HomeMy WebLinkAbout2018-04-05 Utilities Advisory Commission Agenda Packet
NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I. ROLL CALL
II. ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable
time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from
discussing or acting upon any topic initially presented during oral communication.
III. APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Meeting held on March 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. Discussion of Three Utility-Related Sustainability/Climate Action Plan Implementation Discussion
Plan Components: Mobility, Efficiency and Electrification, and Water Management
2. Utilities Advisory Commission Recommendation that Council Approve a Recommendations Action
Concerning: (1) Future Plans for Fiber and Broadband Expansion; and (2) Expand Wi-Fi
To Unserved City Facilities; and Discontinue Consideration of City-Provided Wi-Fi in
Commercial Areas
3. Staff Recommendation that the Utilities Advisory Commission Recommend that the Action
City Council Adopt a Resolution Approving the Fiscal Year 2018 Gas Utility Financial Plan
With no Changes to Gas Distribution Rates
4. Staff Recommendation that the Utilities Advisory Commission Recommend that the City Action
Council Adopt 1) a Resolution Approving the Fiscal Year 2018 Electric Financial Plan, and
2) a Resolution Increasing Electric Rates by Amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU,
E-7, E-7-G, E-7 TOU and E-14 Rate Schedules
5. Appointment of Commissioners to an Ad Hoc Budget Committee for FY 2018 Budget Action
6. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: May 3, 2017 – Special Meeting
ADDITIONAL INFORMATION
The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt.
Code Section 54954.2(a)(2)).
Informational Report Public Letters(s) to the UAC
UTILITIES ADVISORY COMMISSION
WEDNESDAY, APRIL 5, 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
Utilities Advisory Commission Minutes Approved on: Page 1 of 15
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MARCH 1, 2017 MEETING
CALL TO ORDER
Vice Chair Danaher called to order at 7:05 p.m. the meeting of the Utilities Advisory Commission
(UAC).
Present: Vice Chair Danaher, Commissioners Trumbull, Forssell, Danaher, Schwartz, Ballantine,
and Johnston, Councilmember Filseth
Absent: Chair Cook
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Herb Borock, Palo Alto resident, asked that his remarks be amended so that it recorded that his
reference to the “Wastewater Utility” reflect that he called it the “Wastewater Collection Utility”
Commissioner Trumbull moved to approve the minutes from the February 1, 2017 UAC meeting
with the amendment requested by Mr. Borock. Commissioner Johnston seconded the motion. The
motion carried unanimously (6-0, with Vice Chair Danaher and Commissioners Trumbull, Forssell,
Danaher, Schwartz, Ballantine, and Johnston voting yes and Chair Cook absent).
AGENDA REVIEW AND REVISIONS
None.
REPORTS FROM COMMISSION MEETINGS/EVENTS
Vice Chair Danaher attended a conference with clean tech investors. He said the Great Barrier Reef
lost 22% of its coral last year due to global warming, which underscored the urgency of the
problem. There was a lot of activity in the private sector to implement storage. Storage was
becoming more attractive to investors. There were companies coming into existence focused on
helping utilities work with customers to deploy st orage and achieve benefits associated with grid
management.
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 15
UTILITIES GENERAL MANAGER REPORT
Utilities General Manager Ed Shikada delivered the General Manager’s Report:
New Electric Vehicle Charging Station Rebates, Solar PV & EV Calculator
In early March, the City will begin offering rebates for Electric Vehicle Charging Stations installed at
schools, apartment complexes, and non-profit buildings with common area charging
accommodations. This is following Council’s approval of the Low Carbon Fuel Sta ndard program
(#7301) on October 24, 2016. The Bay Area Air Quality Management District also just announced
an incentive program for EV Chargers for public and private entities, which we will promote to
those ineligible to participate in our rebate program. Additionally, we are putting the final touches
on a new online PV and EV calculator. This calculator will help customers understand the costs
associated with use of solar PV and electric vehicles in Palo Alto, using City of Palo Alto Utility rates
and taking into account customers’ roof exposures for solar generation.
Building Operator Certification Courses for Key Account Facilities Managers
The City is sponsoring a Building Operators Certification course for Key Account business utