expenses, and the
Rate Stabilization Reserve will be drawn down over a longer time frame than projected in last
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 5 | Page
year’s financial plan. Going forward, to ensure that revenues cover rising costs and reserves
remain healthy, the financial plan includes the rate trajectory shown in Table 2. The table also
shows rate projections from last year’s Financial Plan. Last year’s plan projected earlier, more
aggressive rate increases. However, the delay of the planned FY 2017 and FY 2018 sewer main
replacement projects resulted in an increase in reserves, which enabled the more gradual
increases projected in the current plan.
Table 2: Projected Wastewater Collection Rate Trajectory for FY 2018 to FY 2026
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
FY
2027
Current Plan 0% 7% 7% 7% 7% 7% 5% 5% 4% 3%
FY 2017 Plan 10% 9% 7% 6% 4% 4% 4% 4% 4% N/A
The Wastewater Collection Utility has a small balance in its Rate Stabilization Reserve. This
reserve is used to phase in rate increases over several years. The FY 2017 Financial Plan
proposed a $342,000 transfer from the Rate Stabilization Reserve, but in the proposed FY 2018
Financial Plan this transfer is moved to later years. Due to the delays in main replacement
noted above, the Operations reserve is above its target level, and will rise again in FY 2018
before beginning to decline. This Financial Plan projects that the Rate Stabilization Reserve will
not be needed until FY 2020.
Table 3: Transfers To/(From) Reserves for FY 2017 to FY 2027 ($000)
Reserve FY 2017 FY 2018 FY 2019 to FY 2027
Rate Stabilization - - (342)
Operations - - 342
SECTION 2 B : SUMMARY OF PROPOSED ACTIONS
Staff proposes no rate changes or transfers for the Wastewater Collection Utility in FY 2017 and
FY 2018.
SECTION 3 : DETAIL OF FY 2018 RATE AND RESERVES PROPOSALS
SECTION 3 A : RATE DESIGN
The Wastewater Collection Utility’s rates are evaluated and implemented in compliance with
the cost of service requirements and procedural rules set forth in the California Constitution
(Proposition 218). Current rates were structured based on staff’s annual assessment of the
wastewater utility’s financial position, as well as the methodology from the January 2011
Wastewater Collection Utility Cost of Service & Rate Study completed by Utility Financial
Solutions (Staff Report 1399). Staff plans to review and update this cost of service study in FY
2018 or FY 2019, unless any major changes occur to the utility’s operations or customer base
that would necessitate an earlier study. Before conducting any new cost of service study, staff
will review current rates and the scope of the study with the Utilities Advisory Commission
(UAC) and Council to determine the City’s policy priorities.
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SECTION 3 B : CURRENT AND PROPOSED RATES
The current rates were adopted July 1, 2016, when the City increased sewer rates by 9%.
CPAU has three sewer rate schedules: one for residents (S-1), one for commercial customers
(S-2), and a special schedule for restaurants (S-6), which discharge higher than average amounts
of grease and oil and, therefore, have a greater impact on the sewer system. Residential
customers are billed a monthly service charge, while commercial customers are billed based on
their dry month water usage (previous January through March). This closely approximates non-
irrigation water consumption, which represents actual sewer use. Restaurant customers are
billed monthly based on water usage. CPAU also maintains a rate schedule for industrial
dischargers (S-7), but there are currently no customers required to be on this rate schedule.
CPAU us not proposing any rate changes for FY 2018 at this time. Table 4, below, summarizes
the current rates for all customer classes. Comparisons with neighboring communities are
discussed in Section 4F: Competitiveness.
Table 4: Current Sewer Rates
Current
(as of 7/1/2016)
Monthly Service and Minimum Charges ($/month)
S-1 (Residential) Service
charge
$34.83
S-2 (Commercial),
S-6 (Restaurant)
Minimum $34.83
Quantity Rates: based on winter water usage (average for January
- March bill period)
S-2 (Commercial) $/CCF 6.71
S-6 (Restaurant) $/CCF 10.38
S-7 (Industrial) $/CCF 3.08
SECTION 3 C : PROPOSED RESERVE TRANSFERS
In the FY 2017 Financial Plan, staff recommended a $1.95 million transfer from the Rate
Stabilization Reserve in FY 2016. This left a small amount, $342,000, which was originally to be
transferred in FY 2017 and bring the Rate Stabilization Reserve balance to zero.
With main replacement projects being deferred in FY 2017 and FY 2018, the Operations reserve
will not require a transfer from the Rate Stabilization Reserve. It is now anticipated that the
remaining $342,000 will not need to be transferred until FY 2020.
These transfers are included in the financial projections in this Financial Plan, and will enable
CPAU to maintain adequate Operations Reserve levels while moderating the pace of increase in
Wastewater Collection rates. The impact of these transfers on reserves levels can be seen in
Appendix A: Wastewater Collection Financial Forecast Detail.
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SECTION 4 : UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in later sections.
SECTION 4 A : WASTEWATER UTILITY HISTORY
The Wastewater Utility commenced operation in 1899 to serve Palo Alto and Stanford. In its
first three decades the system grew to 60 miles of sewers. Raw sewage was discharged into
Mayfield Slough at the edge of the Bay. In the 1930s, at the behest of the State Department of
Health, Palo Alto built the South Bay’s first wastewater treatment plant. At that time the sewer
system served 20,500 Stanford and Palo Alto residents and a cannery. The plant was upgraded
twice in the 1940s and 1950s to increase capacity.1 At the same time, the postwar population
and industrial boom in the 1950s required rapid expansion of the sewer system. In the first half
of the 1960s Palo Alto’s area doubled, as did wastewater flows, overwhelming the capacity of
several of the utility’s “trunk lines,” which are the largest diameter main sewer lines carrying
wastewater to the treatment plant. This prompted the City, in 1965, to perform the first of its
sewer master plans to identify needed capacity improvements. At that point the Wastewater
Utility’s system comprised more than 150 miles of sewer mains.2
In 1968 the City signed agreements with the Cities of Mountain View and Los Altos to build a
new regional treatment plant, the RWQCP, which is still in operation today. Since 1940 the City
had been providing treatment services to the East Palo Alto Sanitary District through an existing
agreement, and was also serving Stanford University by transporting wastewater across the
City’s sewer system to the treatment plant. Both of these organizations became partners in the
RWQCP as well. At the same time the Town of Los Altos Hills became the sixth partner as it
signed an agreement with the City to connect the Town’s sewer system to the City’s sewer
system to carry wastewater to the new RWQCP. The current agreements for the RWQCP
extend through 2035.3
In the 1980s the City directed increased attention to the condition of its sewer system,
performing a series of studies of groundwater inflow and infiltration into the system. The
studies found high rates of infiltration, estimating that as much as 40% of the water going to
the RWQCP from Palo Alto’s system was groundwater and stormwater rather than
wastewater.4 In some parts of Palo Alto the land surface had subsided due to groundwater
pumping by the water utility, and though that practice had ceased many years earlier as the
water utility switched to the Hetch Hetchy Regional Water System, parts of the city had already
subsided two to five feet. This subsidence had damaged several parts of the sewer collection
system, leading to reduced slopes for sewer mains that caused reductions in capacity. In
1 Long Range Facilities Plan for the Regional Water Quality Control Plant, August 2012, Carollo Engineers, pp 2-1
through 2-2
2 Wastewater Collection and Storm Drainage, 1965, Brown and Caldwell Consulting Engineers, pp 4, 6-7, 143
3 Long Range Facilities Plan for the Regional Water Quality Control Plant, August 2012, Carollo Engineers, pg 2-2
4 Wastewater Collection System Master Plan – Capacity Assessment, January 2004, MWH Americas, Inc., pg ES-2
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 8 | Page
response to these studies the City commenced an accelerated sewer system rehabilitation
program.5 At that point the sewer system comprised over 190 miles of mains.6
A Master Plan study in 1988 recommended a variety of capacity expansions, and in the 1990s
the City completed about half of them. However, a 2004 Master Plan update found that the
accelerated sewer rehabilitation plan started in the early 1990s had substantially reduced
infiltration, easing the capacity problems that had led the to the recommended capacity
increases in the 1988 study. Several of the outstanding projects were canceled and replaced
with a different set of projects.7 At the same time the City updated its hydraulic model and
developed greater capacity to do system planning in house.
SECTION 4 B : CUSTOMER BASE
The City of Palo Alto’s Wastewater Collection Utility provides sewer service to the residents and
businesses of Palo Alto. It is distinct from the Wastewater Treatment Utility, which provides
treatment services for surrounding communities in addition to Palo Alto. Nearly 23,300
customers are connected to the sewer system, approximately 21,450 (92%) of which are
residential and 1,850 (8%) of which are non-residential. Residential customers pay a flat fee for
service. Non-residential customers are billed for sewer service based on their metered winter
water usage. There is little variability in revenues for this utility.
SECTION 4 C : COLLECTION SYSTEM
The Wastewater Collection Utility delivers all the wastewater it collects to the Regional Water
Quality Control Plant (RWQCP) operated by the City of Palo Alto under a partnership agreement
with several surrounding communities. Palo Alto is responsible for 35% to 40% of the
wastewater sent to the RWQCP. The cost of running the RWQCP is contained in the
Wastewater Treatment Utility and is not described in detail in this Financial Plan, but since
these costs are a major driver of CPAU’s sewer rates, there is some discussion of future trends
in treatment costs in Section 6A: Wastewater Treatment Costs. Treatment costs make up
nearly half of the Wastewater Collection Utility’s expenses as shown in Table 1 above.
To collect wastewater from its customers and deliver it to the RWQCP, CPAU owns roughly
18,100 sewer laterals (which collect wastewater from customers’ plumbing systems) and 217
miles of sewer mains (which transport the waste to the treatment plant). These laterals and
mains, along with the associated manholes and cleanouts, represent the vast majority of
infrastructure used to collect wastewater in Palo Alto. CPAU conducts a sewer rehabilitation
and replacement program to replace mains over time as they deteriorate or to increase
capacity. For more discussion of this program, see Section 6C: Capital Improvement Program
(CIP). CIP expense accounts for roughly a quarter of the utility’s expenditures.
In addition to its CIP, CPAU performs various maintenance activities on the sewer system.
These include inspecting and repairing sewer laterals, responding to sewer overflows, regularly
5 CMR 183:90, Infrastructure Review and Update, March 1, 1990
6 Master Plan of the Wastewater Collection System, December 1988, Camp Dresser & McKee, Inc., pg 1-2
7 Wastewater Collection System Master Plan – Capacity Assessment, January 2004, MWH Americas, Inc., pg ES-3
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 9 | Page
cleaning sections of the system heavily impacted by fats, oils, and grease (FOG), and building
and replacing sewer laterals for new or redeveloped buildings. The utility also shares the costs
of other operational activities (such as customer service, billing, equipment maintenance, and
street restoration) with the City’s other utilities. These maintenance and operations expenses,
as well as associated administration, debt service, rent, and other costs, make up another
quarter of the utility’s expenses.
SECTION 4 D : COST STRUCTURE AND REVENUE SOURCES
In FY 2016, treatment costs represented nearly half of the Wastewater Collection Utility’s costs
(47%), followed by Capital (27%) and Operations costs (26%). These expenditures are shown in
Figure 1. The utility’s revenue in FY 2016, shown in Figure 2, came primarily from sewer charges
(94%), with the remainder coming mainly from capacity and connection fees and other sources
(6%).
Figure 1: Cost Structure (FY 2016) Figure 2: Revenue Structure (FY 2016)
SECTION 4 E : RESERVES STRUCTURE
CPAU maintains six reserves for its Wastewater Collection Utility to manage various types of
contingencies. These are summarized below, but see Appendix C: Wastewater Collection Utility
Reserves Management Practices for more detailed definitions and guidelines for reserve
management:
• Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserve for Reappropriations: A reserve for funds dedicated to projects reappropriated
by the City Council, nearly all of which are capital projects. Most City funds, including
the General Fund, have a Reappropriations Reserve.
• Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects and is anticipated to be empty
unless a major one-time CIP expenditure is expected in future years. It also acts as a
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February 2016 10 | Page
contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, Gas, and Water) as well.
• Rate Stabilization Reserve: This reserve is intended to be empty unless one or more
large rate increases are anticipated in the forecast period. In that case, funds can be
accumulated to spread the impact of those future rate increases across multiple years.
This type of reserve is used in other utility funds (Electric, Gas, and Water) as well.
• Operations Reserve: This is the primary contingency reserve for the Wastewater
Collection Utility, and is used to manage yearly variances from budget for operational
costs. This type of reserve is used in other utility funds (Electric, Gas, and Water) as well.
• Unassigned Reserve: This reserve is for any funds not assigned to the other reserves
and is normally empty.
SECTION 4 F : COMPETITIVENESS
Table 6 shows the monthly sewer bills for residential customers compared to what they would
be in surrounding communities. The annual sewer bill for a Palo Alto customer is $418 under
current rates, 31% lower than the average neighboring community. Palo Alto has the fourth
lowest bill of the group.
Table 5: Residential Monthly Sewer Bill Comparison
Palo Alto
Neighboring Communities Neighboring
Community
Average
Menlo
Park
Redwood
City
Mountain
View Los Altos
Santa
Clara Hayward
34.83 85.91 75.11 34.30 33.93 41.65 29.80 50.12
Based on rates as of February 2017
Table 7 compares the sewer bills for two classes of commercial customers to what they would
be under surrounding communities’ rate schedules. Note that other communities often have
specific rates for industrial customers that discharge high intensity wastewater, such as food
processors or chemical or electronics manufacturers, but Palo Alto does not currently have any
customers that require these special rates. Palo Alto is less competitive with surrounding cities
with regards to commercial sewer rates, but is not the most expensive jurisdiction in all cases.
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February 2016 11 | Page
Table 6: Commercial Monthly Sewer Bill Comparison
Palo Alto
Neighboring Communities Neighboring
Community
Average
Menlo
Park
Redwood
City
Mountain
View Los Altos
Santa
Clara Hayward
General
Commercial $ 94.00 $ 33.14 $ 75.11 $ 62.86 $ 50.76 $ 65.94 $ 62.02 $ 74.97
Restaurant 581.10 664.72 781.08 490.56 137.70 590.24 463.12 521.24
Based on rates as of February 2017
SECTION 5 : UTILITY FINANCIAL PROJECTIONS
SECTION 5 A : FY 2012 TO FY 2016 COST AND REVENUE TRENDS
Figure 3 shows the Wastewater Collection Utility’s actual expenses and revenues for the past
five years and projections through FY 2027. Operations costs were low in FY 2012, but in
general expenses have grown with inflation at around 2% per year. Capital Investment grew on
average by around 3%, with FY 2014 and FY 2015 seeing a reduction in investment mainly due
to delayed main replacement projects. Treatment costs stayed relatively flat during this time
frame.
Since the revenue for this utility is very stable, revenue changes closely follow rate changes. The
other large revenue item of note is the continued connection and capacity fees from new
construction. These fees have grown dramatically since FY 2010, and it is uncertain when this
trend may dampen.
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February 2016 12 | Page
Figure 3: Wastewater Collection Utility Expenses, Revenues and Rate Changes
Actual Costs through FY 2016 and Projections through FY 2027
SECTION 5 B : FY 2016 RESULTS
Forecasted revenues for FY 2016 were lower than projected ($16.6 million actual vs. $18 million
projected), but expenses related to Administration and Customer Service activities came in well
below expected budget as well. Total FY 2016 expenses were $18.5 million compared to
projections of $19.9 million in the FY 2017 Financial Plan. Table 8 summarizes the variances
from forecast.
Table 7: FY 2016, Actual Results vs. Financial Plan Forecast
Net Cost/
(Benefit)
Type of
change
Admin and customer service costs lower than projected (806,000) Cost savings
Sales revenues lower than forecast 657,000 Revenue decrease
Connection, capacity fees and other revenues were
lower than forecasted
119,000 Revenue decrease
Operations, capital and other cost increases 131,000 Cost increase
Net Cost / (Benefit) of Variances ($101,000)
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SECTION 5 C : FY 2017 PROJECTIONS
The most notable change from the FY 2017 budget identified at this time is the deferral of
Wastewater Collection System Rehabilitation Project 28. Originally budgeted at $3.5 million,
this project is now anticipated to start in FY 2019. Also deferred to FY 2019 will be the design
phase of Project 29, budgeted at $328,000. Capital Improvement issues are further discussed in
Section 6c below.
SECTION 5 D : FY 2018 – FY 2027 PROJECTIONS
Staff has prepared a forecast of costs and revenues through FY 2027. As shown in Figure 3
above (and, in more detail, in Appendix A: Wastewater Collection Financial Forecast Detail), the
Wastewater Collection Utility’s total costs are projected to increase by roughly 6% per year on
average for FY 2017 through FY 2027. The majority of this increase is due to projected
treatment cost increases. The treatment plant itself is facing the need for major upgrades in
coming years, both due to age of equipment and constantly changing environmental
regulations. While the costs of the plant are shared among member agencies, Palo Alto is still
expected to see average cost increases of 5% per year over the forecast horizon.
Revenues are shown by the red line in Figure 3, and what is notable here is that costs have
been generally higher than revenue. Some relief was experienced during times of lower CIP
expenditures, and this is projected to be seen in FY 2017 and 2018. The trend of under-
collection picks up in the future, however, resulting in a fairly rapid reduction of reserves. A
path of 7% annual rate increases in the near term, decreasing to more inflationary increases in
outer years, is required to keep reserves from dropping too low. Figure 4 below shows the
relative drop in reserves, only showing slowing replenishment after the projected increase in FY
2021.
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February 2016 14 | Page
Figure 4: Wastewater Collection Reserves Projections
SECTION 5 E : RISK ASSESSMENT AND RESERVES ADEQUACY
The Wastewater Collection Utility currently has one contingency reserve, the Operations
Reserve, and this Financial Plan maintains reserves within the approved guideline levels
throughout the forecast period, as shown in Figure 5 below. Reserve levels also exceed the
short term risk assessment for the utility.
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Figure 5: Operations Reserve Adequacy
Staff performs an annual assessment of risks for the Wastewater Collection Utility. For this
evaluation, staff estimates the revenue shortfall due to:
1. the maximum observed budget-to-actual variance in one year during the past five years;
2. an increase of 10% in system improvement CIP expenditures for the year; and
3. an increase of 10% in treatment costs.
Table 9 summarizes the risk assessment calculation for the Wastewater Collection Utility
through FY 2022. The Operations Reserve is projected to be adequate to manage these levels
of risk over the entire forecast period.
Table 8: Wastewater Collection Risk Assessment
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total Revenue ($000) 17,146 18,296 19,577 20,947 22,413
Max. Historical Budget-to-Actual variance 3% 3% 3% 3% 3%
Budget-to-Actual Risk ($000) 514 549 587 628 672
System Rehabilitation CIP Budget ($000) 933 4,800 4,602 4,763 4,880
CIP Contingency @10% ($000) 93 480 460 476 488
Treatment Budget ($000) 9,932 10,298 11,088 11,885 12,293
Treatment Cost Contingency @10% ($000) 993 1,030 1,109 1,188 1,229
Total risk assessment value ($000) 1,600 2,059 2,156 2,292 2,389
Projected Operations Reserve Level ($000) 6,688 5,410 5,069 4,529 4,732
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 16 | Page
SECTION 5 F : ALTERNATE SCENARIOS
At its February 2017 meeting, staff presented an earlier scenario with a 2% rate increase in FY
2018 followed by 6% rate increases in outer years. However, with the Operations reserve
projected to be above the target level and well within the guideline levels adopted by Council,
staff no longer sees the need for an increase at this time.
SECTION 5 G : LONG-TERM OUTLOOK
In the longer term (5 to 35 years) the primary factor that could lead to increased costs for the
Wastewater Collection Utility are major upgrades at the RWQCP, a share of which will be
allocated to the utility as part of treatment costs. These upgrades includes replacement or
rehabilitation of the parts of the facility that pump raw sewage to the main treatment works
(the headworks), separate out primary sludge (the primary settling tank), process sludge (the
bio-solids facility), and treat wastewater (the fixed film reactors). Upgrades to the laboratories
and operational buildings are planned as well. In addition, the 72-inch regional trunk sewer line
flowing into the plant needs to be evaluated and rehabilitated.
SECTION 6 : DETAILS AND ASSUMPTIONS
SECTION 6 A : WASTEWATER TREATMENT COSTS
Treatment expenses represent the Wastewater Collection Utility’s share of the costs of
operating the RWQCP. Per the partnership agreements between Palo Alto and its partner
agencies, these charges are assessed based on a formula that takes into account the total
amount of wastewater delivered, the amount of organic material in it, its ammonia content,
and the total suspended solids it is carrying. The Wastewater Collection Utility’s assessed share
of the RWQCP’s revenue requirement fluctuates in the 38% to 40% range. Mountain View is
the other large agency served by the RWQCP (39% of the revenue requirement for FY 2014)
with the smaller agencies (Stanford, Los Altos, East Palo Alto, and Los Altos Hills) making up the
remainder of the flow to the treatment plant.
Based on detailed project cost projections provided by RWQCP staff, treatment costs are likely
to continue to increase by roughly 5% per year through at least 2030. Wastewater Treatment
Fund costs are increasing due to rising salary and benefit costs as well as the attendant
allocated charges for centralized city services needed by the Fund. Additional expenses include
increased water and air permitting fees from the Regional Water Quality Control Board and the
Bay Area Air Quality Management District. Commodity and utility rates to operate the facility
are also increasing with the largest increases in FY2018 for electrical, water, refuse, and storm
rates. Chemical commodity expenses, needed to adjust water quality and meet permit
requirements, are also increasing modestly per latest chemical market conditions and
procurement contract conditions.
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Capital projects, parts, and materials are increasing about 3% to keep up with ongoing
replacement of aging equipment. Larger increase to capital expenses are expected to begin in
FY2020 in the form of new debt service for major projects to implement the Plant’s capital
program. The Plant’s major project in FY2018 will be making progress constructing the Sludge
Dewatering and Truck Loadout Facility, which will allow (in about 2019) the retirement of the
Plant’s two sewage sludge incinerators that have been in operation since 1972.
SECTION 6 B : OPERATIONS
Operations costs include the Customer Service, Distribution Operations, Engineering, and
Allocated Charges categories in Appendix A: Wastewater Collection Financial Forecast Detail.
Debt service, rent, and transfers are also included in this category. Customer Service costs are
primarily related to the call center and collections on delinquent accounts. The Distribution
Operations category includes preventative and corrective maintenance on sewer mains and
laterals, investigation of sewer overflows, regular cleaning of heavily impacted sections of the
sewer system, and services shared with other utilities (such as street restoration and
equipment maintenance). Allocated Charges include the costs of accounting, purchasing, legal,
and other administrative functions provided by the City’s General Fund staff, as well as shared
communications services and Utilities Department administrative overhead and billing system
maintenance costs.
Operations costs are projected to increase by 3% per year, on average, over the forecast period.
Underlying these projections are salary and benefit, consumer price index, and other cost
projections used in the City’s long-range financial forecast.
SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
The Wastewater Collection Utility’s CIP consists of the following programs:
• The Sewer System Replacement/Rehabilitation Program, under which the Wastewater
Collection Utility replaces aging sewer mains.
• Customer Connections, which covers the cost when the Wastewater Collection Utility
installs new services or upgrades existing services at a customer’s request in response
to development or redevelopment. CPAU charges a fee to these customers to cover
the cost of these projects.
• Ongoing Projects, which covers the cost of replacing degraded manholes and sewer
laterals, as well as the cost of capitalized tools and equipment.
The Sewer System Replacement and Rehabilitation Program funds the replacement of
deteriorating sewer mains and projects to increase capacity in various parts of the sewer
system. The sewer system consists of over 217 miles of mains, and CPAU uses a variety of tools
to establish which sections are in need of replacement. Maintenance statistics (such as records
of the location and number of sewer overflows on the system) and videotape of sewer mains
during regular cleaning can reveal areas with large amounts of deteriorating pipe. CPAU uses a
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 18 | Page
scoring system to prioritize which mains to replace first, and coordinates with the Public Works
street maintenance program to avoid cutting into newly repaved streets. A major goal of the
program is to minimize groundwater and rainwater infiltration. As mains deteriorate they
begin to allow groundwater and rainwater to infiltrate the system. Some level of infiltration is
expected on any sewer system, but if there is too much, the combined flow of wastewater and
groundwater/rainwater can overwhelm the capacity of various parts of the sewer system.
Reducing infiltration can reduce the need to expand the system to accommodate increased
flow. To achieve this goal, deteriorating mains are either repaired with a plastic lining or
replaced. CPAU replaces or repairs approximately 25,000 feet of main per year, or 2.5% of the
system.
The CIP program also funds sewer capacity improvements. CPAU uses a hydraulic model, data
from various flow meters on the system, and land use data to identify sections of the system
that are being overloaded. When sewer mains are operating at or above their capacity on a
regular basis it will increase the likelihood of sewer overflows. CPAU also does occasional
comprehensive master planning studies to identify necessary capacity improvements. The most
recent study, in 2004, identified eight projects, three of which have been completed. The
remaining four projects are low priority projects and will be scheduled and planned as the need
arises.
Over the last few years, main replacement costs have been increasing for Wastewater as well
as the Gas and Water utilities. The replacement cost per linear foot has increased by between
25 and 50% in some cases. Several factors may be contributing to this. Economic recovery in
the Bay Area, as well as a greater focus on infrastructure improvement by many municipal
agencies and utilities could be creating high demand for contractors in this field. There may be
ongoing greater costs for newer, more leak resistant pipe materials. Should these trends prove
to be less than short-term phenomena, wastewater main replacement budgets may need to be
increased by $1.5 to $1.7 million more per year to maintain the current pace of replacement.
This increase in cost is a partial reason for the two year delay in projects. The most recent
project, when put out for bid, resulted in very few contractors competing, and project bids
larger than budgeted. Staff will redesign this and future projects into smaller segments to keep
budgets lower, while not compromising on overall system integrity. The other reason for delay
is the University Avenue Business District project, and getting coordination amongst all
departments is taking more time than expected. Finally, there has been an ongoing issue with
keeping and maintaining qualified staff to design and work on projects.
Customer Connections costs are projected to increase steadily by around 3% each year through
the end of the forecast period. Actual expenses for these projects fluctuate annually depending
on how many defective laterals and manholes are discovered during routine maintenance, as
well as how much development and redevelopment is going on that prompts the replacement
or upgrade of sewer laterals. It is worth noting that property owners pay a fee for sewer lateral
replacement or expansion during redevelopment, so when the number of projects increases, so
does fee revenue.
Projected CIP spending is displayed in Table 10 for the 5-year financial forecast period.
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Table 9: Projected CIP Spending
Aside from Customer Connections, the CIP plan for FY 2018 to FY 2022 is funded by sewer rates
and capacity fees. The details of the plan are shown in Appendix B: Wastewater Collection
Utility Capital Improvement Program (CIP) Detail.
SECTION 6 D : DEBT SERVICE
The Wastewater Collection Utility currently pays its share of one bond issuance, the 1999 Utility
Revenue Bonds, Series A, which is due to be retired in 2024. This $17.7 million issuance
refinanced various earlier Storm Drain, Wastewater Treatment, and Wastewater Collection
Utility bond issuances. The Wastewater Collection Utility’s share of the issuance was roughly
$1.9 million. This amount represented the second refinancing of the remaining principal of a
1990 bond issuance which itself was a refinancing of a 1985 issuance that financed a variety of
improvements to the sewer system. The cost of debt service for the Wastewater Collection
Utility’s share of this bond issuance for the financial forecast period is roughly $128,000 per
year as shown in Table 11 below.
Table 10: Wastewater Collection Utility Debt Service ($000)
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
1999 Utility Revenue Bonds, Series A 128 128 128 129 129 129
The 1999 Utility Revenue Bonds include two covenants stating that 1) the Wastewater
Collection Utility will maintain a debt coverage ratio of 125% of debt service, and 2) that the
City will maintain “Available Reserves”8 equal to five times the annual debt service. The current
financial plan maintains compliance with both covenants throughout the forecast period.
Compliance with covenant one is shown below in Table 12, below. Due to the small size of the
annual debt service payment for these bonds, the Wastewater Collection Utility’s Operations
Reserve alone more than satisfies the second covenant at more than 30 times annual debt
service throughout the forecast period.
8 Available Reserves as defined in the 1999 Utility Revenue Bonds included reserves for the Water, Wastewater
Treatment, Wastewater Collection, Refuse, Storm Drain, Electric, and Gas Utilities
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 20 | Page
Table 11: Debt Service Coverage Ratio ($000)
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Revenues 19,042 19,170 20,381 21,787 23,112 24,611
Expenses (Excl. CIP
and Debt Service) -15,869 -16,146 -16,713 -17,709 -18,717 -19,343
Net Revenues 3,173 3,024 3,668 4,078 4,395 5,268
Debt Service 128 128 128 128 129 129
Coverage Ratio 2479% 2363% 2866% 3186% 3407% 4084%
The Wastewater Collection Utility’s reserves (but not its net revenues) are also considered
security for the Storm Drain and Wastewater Treatment Utilities’ shares of the debt service on
the 1999 bonds. Throughout the term of the bonds there remains a small risk that the
Wastewater Collection Utility’s reserves could be called upon to make a debt service payment
on behalf of one of those utilities if it cannot meet its debt service obligations. Staff does not
foresee this occurring based on the current financial condition of those utilities. If the
Wastewater Collection Utility’s reserves were used this way, any amounts advanced would
have to be repaid by the borrowing utility.
One other bond series is secured by the net revenues (but not the reserves) of the Wastewater
Collection Utility. The 1995 Series A Utility Revenue Bonds issued for the Storm Drain utility
was secured by the net revenues of the City’s “Enterprise,” which was defined as the City’s
water, gas, wastewater, storm drain, and electric utilities, and are senior to the 1999 bonds
referenced above. Debt service payments of roughly $680,000 per year are made on the 1995
Series A bonds by the City’s Storm Drain Utility, and staff does not currently foresee any risk of
that utility being unable to make payment.
SECTION 6 E : OTHER REVENUES
The utility has seen substantial increases in connection and capacity fee revenues in recent
years, offsetting the need for increased sales revenue in the past, and these are assumed to
continue, albeit slightly reduced from current levels. Income from interest and transfers in are
projected to remain steady through the forecast horizon.
SECTION 7 : COMMUNICATIONS PLAN
The FY 2017 Wastewater Collection Utility communications strategy covers three primary areas:
rates, maintenance and operations, and safety. Communication about wastewater rate
adjustments will highlight the important infrastructure and operations upgrades that are
occurring at the Regional Water Quality Control Plant to improve wastewater collection utility
services. To keep customers apprised of the status and accomplishments of CIP projects, a
network of project web pages are maintained and updated as needed. Traffic is driven to the
website via ads in newspapers and local publications, utility bill inserts, social media and email
newsletters.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 21 | Page
An important communications topic for the wastewater utility is avoiding sewer back-ups due
to FOG (fats, oil and grease) and trash being dumped down drains and toilets. Safety topics are
emphasized year-round. Staff continues its outreach goal of educating customers about the
utility’s gas-sewer line cross-bore inspection program, including the importance of calling
Utilities prior to clearing sewer lines in the event of a sewer back-up.
Promotional activity about wastewater utility maintenance and safety operations includes use
of bill inserts, ads in local print publications, website pages, email newsletters and social
media. While print materials and website pages feature prominently, CPAU is increasing the
outreach emphasis on more direct communication with customers, including through use of
social media, email newsletters, digital ads, videos and short commercials on the local
television channels. Staff is also attending more community safety/emergency preparation
events and neighborhood meetings.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 22 | Page
APPENDICES
Appendix A: Wastewater Collection Financial Forecast Detail
Appendix B: Wastewater Collection Utility Capital Improvement Program (CIP) Detail
Appendix C: Wastewater Collection Utility Reserves Management Practices
Appendix D: Sample of Wastewater Collection Outreach Materials
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 23 | Page
APPENDIX A : WASTEWATER COLLECTION FINANCIAL FORECAST DETAIL
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 24 | Page
APPENDIX B : WASTEWATER COLLECTION UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 25 | Page
APPENDIX C : WASTEWATER COLLECTION UTILITY RESERVES
MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Wastewater
Collection Utility Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY
2015 to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net
Assets as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Reserves
The Wastewater Collection Utility’s Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 3 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 4 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Wastewater Collection
Utility’s Capital Improvement Program (CIP), as described in Section 5 (CIP Reserve)
d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 7 (Operations Reserve)
f) Any funds not included in the other reserves will be considered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 8 (Unassigned Reserves).
Section 3. Reserve for Commitments
At the end of each fiscal year the Reserve for Commitments will be set to an amount equal
to the total remaining spending authority for all contracts in force for the Wastewater
Collection Utility at that time.
Section 4. Reserve for Re-appropriations
At the end of each fiscal year the Reserve for Re-appropriations will be set to an amount
equal to the amount of all remaining capital and non-capital budgets, if any, that will be re-
appropriated to the following fiscal year in accordance with Palo Alto Municipal Code
Section 2.28.090.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 26 | Page
Section 5. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 12 months of budgeted CIP expense
Maximum Level 24 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added or removed from to that reserve
as a result of a change in contractual commitments related to CIP projects. Any other
additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Section 6. Rate Stabilization Reserve
Funds may be added to the Rate Stabilization Reserve by action of the City Council and held
to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate
Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization
Reserve at the end of any fiscal year, any subsequent Wastewater Collection Utility
Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the
Financial Planning Period.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 27 | Page
Section 7. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Wastewater Collection Utility’s Fund Balance not
included in the reserves described in Section 3-Section 6 above will be included in the
Operations Reserve unless this reserve has reached its maximum level as set forth in Section
7(d) below. Staff will manage the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for
that year in the Financial Plan.
Minimum Level 60 days of O&M and commodity expense
Target Level 105 days of O&M and commodity expense
Maximum Level 150 days of O&M and commodity expense
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months
of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Wastewater Collection Utility
shall be designed to return the Operations Reserve to its target level within four years.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Wastewater Collection
Utility’s Fund Balance shall be automatically included in the Unassigned Reserve
described in Section 8, below.
Section 8. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the
Wastewater Collection Utility’s Fund Balance will be held in the Unassigned Reserve. If
there are any funds in the Unassigned Reserve at the end of any fiscal year, the next
Financial Plan presented to the City Council must include a plan to assign them to a specific
purpose or return them to the Wastewater Collection Utility ratepayers by the end of the
first fiscal year of the next Financial Planning Period. For example, if there were funds in the
Unassigned Reserves at the end of FY 2015, and the next Financial Planning Period is
FY 2016 through FY 2020, the Financial Plan shall include a plan to return or assign any
funds in the Unassigned Reserve by the end of FY 2016. Staff may present an alternative
plan that retains these funds or returns them over a longer period of time.
WASTEWATER COLLECTION UTILITY FINANCIAL PLAN
February 2016 28 | Page
APPENDIX D : SAMPLE OF WASTEWATER COLLECTION OUTREACH
MATERIALS
Page 1 of 13
5
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: MARCH 1, 2017
SUBJECT: Utilities Strategic Plan Performance Update (Fiscal Year 2016)
SUMMARY:
This update on implementation of the Utilities Strategic Plan covers the 12-month period from
July 2015 through June 2016. The Council-approved Utilities Strategic Plan, adopted by Council
in 2011 and updated in 2013 and 2015, (Attachment A) uses a Balanced Scorecard concept with
four main perspectives (“Four Perspectives”) with strategic objectives to be achieved for each.
To translate these objectives into plans for action, performance measures were identified for
each objective. A summary of the performance measures and status for each of the Four
Perspectives is shown below:
Internal Business Process Perspective
People & Technology Perspective
Performance Measure Status
Performance Measure Status
Interruption Duration Met
Employee Satisfaction Met
Emergency Response Time Met
Certification & Training Met
Gas Incident Rate Met
Tools & Technologies N/A
Gas Safety Awareness Met
New Technology Evaluation Met
Infrastructure Backlog Not yet met
Call Wait Time Met
Financial Perspective
Billing Adjustments Met
Performance Measure Status
Emergency Notification Met
High Credit Ratings Met
Program Participant Satisfaction Met
Maintain Reserves Not yet met
Competitive Commodity Bids Met
Recover Fixed Charges Met
Unaccounted Gas & Water Met
Full Value from Redwood Gas Met
Customer & Community Perspective
Strategic Initiatives Not yet met
Performance Measure Status
Water Use Reduction per capita Met
Service Restoration Not yet met
Efficiency Achievement N/A
System Interruptions Met
Satisfaction Not yet met
Competitive Bill Met
Rate Change Met
PAG Gas Participation N/A
Greenhouse Gas Reductions N/A
Page 2 of 13
The Balanced Scorecard Performance Measures Result (Attachment B) provides a more detailed
description of the objectives and performance measures within each of the Four Perspectiv es.
The (+) “plus” or (-) “minus” listed after each measure on the chart in Attachment B is an
indicator of the degree to which the measure has been achieved. Where “TBD”, or “to be
determined” is noted, it indicates that staff continues to evaluate benchmark goals for a
performance measure, which must be done prior to assess ing progress towards achieving the
performance measure.
It should be noted that the Four Perspectives are presen ted above, and throughout this report,
in no particular order. They are not arranged in order of importance and no single item is
weighted more heavily than another.
BACKGROUND
On July 18, 2011, the Council approved the 2011 Utilities Strategic Plan (Staff Report #1880). In
implementing the Utilities Strategic Plan, staff regularly reviews the objective measures and
initiatives and recommends any appropriate updates on an annual basis. In addition, on a semi-
annual basis, staff reports progress on implementation of the plan to the UAC and Council.
The Balanced Scorecard tracking methodology was chosen by Staff to assist in performance
measurement and to promote better understanding of the City of Palo Alto Utilities’ (CPAU’s)
strategic business processes. The performance scorecard will evolve over time and respond to
changes in the business climate, with potential new measures added and others mod ified or
completely removed. Utilities managers meet on a regular basis to review the overall Utilities
Strategic Plan and evaluate the strategic objectives, performance measures, and targets, and
strategic initiatives. From time to time, management will recommend changes to keep the
Utilities Strategic Plan aligned with changing environments and priorities.
The Council approved changes to the Performance Measures and Strategic Initiatives of the
Utilities Strategic Plan in August 2013 (Staff Report #3950) and May 2015 (Staff Report #5709).
No additional changes are proposed at this time, in light of the upcoming major update to the
Strategic Plan.
Given the rapid pace of change, emerging issues and technological advancements within the
utility industry in the past several years, Utilities will review and reestablish the department’s
strategic priorities in 2017. Utilities will engage with the UAC, staff and other stakeholders in
updating the strategic plan to ensure it aligns with the communities’ sustainability goals and
addresses emerging issues for utilities of the future, while ensuring safe and reliable services
today.
DISCUSSION
The Four Perspectives used in the Strategic Plan are:
Customer and Community
People and Technology
Finance
Internal Business Processes
Page 3 of 13
Each of the Four Perspectives represents a specific viewpoint and ensures CPAU’s business
activities are aligned with the Strategic Plan. The Customer and Community Perspective
represents customer satisfaction and delivery of services to stakeholders. People and
Technology includes employee training and development as well as keeping pace with
technological advancements in the utilities industry. The Finance Perspective focuses on CPAU
having a strong financial base and delivering cost-effective services. The Internal Business
Processes Perspective covers operational goals and outlines the key processes necessary to
deliver services to customers.
Each of the Four Perspectives of the Utilities Strategic Plan includes strategic initiatives which
are key programs or projects required to achieve one or more objectives and the overall
strategic plan. Many of the original strategic initiatives were completed and eight new ones
were added when Council approved updates to the Strategic Plan in May 2015, resulting in 13
active initiatives. Strategic initiatives aim to significantly change the way CPAU does business,
require significant resources to complete, and have a defined timeline.
A summary of performance under each of the Four Perspectives follows.
CUSTOMER AND COMMUNITY PERSPECTIVE
Four strategic objectives are measured from this perspective: service reliability, customer
satisfaction with CPAU’s responsiveness, competitive bills compared to neighboring
communities and care for the environment. CPAU has achieved three performance measures,
two measures are no longer applicable and measures were not met in these categories.
Performance Measures
Service reliability performance measures:
C1.1 an average restoration time after an outage of 90 minutes or less per interrupted
customer
C1.2 an average number of 0.9 or fewer interruptions per customer per year
CPAU did not meet the target of less than 90 minutes restoration time. The average time to
restore service per interrupted customer for fiscal year 2016 was 165 minutes. There were two
extended outages during this period. The first outage affected 209 households near San
Antonio Road in October 2015. Since the outage occurred around midnight , it took the crews
longer than normal to organize and troubleshoot. It took approximately eight hours to identify
and repair the faulty underground cable. Underground utilities are more difficult to inspect,
diagnose and repair increasing outage times. The second major outage affected 310 households
near Arastradero Road in December 2015. The outage lasted approximately ten hours due to a
failed electrical switch which required replacement. CPAU experienced 26 total outages in
fiscal year 2016, which is seven more outages experienced in fiscal year 2015 (19 total outages).
In addition to specific conditions that may be unique to each outage, aging infrastructure and
crew member staffing and retention may continue to present challenges for CPAU to improve
its restoration times in the near term. Even though restoration time was longer than
Page 4 of 13
anticipated, CPAU’s performance measurement for average interruptions per customer of 0.24
is well below the top quartile of industry standard of 0.9 interruptions per customer.
Customer satisfaction performance measure:
C2.0 to be rated 85% or higher in overall customer satisfaction
In 2016, RKS Research and Consulting conducted a residential electric utility customer
satisfaction survey. Even though CPAU fell slightly short of the target of 85% or above in
customer satisfaction, the overall results were positive and CPAU have trended upward in
customer satisfaction with reliability, cost and concern for the environment compared to other
RKS surveys. The average overall satisfaction score for CPAU electric residential customer was
82% which is significantly higher than the statewide municipal average of 71%. CPAU’s image
on “concern for the environment” is first rate. This is reinforced by the survey when customers
were asked whether they were willing to pay slightly more for carbon offsets, the supporters
outnumbered opponents by about 2:1. CPAU also stood out in its customers’ support for
having a municipally owned utility. A majority of the customers saw “great benefit” resulting
from the City having its own utility. Approximately 75% of the customers a lso believed they
would be worse off in reliability, customer service and cost of electricity if the utility was
investor-owned.
Customer paying a reasonable bill performance measures:
C3.1 residential bill is less than the average bills in neighboring communities
C3.2 rate increases are less than 10% (electric, gas, wastewater) and 20% (water)
CPAU met both “reasonable bill” performance targets. The total average residential bill
including electric, gas, water and wastewater services in Palo Alto was $188.04, which is 8.9%
below the average bill of $204.86 in neighboring jurisdictions (i.e. Menlo Park, Mountain View,
Santa Clara and Redwood City). CPAU’s bill for electric (<50%), gas (<31%) and wastewater
(<48%) are below the average of neighboring cities; however, CPAU’s water bill is 27% higher
and represents the largest portion of the total utility bill (40%).
CPAU also met the performance measure of a “less than 10%” rate increase for electric, gas,
and wastewater and a “less than 20%” rate increase for water. For FY 2016, CPAU increased
rates for water and wastewater services by 12 % and 9% respectively. CPAU did not
recommend any rate adjustments for electric and gas services.
PaloAltoGreen Gas performance measures:
C4.1 20% of customer participation
C4.2 10% greenhouse gas reductions
The PaloAltoGreen Gas (PAGG) program is scheduled to be terminated at the end of FY 2017 in
anticipation of the newly adopted Carbon Neutral Gas Plan. Council approved the Carbon
Neutral Gas Plan (staff report #7441), enabling the City to achieve a carbon-neutral gas supply
portfolio starting in FY 2018 with a rate impact not to exceed ten cents per therm. CPAU is in
Page 5 of 13
the process of developing an implementation plan for the Carbon Neutral Gas Plan to
eliminate/offset greenhouse gas emissions associated with their natural gas use.
Prior to PAGG termination, approximately 900 customers including all City facilities were
enrolled in the program. As a result of PAGG, there was a 6% or 9,000 metric tonnes reduction
in greenhouse gas emissions in FY 2016. CPAU will eliminate and/or replace these performance
measures in the next strategic plan update.
Strategic Initiatives
Under the Customer and Community perspective there are three strategic initiatives.
1. To establish more mechanisms for eliciting feedback from customers. CPAU conducts
annual or bi-annual customer surveys through independent research companies, which
allow customers to rate their satisfaction and value of the utility services they receive.
Customers are asked to provide written feedback via paper and online surveys after
participation in events and workshops. The CPAU website encourages the public to contact
CPAU by phone or email at any time to provide feedback or ask questions, and CPAU’s
communication with customers via social media channels has grown considerably over the
past few years. Staff is currently in the process of developing new customer feedback cards
that can be placed at key public-facing locations such as Customer Service counters and
carried with Field Service, Meter Reading, Engineering and Maintenance employees while in
the field. In addition to customer surveys, CPAU Communications staff are exploring ways to
record feedback through a more formal process that will allow CPAU to report out on
general customer satisfaction, deliver praise for employees and use critical, constructive
feedback in an effort to continually improve upon the services we offer the community.
Additionally, as part of the billing system improvements and redesign of the My Utilities
Account web portal, we hope to include a user’s feedback mechanism to make it easier for
users to give us feedback.
2. Improving the electronic bill presentment, payment functionality, and enhancing the
utility’s online capabilities. The Information Technology and Utilities departments deployed
an interactive voice response (IVR) system to enhance CPAU’s customer service call center
operations and provide 24x7 communication and payment options to customers. Some of
the IVR features include retrieval of outstanding account balance and payment history,
payment by credit card, and customer satisfaction survey. Thus far, 12% of total customer
calls have been diverted to the IVR system to transact business instead of requesting for
assistance from a customer service representative. CPAU is also embarking on a new
customer service online portal. CPAU issued a request for proposal (RFP) in 2016 for the
next generation customer portal (My Utilities Account 2.0). The new customer portal will
provide customers a more user friendly and mobile experience. Some of the new features
include rate calculator, notification alerts, recurring payments, e-billing and meter self
reads. The new customer portal is tentatively scheduled to be rolled out in early 2018.
3. Reevaluate the cost-effectiveness of fuel switching especially for new construction and
evaluate whether new programs or incentives should be offered, consistent with all
Page 6 of 13
applicable legal requirements. On August 2015, City Council approved a ten-point work
plan to evaluate and implement greenhouse gas reduction strategies by reducing natural
gas and gasoline use through electrification measures related to electric vehicles, and
electric heat-pump based technologies to replace water and space heating appliances in the
community. The work plan consists of two phases over a five year period. The first phase is
already underway which will determine the scope of the analysis and identify any staff
and/or consulting resources required to complete it. Phase I will contain additional
information to inform Council’s decisions about whether to pursue or not pursue those
actions related to fuel switching either identified initially in the Colleagues Memo or in the
Phase I analysis. The second phase will involve detailed analysis of proposed actions and
measures identified in the first phase and the development of an implementation plan.
Staff will provide UAC an update of phase one in March 2017.
PEOPLE AND TECHNOLOGY PERSPECTIVE
CPAU measures its success in attracting and retaining of employees, training and development,
and implementation and evaluation of technologies. So far, CPAU has successfully reached
three of four performance measures in these categories. Staff has not been able to identify a
consistent and reliable metric for the tools & technologies performance measure.
Performance Measures
Employee attraction and retention performance measure:
PT1.0 Improvement from prior year’s employee satisfaction survey
In the FY 2016 CPAU employee survey, there were 137 participants or a 60% response rate
which is the highest response rate since we began the surveys in FY2012. The survey provided
CPAU a better understanding of employee priorities, satisfaction and engagement within the
organization. 71% of the employees reported either being “very satisfied” or “satisfied”
compared to 62% in FY 2015.
Most employees agree that CPAU generally develops and promotes employees from within the
department. In addition, managers are actively engaged with employees in their career
development. However, CPAU received lower marks for employee retention, length of time to
fill vacancies, and transparency for advancement opportunities in certain workgroups.
Management will collaborate with HR to identify and rectify some of these shortcomings over
the upcoming year. As part of the citywide professional development and succession planning
effort, the City will continue to seek academies and classes to improve skills and knowledge and
implement cross training programs.
Training and development performance measure:
PT2.0 100% of Operations personnel have the appropriate certification and training for
their assigned work area
CPAU is committed to provide ongoing training and development for all emplo yees to ensure
safety and best practices are implemented in each CPAU employee’s current job. CPAU met its
performance target of having 100% of Operations personnel with the appropriate certification
Page 7 of 13
and training required for working in their assigned are as to fulfill annual and periodic
requirements to comply with various mandated State of California regulations. In January,
Operations rolled out an on-line training system that complies with CAL/OSHA requirements
and also addresses the unique Utilities related field safety requirements. The new system
allows the department flexibility to structure trainings for staff as needed rather than restricted
to costly one-time on-site sessions. Additionally, Operations has a few staff who are
Operational Qualification certified by the Department of Transportation to proctor the
classroom training sessions.
Ensuring workgroups have necessary tools and technologies performance measure target:
PT3.0 Employees have adequate tools and technologies to perform their jobs
Even though CPAU has not been able to identify a consistent and reliable metric to measure
employees’ tools and technologies, the City and department continue to seek and add new
solutions to assist employees with their work and improve operational efficiencies. The
Information Technology Department rolled out Microsoft Office 365 to all City staff. Office 365
enables staff to access files, share documents, and collaborate with colleagues from wherever
they are and across multiple devices. Documents created in Word, Excel or PowerPoint and
saved on OneDrive can be opened and edited on personal devices or a browser. Collaborating
with colleagues is easier with co-authoring, which helps one cut through the complexity of
managing feedback and versions from multiple people. Under a shared document, one can see
what others are typing and negotiate changes in real-time. In addition, CPAU has issued an RFP
to track emergency equipment and excess inventory outside of the City’s warehouse. With the
use of bar code scanning on a mobile phone or tablet, this will provide staff efficiencies in
complying with City inventory policies. The vendor software includes mobile enabled
applications to capture data in the field. The anticipation is that after the inventory
implementation, CPAU can expand the mobile applications to include data collection of
necessary work details while crews are in the field and integration with the ERP system. Finally,
the City has embraced digital signatures as an acceptable replacement for wet signatures on
official and non-official documents. CPAU has identified several customer service documents
that can be converted and incorporated with an internal workflow through DocuSign, allowing
Customer Service staff to quickly respond to and efficiently process customer applications.
Evaluation of new technologies performance measure target:
PT4.0 Evaluate at least three new technologies per year
CPAU’s Program for Emerging Technologies, or PET, (www.cityofpaloalto.org/UTLInnovation)
provides the opportunity for local businesses and organizations to submit proposals for
innovative and impactful products to CPAU for review as a prospective partner. The goal is to
find and nurture creative products and services that will manage and better use elec tricity, gas,
water and fiber optic services. In FY 2016, CPAU met the performance measure by evaluating
14 applications, of which, five were approved and five are pending review. Three of the five
approved projects were letters of support from CPAU for federal funding to develop prototype
applications. The projects are in support of solar water heating, community solar, and power
measurement of the electrical distribution system. Another approved project was
Page 8 of 13
establishment of an Advanced Distribution Management System (ADMS) testbed. The testbed
will accelerate development and adoption of ADMS applications to optimize the performance
of the distribution grid. The fifth project was an integrated energy storage system for
residential and small commercial customers. The energy storage system will serve as a power
backup supply and contribute to CPAU’s demand response program.
Strategic Initiatives
There are two strategic initiatives under the People and Technology perspective.
1. Update the five year department-wide succession plan. Public agencies including
utilities across the nation are facing a retirement wave and anticipate losing 35 to 50
percent of their workforce within the next five years. Recruiting and retaining qualified
personnel (92 percent), succession planning (80 percent), and staff development (79
percent) are ranked as the most important issues for the second year in a row by state
and local government human resources managers.1 This creates not only a challenge but
also offers an opportunity for our employees to grow in knowledge and advance
through the organization.
As part of professional development and succession planning, the City hosted a
leadership academy to teach fundamentals of supervision and leadership. 30 CPAU
employees across all divisions (Administration, Customer Support, Engineering,
Operations and Resource Management) participated and graduated from the academy.
The academy consisted of 10 modules covering communication, decision-making,
training, team-building, establishing expectations and management of change, time and
stress. The City received positive feedback and reinforcement techniques from the
participants and management. The City will continue to seek other leadership training
opportunities and host another academy in 2017.
2. Develop a Utilities-specific smart grid and IT strategic plan. CPAU is in the process of re-
evaluating the feasibility of an Advanced Metering Infrastructure (AMI) system and
associated smart grid technologies and programs. The prior 2012 smart grid assessment
recommended CPAU undertake pilot scale smart grid projects and defer major
investments in smart grid for several years. After implementing pilot scale projects over
the past several years, the City has released an RFP in 2016 for consulting services to
develop a smart grid/AMI business case and Utilities IT strategic roadmap. The
consultant will perform cost benefit analysis including capital costs, life of capital
equipment, recurring expenses, cost savings, system reliability, operational efficiencies
and customer benefits as part of the AMI business case. Under the IT strategic
roadmap, the consultant will identify technology trends in the market place and develop
a 10 year technology roadmap that includes prioritization of technology projects,
resource requirements, estimated one-time and recurring project costs, and
1 “Survey Findings – State and Local Government Workforce: 2016 Trends” by Center for State & Local Government Excellence,
available at: http://slge.org/wp-content/uploads/2016/05/State-and-Local-Government-Workforce-2016-Trends.pdf
Page 9 of 13
implementation timeline. Staff plans to present the findings and recommendations of
the AMI business case and technology roadmap to the UAC by end of 2017.
FINANCIAL PERSPECTIVE
Under this perspective, the performance measures involve maintaining financial strength,
designing rate structures that balance costs of service with the promotion of conservation and
providing an investment return to the community. CPAU has met 2 of 3 performance goals
under this perspective.
Performance Measures
High credit rating performance measure target :
F1.1 At least AA by Standard and Poor’s (S&P)
F1.2 At least Aa3 by Moody’s
The City maintains S&P’s highest credit rating, Triple A, for the 1999 utility revenue bond, 2007
Clean Energy Renewable bond, 2009 water revenue bond and 2011 utility revenue bond. The
2011 utility revenue bond was refinancing of the 2002 revenue bonds for water and gas
utilities. S&P cited the following factors in conferring the AAA rating: 1) very strong historical
and projected debt service coverage; 2) extremely strong cash balances and strong reserve
policies; 3) low debt levels, with capital needs to be funded on a pay-as-you-go basis and 4)
strong economic base with very high income levels.
Maintain adequate Operations Reserve levels for all utilities performance measure target:
F2.0 Within guidelines in Council-adopted long-term financial plans
The Gas, Wastewater Collection and Water Funds either met or exceeded the minimum
guidelines in June 2016 and short-term risk assessment level. The Electric Fund was slightly
below the minimum guideline level due to a combination of higher costs and lower revenues.
As a result of the extended drought, hydroelectric resources were lower than average. The City
had to purchase additional higher-priced energy in the markets. In addition, customer sales
was 1% lower than expected. Electricity consumption has declined slowly as a result of a
continuing focus on energy efficiency, as well as the adoption of more stringent appliance
efficiency standards and energy standards in building codes. CPAU had to increase overall
electric rates by 11% in FY 2017 to offset increasing costs and bring reserves back within the
guidelines.
Strategic Initiatives
There is one strategic initiative under the financial perspective.
1. Complete Electric cost of service analysis (COSA) by end of CY 2015. – Completed
The City completed the electric COSA in 2016 (the previous electric COSA was updated
in 2007). The primary goal of the COSA was to ensure costs are allocated equitably
among customers and rate designs are cost of service-based and in alignment with
Council guidelines. As a result of the COSA, there were several design changes to ensure
Page 10 of 13
rates were aligned to the cost of serving customers. The number of tiers was reduced
from three to two for the residential rate because two tiers were required to capture
differences in commodity costs and seasonal capacity needs, instead of three. A
minimum charge was added to all rate classes to recover the minimum direct costs of
customer service, metering, and billing. The municipal rate class was repealed because
it shared similar characteristics to other non-residential classes. The cost of electricity
and operational expenses of streetlights and traffic signals were transferred from the
Electric Fund to the General Fund in alignment with cost of service principles as well.
UTILITIES INTERNAL BUSINESS PROCESS PERSPECTIVE
The largest number of performance measure targets fall under this perspective. Twelve were
met, two were not met and one was unavailable.
Performance Measures
The targets for the following measures were met, including:
BP1.1 Restore electrical power in less than 60 minutes
BP1.2 Respond to emergency calls in less than 30 minutes
BP2.1 Zero reportable gas incidents
BP2.2 Customer gas safety awareness of 90% or higher
BP4.1 Average phone wait time of less than 90 seconds
BP4.2 Number of billing adjustments of less than 2,958
BP5.0 Reporting significant outages within 30 minutes
BP6.0 Customers satisfaction of 90% or higher with program experiences
BP7.0 Minimum of 3 competitive bids for each electric fixed-price purchase transaction
BP8.0 Reduce lost and unaccountable volumes of gas and water
BP9.0 100% of full value received from Redwood gas pipeline
BP11.0 Meet the state’s 20% per capita water use reduction by 2020
One of the performance measures was not updated because data were not yet available. This
measure will be updated in the next annual report. The energy efficiency achievements for
FY 2016 will not be available until the second quarter of FY 2017.
BP12.0 Meet energy efficiency achievement goals
The following measures were not met:
BP3.0 Zero backlog of infrastructures beyond their useful lives
Replacing aging infrastructure plays an important role in being able to provide a safe
and reliable distribution. Electric replacement of aging infrastructure , in particular
rebuild of underground districts, has been delayed over the last several years due to
staffing shortages in Engineering and Operations and increasing customer requests.
Due to challenges in hiring qualified employees, CPAU has either executed or is
evaluating short-term contracts with construction and engineering firms to bring the
backlog to a manageable level. The Gas utility has zero backlog and is currently up to
date with gas main replacement projects. The Water Reservoir Coating Improvement
and Seismic Upgrade projects have been temporarily suspended due to associated
Page 11 of 13
escalating costs and new findings of the reservoirs. Staff will conduct an overall water
system study to determine if the City’s emergency water storage and supplies can be
reconfigured and whether the reservoir(s) require replacement. The Wastewater utility
will complete Sewer System Rehabilitation (SSR) / Augmentation Project 24/25/26 in
2017. Capital Improvement project SSR 24/25 was delayed because of unexpectedly
high bid proposals. Unexpected high costs were attributed to increased labor rates and
material prices on high-density polyethylene main pipes. As a result, CPAU had to revise
the scope and re-issue a new bid for SSR 24/25/26 in order to stay within the project
budget. The final bid came in at 2% below estimate as opposed to 20% above estimate
from the original bid.
BP10.0 100% of strategic initiatives completed
This performance measure has not yet been met. Strategic initiatives are specific
programs or projects required to achieve key objectives in the overall strategic plan.
Strategic initiatives are updated and re-prioritized as business needs change over time.
When the strategic plan was developed in 2011, CPAU identified 17 initiatives. Since
then, 13 of the initial 17 initiatives have been completed including redesign of
PaloAltoGreen, reassessment of gas laddering strategy, development of
communications plan, implementation of new technologies program and reevaluation
of Calaveras Reserves. Nine new initiatives have been added to the strategic plan and
four them have been completed including evaluation of fuel -switching, infrastructure
master studies, new financial policies and completion of the electric COSA. Staff may
propose to replace or add new initiatives in future updates.
Strategic Initiatives
Below are updates of four strategic initiatives for the internal business process perspective.
1. Develop a plan to complete a new electric transmission interconnection . The City continues
to have ongoing discussions with Stanford, SLAC National Accelerator Laboratory (SLAC), the
Department of Energy (DOE), Pacific Gas and Electric (PG&E), and the California
Independent System Operator to evaluate alternative transmission connections. The
proposed 60 kilovolt (kV) transmission line would provide an interconnection between two
existing corridors – the 230kV line in west serving SLAC and the 115kV line in the east
serving the City. The new 60kV would provide SLAC, Stanford and the City transmission
service reliability improvements and potential cost savings. Even though the feasibility
studies to date have indicated the proposed interconnection feasible, would strengthen the
local transmission system, could improve power quality, and could provide for the
participants’ current and forecasted electric load, much work remains to move this project
forward. Additional joint evaluation of various issues, including, but not limited to, the
method by which the City can provide electric transmission service to Stanford; land use
and environmental analysis under the California Environmental Quality Act (CEQA); siting
issues and easement acquisition; and possibly the negotiation of separate agreements with
other parties such as PG&E, the Western Area Power Administration (WAPA), and the DOE.
There is an alternative to the SLAC 230kV connection that will provide redundant
Page 12 of 13
transmission service to the City. The alternative is a PG&E project that would connect the
Adobe Creek Substation near San Antonio Road with PG&E’s Ames Substation in Mountain
View. Although the PG&E alternative would provide the redundant service and come at
minimal cost to the City, it does not provide the same level of local system benefits or offer
the opportunity for the City to avoid any transmission access charges. This alternative has
been proposed by PG&E to the California Independent System Operator and is currently on
hold pending the results of the City’s negotiations on the SLAC project.
2. Update the Water Integrated Resource Plan (WIRP) including a comprehensive evaluation of
the use of groundwater by end of CY 2015. The WIRP is a roadmap for the City of Palo
Alto’s future potable water supply. CPAU updated the WIRP guidelines in January 2017.
The following potable water supply alternatives were evaluated: 1) water from the San
Francisco Public Utilities Commission (SFPUC); 2) groundwater (with or without
groundwater recharge); 3) treated water from the Santa Clara Valley Water District
(SCVWD); and 4) Demand Side Management (DSM). The evaluation concluded that DSM is
the best resource, but potable water supplies are still needed. While SFPUC water is more
expensive, it has higher water quality than groundwater or treated water from the SCVWD.
In addition, groundwater and SCVWD treated water supplies may increase in cost and aren’t
likely to offer additional protection in droughts. The 2017 WIRP guidelines were approved
by UAC in January 2017 and scheduled for Council approval in March 2017. Recycled water
is being evaluated outside of the WIRP in the Recycled Wat er Strategic Plan process that will
include an evaluation of direct and indirect potable reuse as well as the feasibility and
advisability of expanding the existing non-potable recycled water distribution system. The
WIRP will be updated again in a couple years after the recycled water strategic plan is
completed.
3. Participate actively in Northern California Power Agency’s (NCPA) on-going allocation of
cost, including new cost allocation studies if undertaken, to ensure that the City’s costs are
fair. CPAU staff continues to actively participate in studies and efforts to allocate costs to
Palo Alto and its other members as part of the annual budget process. Additionally, CPAU
staff has been assigned to an NCPA committee to review how to best allocate new r evenues
coming into NCPA as a result of expansion services to non -NCPA members. This effort may
lead to a reduction of Palo Alto’s share of costs at NCPA. CPAU continues to evaluate
alternative scheduling service providers for its renewable energy contracts. Staff will assess
the merits of acquiring scheduling coordination services from an entity other than NCPA
including the impacts on current CPAU staff. A recommendation is expected to be made
during the FY 2018 timeframe.
4. Complete environmental impact report (EIR) and financial plan for expanding recycled
water system. The Final EIR to expand the recycled water distribution system to serve non -
potable uses in Palo Alto, including the Stanford Research Park, was certified by Council on
September 28, 2015 (Staff Report #5962). Palo Alto and the Santa Clara Valley Water
district have embarked on a project to initiate preliminary design of the recycled water
distribution system expansion and develop a business plan to confirm the economic
feasibility of constructing the pipeline. The work is expected to be completed in FY18.
ATTACHMENTS:
A. 2011 Utilities Strategic Plan (as updated by Council in September 2015)
B. Balanced Scorecard Performance Measure Results
PREPARED BY: ~"\. DAVE YUAN, Strategic Business Manager
REVIEWED BY: DEAN BATCHELOR, Chief Operating Officer
CJ~ APPROVED BY:
EDSHIKADA
General Manager of Utilities
Page 13of13
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
1
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
Customer and Community Perspective
C1. “I receive
safe and reliable
service.”
Customers expect that Utilities services are provided on a continuous basis,
without interruption. In addition, customers expect that the Utilities
delivery systems are safe and will not harm them or put them in any danger.
We will listen to our customers and seek to understand their reliability and
safety concerns and implement programs and projects to address them.
Average time to
restore service per
interrupted
customer
Less than 90
minutes
Number of electric
system interruptions
per year for average
customer
Ranks in the top
quartile
nationwide (less
than 0.9)
C2. “Be
responsive to all
my utilities‐
related service
needs.”
We understand that the customer wants clear, accurate bills with easy
methods of payment; access to usage history and enough understanding to
efficiently manage usage; to feel quickly and completely “taken care of”
when they have concerns, questions or requests and to be communicated
with effectively both as individuals and as CPAU’s owners. One of the ways
to achieve this is to elicit feedback from customers to help improve service.
Customer
satisfaction scores
on annual surveys
for overall value.
Residential and
commercial surveys
alternate every other
year.
Ranking in the top
two utilities
statewide
Establish
mechanisms to
elicit customer
feedback on their
satisfaction with
all interactions
with CPAU.
C3. “I expect to
pay a reasonable
bill”
We understand that customers expect their bills to be comparable to those
in surrounding communities and do not expect to pay more than PG&E
customers. Customers believe it is reasonable to pay slightly more in
exchange for increased reliability, safety and protection of the environment.
However, customers’ overall bills for Utilities services must remain
reasonable and be reasonably stable and should not increase significantly in
any one year. Customers also want their bills to provide useful information
about their consumption of resources in addition to the rate so that they can
The average
combined residential
customer bill for
electricity, water,
gas, and wastewater
services
Less than the
average of bills for
comparable
services in nearby
communities (MP,
MV, SC, Hayward,
RC, Roseville, and
Alameda).
Improve the
electronic bill
presentment,
payment
functionality and
enhance the
utility’s online
capabilities.
ATTACHMENT A
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
2
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
understand how they can influence their total cost for Utilities services. For
natural gas service, Palo Alto’s supply cost has been relatively stable due to a
laddered gas portfolio purchasing strategy; however, this strategy needs to
be re‐evaluated as gas prices are currently low and are projected to stay low
for the foreseeable future. Although, the average bill for all services should
be comparable to those in surrounding communities, staff will continue to
monitor and report the bills for each service separately on a quarterly basis.
Annual rate change Maximum of 10%
per year for
electric and
wastewater
services.
Maximum of 20%
per year for water
service.
C4. “Care for
our
environment”
Our community wants its customer‐owned utility to offer choices for them
to manage their resource use in ways that reflect their environmental
values. Utilities will improve existing programs and develop new programs
to meet customer needs and allow customers to manage their own
environmental footprint.
Percentage of
customers
participating in the
PaloAltoGreen Gas
program
20% of customers
Re‐evaluate the
cost‐effectiveness
of electrification
especially for new
construction and
evaluate whether
new programs or
incentives can or
should be offered,
consistent with all
applicable legal
requirements.
Percentage of
Greenhouse gas
reductions
10% GHG
reductions
Internal Business Process Perspective
Safety and Reliability
BP1. Ensure a
reliable supply of
utility resources
We will implement strategies that ensure the reliable supply of utility
resources to meet present and future needs. To provide opportunities for
economic development within Palo Alto, we must provide sufficient
resources that meet the short and long‐term needs of our customers. To
achieve this we will maintain the utility system components, and provide for
Duration of electric
system interruption
per year for average
customer
Ranks in the top
quartile
nationwide (less
than 60 minutes
per customer)
Develop a plan to
complete a new
electric
transmission
interconnection.
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
3
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
adequate utility resource supplies to our current and future customers. We
will also develop new management practices and organizational structure to
ensure compliance with regulatory requirements.
Response time to all
emergency calls
Under 30 minutes Complete the
Water Integrated
Resource Plan
(WIRP) including a
comprehensive
evaluation of the
use of
groundwater by
end of CY 2015.
BP2. Operate
the utility
systems safely
We will continue to ensure the safety of our customers, employees and the
community by the ongoing implementation of a safety programs. Protecting
customers and employees from injury and customer’s property from
damage is essential for delivering quality utility services to our customers.
The safety programs will be implemented by updating safety procedures,
educating customers via outreach materials and workshops, correcting
system deficiencies, operating in accordance with existing safety rules, and
ensuring that products delivered to customers are safe.
AGA (American Gas
Association)
Incidence Rate
Zero reportable
incidents
Customer awareness
of gas safety issues
90% of customers
responding to
annual gas
customer safety
awareness survey
BP3. Replace
infrastructure
before the end
of its useful life
We will continue to implement a long‐term strategy for replacing
infrastructure before the end of its useful life. Reliable delivery of utility
services to our customers is critical for the success of business and the
quality of life for our residents. To accomplish this, we will focus on
reducing any backlog of infrastructure work and replace infrastructure
systems in a manner that spreads the expense across multiple years
resulting in program with even expenditures patterns in future years when
possible.
Backlog of
infrastructure
elements whose
ages are beyond
their useful lives.
Zero Complete long
range Gas and
Water master
infrastructure
plans by end of
CY2015.
Customer Service Excellence
BP4. Serve
customers
promptly and
We will provide customers with the highly responsive service they desire.
We will do this by reviewing and improving our processes for managing
accounts, handling payments, resolving billing issues, responding to
Average phone wait
time
Less than 90
seconds
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
4
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
completely information and field service requests and notifying customers during
service disruptions. We will identify ways to streamline these processes and
implement changes. Specifically, we will review, document and improve
business processes that have been identified as having long customer
response times.
Number of billing
adjustments
10% reduction
from number in
2009.
BP5. Communic
ate clearly and
pro‐actively with
all our
stakeholders
We will proactively communicate with all our stakeholders, including all
customer groups, civic leaders, community groups and the press. To achieve
this objective we will provide the information needed for our stakeholders
to effectively access, understand and utilize all utilities services and
programs. In addition, we will design communication vehicles and
dissemination processes that will enable our residents to be educated
owners of their municipal utilities system.
Time until informing
the public and local
media of a disruption
affecting all sensitive
major customers
Less than 60
minutes after
becoming aware
of a disruption
BP6. Offer
programs to
meet the needs
of customers
and the
community
We will assist customers to lower their cost of utilities services and support
the environment. We will assist customers facing economic hardship by
offering bill payment assistance programs. We will educate customers on
the reasons for and their means of compliance with our safety and
regulatory requirements. We will also identify all customer groups, identify
any gaps in service provision to those customers, and propose new
programs or changes to existing programs to close those gaps.
Participant*
satisfaction with
Utilities programs
(*rebate recipients,
workshop attendees,
callers, etc.)
At least 90% of
program
participants
satisfied with their
experience
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
5
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
Reduce Costs
BP7. Negotiate
supply contracts
to minimize
financial risk
We will continue to negotiate supply contracts to acquire supply resources
while managing supply portfolio cost uncertainty to meet rate and reserve
objectives and following sound risk management practices. To ensure that
we are buying commodities at as competitive prices as possible, we will
negotiate contracts with new counterparties to continue to have a sufficient
set of credit‐worthy trading partners. We will continue to develop long‐
term acquisition policies and plans (LEAP) and update those plans at least
every three years. We will also determine all that is necessary to execute a
gas prepay transaction as that is one clear way to lower the cost of gas
supply resources.
Number of
competitive bids
received for each
fixed‐price
transaction.
Minimum of three
bids for electric
power
Participate
actively in
Northern
California Power
Agency’s (NCPA)
on‐going
allocation of cost,
including new cost
allocation studies
if undertaken, to
ensure that the
City’s costs are
fair. Evaluate
alternative
providers for
services provided
by NCPA as
appropriate.
BP8. Reduce
cost of delivering
service through
best
management
practices
We will reduce the cost of delivering service to customers. We will identify
opportunities to better coordinate between Utilities and other City
departments to improve efficient delivery of services. We will perform
benchmarking studies to identify potential modifications to procedures,
practices, materials, and plans and to ensure that we are following best
practices. One best practice is to increase calibration and replacement
schedules for gas and water meters since the meters slow over time causing
actual usage to be under‐recorded, resulting in lost revenue.
“lost and
unaccounted for”
volumes of gas and
water
80% of 2009
levels.
Complete Water
benchmarking
study by end of FY
2015.
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
6
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
BP9. Maximize
value of existing
generation
assets
Palo Alto owns significant supply resource assets including a portion of the
Calaveras Hydroelectric Project, a contract with the Western Area Power
Administration, a permanent allocation of water from the regional water
system managed by San Francisco, and allocated capacity on a gas
transportation pipeline. We will seek out both daily and operational and
long‐term opportunities to optimize the value of these assets to enhance
revenue and/or to reduce costs. We will work with joint‐owners of our
resource assets to leverage those resources and advocate to maintain or
improve the value of existing resources into the future (LEAP and GULP
strategies).
Value harvested
from Redwood gas
pipeline capacity
100%
BP10. Manage
implementation
of strategic plan
Completing the strategic plan is only the beginning of getting value from the
strategic planning process. Ongoing management of the strategies and
initiatives and reporting on progress of those initiatives is essential to
achieving positive results from the strategy. We will report to the UAC and
Council on this plan’s progress twice annually and we will review and revise
the objectives and develop new initiatives on an annual basis.
Number of strategic
initiatives completed
100%
Environmental Sustainability
BP11. Increase
the
environmental
sustainability of
all Utilities
activities
Adding sustainable resources to the supply portfolios will help the City meet
its Climate Protection Plan goals by reducing the carbon footprint of the
utility services provided to our customers. We will achieve this by acquiring
renewable resources and promoting the development of local renewable
resources within the rate objectives in the Long‐term Electric Acquisition
Plan (LEAP). Sustainable practices will be pursued not just for the supply
portfolios, but across all the Utilities day‐to‐day operations.
Meet the state’s
20% per capita water
use reduction by
2020 target
20% by 2020
Complete EIR and
financial plan for
expanding
recycled water
system
BP12. Promote
efficient use of
resources
Resource efficiency programs meet our customers’ desire for environmental
solutions that save money as well as contributing towards the Climate
Protection Plan goals. We will promote resource efficiency by dedicating the
tactical staffing and budgetary resources necessary to reach maximum
Actual electric
energy efficiency
achievement
At least as high as
goals Council set in
December 2012
Include all cost
effective water
efficiency
measures in 2015
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
7
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
deployment of economically feasible resource efficiency. We will revise and
document our long‐term efficiency strategies by updating our 10‐year
Energy Efficiency goals every three years and updating our water efficiency
goals every five years in the Urban Water Management Plan. To maximize
the savings potential for new development, coordinate with the City’s
Economic Development Manager to ensure that new developments
incorporate energy saving features in the design phase.
Actual gas energy
efficiency
achievement
At least as high as
goals Council set in
December 2012
Urban Water
Management Plan
(UWMP).
People and Technology Perspective
PT1. Be an
attractive place
to work
We will create a positive values‐based work environment which attracts and
retains qualified staff. To achieve this objective we will try to better
understand employees desires and incentives, and will articulate our values
both internally and as we recruit.
Employee
satisfaction rating
Improvement
from prior year’s
level
PT2. Obtain,
develop and
train employees
to ensure an
adequate and
qualified
workforce
A properly sized, trained and certified workforce is essential to our
effectiveness. We will identify skill and staffing gaps at the individual and
organizational levels and seek to fill those gaps through the effective use of
opportunities including hiring, mentorship programs, role rotations,
knowledge transfer opportunities, long‐term developmental assignments
and both internal and external training opportunities. We will plan for
workforce succession and provide cross‐training opportunities for
employees to improve employee satisfaction and build a more robust work
force.
Percentage of
operations personnel
that has appropriate
certification and
training required for
working in all areas
they may be
assigned
100% Update the 5‐year
succession plan
for each division.
PT3. Ensure
employees have
adequate tools
to perform job
duties
As major users of technology assets, we must have access to quality and
timely delivered IT services. We must build and maintain an effective
relationship with the City’s IT division that includes clear, frequent
communication as well as productive coordination. We will collaborate with
IT to identify barriers to providing support for technology projects and
remove them. In those instances in which our immediate technology needs
cannot be addressed by the City’s IT division in a timely or sufficiently‐
comprehensive fashion, we will utilize external expertise.
Employees have
adequate tools and
training to perform
their jobs
100% of
employees
Develop a
Utilities‐specific
smart grid and IT
strategic plan.
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
8
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
PT4. Investigate
and adopt
innovative
technologies
Our customers value Utilities embracing new technologies that will help
reduce costs and/or meet Climate Protection Plan goals. We will innovate
by researching technologies and cultivating relationships with entrepreneurs
and academics to identify new cost‐effective and environmentally
sustainable technologies to consider adopting. New technologies, programs,
and projects identified in the smart grid strategic plan will be implemented.
Number of new
technologies
evaluated per year
by an in‐depth study
or pilot project
Three
Financial Perspective
F1. Maintain
financial
strength
Maintaining a high credit rating reduces the cost of borrowing if needed for
capital projects. We will continue best practices for financial management,
adhere to energy risk management policies and guidelines to minimize
financial risk, and maintain sufficient reserves to cover debt obligations as
required to retain CPAU’s current favorable bond rating so that the cost of
capital is low for any bond funded capital projects.
Credit rating At least AA as
determined by
Fitch Ratings or
Standard and
Poor’s or at least
Aa3 as determined
by Moody’s
F2. Maintain
adequate
reserves
Maintaining adequate cash reserves contributes to maintaining our overall
financial health and retaining our current favorable bond rating. We will
maintain Rate Stabilization Reserves levels within Council‐approved
guidelines and sufficient to provide rate stability as desired by ratepayers.
During the annual budget and rate setting process, the risks that each
Utilities fund is exposed to will be identified along with the trajectory of
costs and revenues to allow Council to determine appropriate reserve levels
and rate adjustments.
Operations Reserve
levels
Within guidelines
in Council‐adopted
long‐term
Financial Plans
Utilities Strategic Plan – Strategic Objectives
Approved by Council July 18, 2011 (Staff Report 1880)
Updated by Council August 5, 2013 (Staff Report 3950)
Updated by Council May 11, 2015 (Staff Report 5709)
9
Strategic
Objective
Objective Statement Performance
Measure
2015 Target Strategic
Initiative
F3. Implement
rate structures
that balance cost
of service and
resource
conservation
Retail rates should be designed so that the revenues from a customer group
match the cost to serve those customers. Rates consist of fixed charges and
volumetric charges, which are based on usage. Fixed costs consist of
customer‐related costs (meter reading, billing, etc.) and costs related to
capital projects and operations while variable costs include the cost of
buying supplies (water, gas, or electricity). When fixed costs are recovered
through charges based on usage, costs will not be recovered if customers
reduce usage more than projected. To address this problem we will
examine alternate rate structures that strike a balance between the two
competing objectives (cost of service and resource efficiency) to ensure that
certain fixed costs are recovered with a fixed charge, but other costs are
recovered with charges that vary depending on usage (volumetric charges).
Complete Electric
cost of service
analysis (COSA) by
end of CY 2015.
10
Maintain adequate
reserves
Maintain financial
strength
Implement rate structures that balance cost of
service and resource conservation
Fi
n
a
n
c
i
a
l
Re
s
o
u
r
c
e
s
Pe
o
p
l
e
a
n
d
Te
c
h
n
o
l
o
g
y
Be an attractive
place to work
Obtain, develop and train
employees to ensure an
adequate and qualified workforce
Ensure employees have
adequate tools to
perform job duties
Values: Honesty and Integrity Teamwork Accountability Quality of Service
“Be responsive to all
my Utilities services-
related needs”
“I receive safe and
reliable service”
“I expect to pay a
reasonable bill”
“Care for our
environment”
Vision: We Deliver Extraordinary Value to Our Customers
Strategic Destination: We will earn the high satisfaction of our customers with our cost-
competitive provision of safe, reliable and environmentally sustainable utility services
Cu
s
t
o
m
e
r
Operate the
Utilities systems
safely
Reliability and Safety Customer Service
Excellence
Manage Cost Environmental
Sustainability
Serve customers
promptly and
completely
Offer programs to meet
the needs of customers
and the community
Communicate clearly and
proactively with all our
stakeholders
Negotiate supply contracts
to minimize financial risk
Reduce cost of delivering
service through best
management practices
In
t
e
r
n
a
l
B
u
s
i
n
e
s
s
P
r
o
c
e
s
s
e
s
Increase the
environmental
sustainability of all
Utilities operations
Promote efficient
use of resources
Investigate and
adopt innovative
technologies
Ensure a reliable
supply of utility
resources
Replace infrastructure
before the end of its
useful life
Maximize value of existing
generation assets
Manage implementation
of strategic plan
Balanced Scorecard Performance Measure Results Attachment - B
1
Measure ID Strategic
Objective Objective Statement Performance Measure 2015 Target Measure Goal
Value FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Score
(Values: +, -
, TBD)
C1.1
C1. “I receive
safe and reliable
service.”
Customers expect that Utilities services are provided on a continuous basis,
without interruption. In addition, customers expect that the Utilities delivery
systems are safe and will not harm them or put them in any danger. We will listen
to our customers and seek to understand their reliability and safety concerns and
implement programs and projects to address them.
Average time to restore service
per interrupted customer Less than 90 minutes <90 113 min 139 min 38.69 263.57 164.78
-
C1.2
Number of electric system
interruptions per year for average
customer
Ranks in the top
quartile nationwide (less
than .9)<0.9 0.13 0.25 0.41 0.18 0.24
+
C2
C2. “Be
responsive to all my
utilities-related
service needs.”
We understand that the customer wants clear, accurate bills with easy methods of
payment; access to usage history and enough understanding to efficiently manage
usage; to feel quickly and completely “taken care of” when they have concerns,
questions or requests and to be communicated with effectively both as individuals
and as CPAU’s owners. One of the ways to achieve this is to elicit feedback from
customers to help improve service.
Customer satisfaction scores on
annual surveys for overall value.Ranking in 85-90%>85%
81%
Commercial
86%
Residential
85%
Water
Customers 87% Commercial
82%
Residential
-
C3.1
C3. “I expect to
pay a reasonable
bill”
We understand that customers expect their bills to be comparable to those in
surrounding communities and do not expect to pay more than PG&E customers.
Customers believe it is reasonable to pay slightly more in exchange for increased
reliability, safety and protection of the environment. However, customers’ overall
bills for Utilities services must remain reasonable and should not increase
significantly in any one year. Customers also want their bills to provide useful
information about their consumption of resources in addition to the rate so that they
can understand how they can influence their total cost for Utilities services.
The average combined residential
customer bill for electricity, water,
gas, and wastewater services.
Less than the average
of bills for comparable
services in nearby
communities (MP, MV,
SC, Hayward, RC,
Roseville, and
Alameda).
Total bill calculation
for each month for
CPAU and for
comparator agencies
- this changes every
year so Measure
Goal Value is not a
constant
CPAU:
E - $42.76
G - $51.03
W - $51.19
WW - $27.91
Tot - $172.89
Nearby
community
average:
$158.93
CPAU:
E - $42.76
G - $37.49
W - $62.16
WW - $29.31
Tot - $171.72
Nearby
community
average: $166.35
CPAU:
E - $42.76
G - $38.89
W - $67.35
WW - $29.31
Tot - $178.31
Nearby
community
average:
$177.06
CPAU:
E - $42.76
G - $37.39
W - $67.35
WW - $29.31
Tot - $177.22
Nearby
community
average:
$191.63
CPAU:
E - $42.76
G - $37.98
W - $75.35
WW - $31.95
Tot - $188.04
Nearby
community
average:
$204.86
+
C3.2 Annual rate change
Maximum of 10% per
year for electric, gas,
and wastewater Utilities
service.
Maximum of 20% per
year for water Utility
service.
<10% for E, G,
WWC
<20% for W
Effective 7/1/11:
E 0%
G 0%
W 12.5%
WW 0%
Effective 7/1/12:
E 0%
G -10%*
W 15%
WW 5%
*Gas supply rates
change monthly
Effective 7/1/13:
E 0%
G 0%*
W 7%
WW 0%
*Gas supply
rates change
monthly
Effective 7/1/14:
E 0%
G 0%*
W 0%
WW 0%
*Gas supply
rates change
monthly
Effective 7/1/15:
E 0%
G 0%
W 12%
WW 9%
*Gas supply
rates change
monthly
**Drought
surcharge added
9/1/15 still in
effect
+
C4.1
C4. “Care for our
environment”
Our community wants its customer-owned utility to offer choices for them to
manage their resource use in ways that reflect their environmental values. Utilities
will improve existing programs and develop new programs to meet customer needs
and allow customers to manage their own environmental footprint.
Percentage of customers
participating in the PaloAltoGreen
Gas program 20% Customers Top rank nationally E - 24%E - 18% E - 18%G - 3.2%G - 3.8%
N/A
C4.2
Percentage of greenhouse gas
reductions
10% greenhouse gas
reductions N/A N/A N/A 1.3%5.6%
N/A
Customer and Community Perspective
Balanced Scorecard Performance Measure Results Attachment - B
2
Measure ID Strategic
Objective Objective Statement Performance Measure 2015 Target Measure Goal
Value FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Score
(Values: +, -
, TBD)
BP1.1
BP1. Ensure a
reliable supply of
utility resources
We will implement strategies that ensure the reliable supply of utility resources to
meet present and future needs. To provide opportunities for economic
development within Palo Alto, we must provide sufficient resources that meet the
short and long-term needs of our customers. To achieve this we will maintain the
utility system components, and provide for adequate utility resource supplies to our
current and future customers. We will also develop new management practices
and organizational structure to ensure compliance with regulatory requirements.
Duration of electric system
interruption per year for average
customer
Ranks in the top
quartile nationwide (less
than 60 minutes per
customer) <60 15 min 34 min 15.78 min 46.85 39.48
+
BP1.2
Response time to all emergency
calls Under 30 minutes <30m 22 min 23 min 22 min 22 Min 19 min
+
BP2.1
BP2. Operate the
utility systems safely
We will continue to ensure the safety of our customers, employees and the
community by the ongoing implementation of a safety programs. Protecting
customers and employees from injury and customer’s property from damage is
essential for delivering quality utility services to our customers. The safety
programs will be implemented by updating safety procedures, educating customers
via outreach materials and workshops, correcting system deficiencies, operating in
accordance with existing safety rules, and ensuring that products delivered to
customers are safe.
AGA (American Gas Association)
Incidence Rate Zero reportable
incidents
0 0 0 0 0 0
+
BP2.2
Customer awareness of gas
safety issues
90% of customers
responding to annual
gas customer safety
awareness survey >90%96.70%96%96%94.6%97.0%
+
BP3
BP3. Replace
infrastructure before
the end of its useful
life
We will continue to implement a long-term strategy for replacing infrastructure
before the end of its useful life. Reliable delivery of electric service to our
customers is critical for the success of business and the quality of life for our
residents. To accomplish this, we will focus on reducing the backlog and replaces
infrastructure systems in a manner that spreads the expense across multiple years
resulting in program with even expenditures patterns in future years.
Backlog of infrastructure elements
whose age is beyond its useful life Zero
E - $0
G - $0
W - $0
WWC - $0
E - $7M
G - $1M
W - $3M
WW - $5M
E $7M
G $0
W $7M
WW $5M
E $6.4 M
G $0 M
W $4 M
WW $3 M
E $4 M
G $0 M
W $2 M
WW $3 M
E $3.7M
G $0M
W $2.1 M
WW $2.6 M
-
Internal Business Process Perspective
Safety and Reliability
Balanced Scorecard Performance Measure Results Attachment - B
3
Measure ID Strategic
Objective Objective Statement Performance Measure 2015 Target Measure Goal
Value FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Score
(Values: +, -
, TBD)
BP4.1
BP4. Serve
customers promptly
and completely
W e will provide customers with the highly responsive service they desire. We will
do this by reviewing and improving our processes for managing accounts, handling
payments, resolving billing issues, responding to information and field service
requests and notifying customers during service disruptions. We will identify ways
to streamline these processes and implement changes. Specifically, we will
review, document and improve business processes that have been identified as
having long customer response times.Average phone wait time 90 seconds or less <90 sec 134 sec 107 sec 63 sec 68 sec 62 sec +
BP4.2 Number of billing adjustments
10% reduction from
number in 2009
FY09 - 3286
90% - 2,958 1,365 1,340 2,743 1,449 1,165 +
BP5
BP5.
Communicate
clearly and pro-
actively with all our
stakeholders
We will proactively communicate with all our stakeholders, including all customer
groups, civic leaders, community groups and the press. To achieve this objective
we will provide the information needed for our stakeholders to effectively access,
understand and utilize all utilities services and programs. In addition, we will design
communication vehicles and dissemination processes that will enable our residents
to be educated owners of their municipal utilities system.
Time until informing the public and
local media of a disruption
affecting all sensitive major
customers
Less than 90 60 30
minutes after becoming
aware of a disruption <60m < 90 min <30 Min <30 Min <30 Min <30 min +
BP6
BP6. Offer
programs to meet
the needs of
customers and the
community
We will assist customers to lower their cost of utilities services and support the
environment. We will assist customers facing economic hardship by offering bill
payment assistance programs. We will educate customers on the reasons for and
their means of compliance with our safety and regulatory requirements. We will
also identify all customer groups, identify any gaps in service provision to those
customers, and propose new programs or changes to existing programs to close
those gaps.
Participant* satisfaction with
Utilities programs (*rebate
recipients, workshop attendees,
callers, etc.)
At least 90% of
program participants
satisfied with their
experience >90%
Average of all
workshops:
94%
Average of all
workshop: 95%
Average of all
workshop: 95%
Average of all
workshop: 95%
Workshops &
Home Energy
Genie: 93.83%+
BP7
BP7. Negotiate
supply contracts to
minimize financial
risk
We will continue to negotiate supply contracts to acquire supply resources while
managing supply portfolio cost uncertainty to meet rate and reserve objectives and
following sound risk management practices. To ensure that we are buying
commodities at as competitive prices as possible, we will negotiate contracts with
new counterparties to continue to have a sufficient set of credit-worthy trading
partners. We will continue to develop long-term acquisition policies and plans
(LEAP) and update those plans at least every three years. We will also determine
all that is necessary to execute a gas prepay transaction as that is one clear way to
lower the cost of gas supply resources.
Number of competitive bids
received for each fixed-price
transaction.
Minimum of three
electric bids > 3 E - 2.75 bids E - 2.4 E - 3.5 bids E - 4.6bids E - 3.9 bids
+
BP8
BP8. Reduce
cost of delivering
service through best
management
practices
We will work towards reducing the cost of delivering service to customers. We will
identify opportunities to better coordinate between Utilities and other City
departments to improve efficient delivery of services. We will perform
benchmarking studies to identify potential modifications to procedures, practices,
materials, and plans and to ensure that we are following best practices. One best
practice is to increase calibration and replacement schedules for gas and water
meters since the meters slow over time so that the actual usage is under-recorded,
resulting in lost revenue.
“lost and unaccounted for”
volumes of gas and water 80% of 2009 levels.
2009
G - 2.6%
W - 5.0%
G - 2.8%
W - 8.2%
G-2.1%
W-7.8%
G-2.5%
W-8.6%
G-2.3%
W-5.0%
G-0.0%
W-4.9%
+
Customer Service Excellence
Reduce Costs
Balanced Scorecard Performance Measure Results Attachment - B
4
Measure ID Strategic
Objective Objective Statement Performance Measure 2015 Target Measure Goal
Value FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Score
(Values: +, -
, TBD)
BP9
BP9. Maximize
value of existing
generation assets
Palo Alto owns significant supply resource assets including a portion of the
Calaveras Hydroelectric Project, a contract with the Western Area Power
Administration, a permanent allocation of water from the regional water system
managed by San Francisco, and allocated capacity on a gas transportation
pipeline. We will seek out both daily and operational and long-term opportunities to
optimize the value of these assets to enhance revenue and/or to reduce costs. We
will work with joint-owners of our resource assets to leverage those resources and
advocate to maintain or improve the value of existing resources into the future
(LEAP and GULP strategies).
Value harvested from Redwood
gas pipeline capacity 100%100%99%100%100%100%100%
+
BP10
BP10. Manage
implementation of
strategic plan
Completing the strategic plan is only the beginning of getting value from the
strategic planning process. Ongoing management of the strategies and initiatives
and reporting on progress of those initiatives is essential to achieving positive
results from the strategy. We will report to the UAC and Council on plan progress
twice annually and we will review and revise the objectives and develop new
initiatives on an annual basis.
Number of strategic initiatives
completed 100%100%8 8 10 13 17
-
BP11
BP11. Increase
the environmental
sustainability of the
supply portfolios
Adding sustainable resources to the supply portfolios will help the City meet its
Climate Protection Plan goals by reducing the carbon footprint of the utility services
provided to our customers. We will achieve this by acquiring renewable resources
and promoting the development of local renewable resources within the rate
objectives in the Long-term Electric Acquisition Plan (LEAP).
Meet states 20% per capita water
use reduction by 2020
20% of baseline (2015)
level 4,611,979 CCF N/A N/A N/A N/A 19.6%29.2%
+
BP12
BP12. Promote
efficient use of
resources
Resource efficiency programs meet our customers’ desire for environmental
solutions that save money as well as contributing towards the Climate Protection
Plan goals. We will promote resource efficiency by dedicating the tactical staffing
and budgetary resources necessary to reach maximum deployment of
economically feasible resource efficiency. We will revise and document our long-
term efficiency strategies by updating our 10-year Energy Efficiency goals every
three years and updating our water efficiency goals every five years in the Urban
Water Management Plan.
Actual annual energy efficiency
achievement as percentage of
electric and gas load
E - Goals Council set in
December 2012
G - Goals Council set in
December 2012
E - 0.60%
G - 0.50%
E - 1.52%
G - 0.73%
E - 0.85%
G - 1.13%
E - 0.87%
G - 1.16%
E - 0.65%
G - 0.92%N/A
N/A
Environmental Sustainability
Balanced Scorecard Performance Measure Results Attachment - B
5
Measure ID Strategic
Objective Objective Statement Performance Measure 2015 Target Measure Goal
Value FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Score
(Values: +, -
, TBD)
PT1
PT1. Be an
attractive place to
work
We will create a positive values-based work environment which attracts and retains
qualified staff. To achieve this objective we will try to better understand employees
desires, work with City management to establish sufficient compensation, benefits,
and incentives, and will articulate our values both internally and as we recruit.Employee satisfaction rating
Improvement from 2012
baseline level 100%
62.7% -
Satisfied
12.7% - Neutral
66.3% - Satisfied
12.5% - Neutral
72.5%- Satisfied
5%- Neutral
62.4%- Satisfied
15.6%- Neutral
70.8%- Satisfied
8.9%- Neutral
+
PT2
PT2. Develop
and train employees
to ensure a qualified
workforce
A properly trained and certified workforce is essential to our effectiveness. We will
identify skill gaps at the individual and organizational levels and seek to fill those
gaps through the effective use of opportunities including mentorship programs, role
rotations, knowledge transfer opportunities and both internal and external training
opportunities. We will plan for workforce succession and provide cross-training
opportunities for employees to improve employee satisfaction and build a more
robust work force.
Percentage of operations
personnel that has appropriate
certification and training required
for working in all areas they may
be assigned 100%100%100%100%100%100%100%
+
PT3
PT3. Ensure
employees have
adequate tools to
perform job duties
As major users of technology assets, we must have access to quality and timely
delivered IT services. We must build and maintain an effective relationship with the
City’s IT division that includes clear, frequent communication as well as productive
coordination. We will collaborate with IT to identify barriers to providing support for
technology projects and remove them. In those instances in which our immediate
technology needs cannot be addressed by the City’s IT division in a timely or
sufficiently-comprehensive fashion, we will utilize external expertise.
Employees have adequate tools
and training to perform their jobs 100% of employees 100%N/A N/A N/A N/A N/A
N/A
PT4
PT4. Investigate
and adopt
innovative
technologies
Our customers value Utilities embracing new technologies that will help reduce
costs and/or meet Climate Protection Plan goals. We will innovate by researching
technologies and cultivating relationships with entrepreneurs and academics to
identify new cost-effective and environmentally sustainable technologies to
consider adopting. Review of Utilities Technology needs was completed in 2014
and a technology strategic plan is expected to be completed by the end of CY
2015. New technologies, programs, and projects identified in the plan will be
implemented in the subsequent years.
Number of new technologies
evaluated per year Three >3 N/A 13 15 15 14
+
People and Technology Perspective
Balanced Scorecard Performance Measure Results Attachment - B
6
Measure ID Strategic
Objective Objective Statement Performance Measure 2015 Target Measure Goal
Value FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Score
(Values: +, -
, TBD)
F1
F1. Maintain
financial strength
Maintaining a high credit rating reduces the cost of borrowing if needed for capital
projects. We will continue best practices for financial management, adhere to
energy risk management policies and guidelines and maintain sufficient reserves to
cover debt obligations as required to retain CPAU’s current favorable bond rating
so that the cost of capital is low for any bond funded capital projects.Credit rating
At least AA as
determined by Fitch
Ratings or Standard
and Poor’s or at least
Aa3 as determined by
Moody’s <=AA or <=Aa3
S&P = AAA
Moody's = Aa2
S&P = AAA
Moody's = Aa2
S&P = AAA
Moody's = Aa2
S&P = AAA
Moody's = Aa2
S&P = AAA
Moody's = Aa2
+
F2
F2. Maintain
adequate reserves Operations Reserve levels
Within guidelines in
Council-adopted long-
term financial plans
Above rate
stabilization reserve
levels
All RSRs are
above minimum
guideline levels.
All RSRs are
above minimum
guideline levels.
All RSRs are
above minimum
guideline levels.
All reserves are
within Operations
reserve guideline
levels.
E - Below
G - Above
W - Above
WWC - Within
-
F3
F3. Implement
rate structures that
balance cost of
service and
resource
conservation
Retail rates should be designed so that the revenues from a customer group match
the cost to serve those customers. Rates consist of fixed charges and volumetric
charges, which are based on usage. Fixed costs consist of customer-related costs
(meter reading, billing, etc.) and costs related to capital projects and operations
while variable costs include the cost of buying supplies (water, gas, or electricity).
When fixed costs are recovered through charges based on usage, costs will not be
recovered if customers reduce usage more than projected. To address this
problem we will implement rate structures that strike a balance between the two
competing objectives (cost of service and resource efficiency) to ensure that
certain fixed costs are recovered with a fixed charge, but other costs are recovered
with charges that vary depending on usage (volumetric charges).Fixed charges on Utilities rates
By 2013, adequate to
cover 100% of the fixed
costs of meter reading,
billing, and other
customer-related costs
E - 100%
G - 100%
W - 100%
WWC - 100%
E - NA
G - 100%
W - 100%
WWC - 100%
E - NA
G - 100%
W - 100%
WWC - 100%
E - NA
G - 100%
W - 100%
WWC - 100%
E - NA
G - 100%
W - 100%
WWC - 100%
E - 100%*
G - 100%
W - 100%
WWC - 100%
+
Financial Perspective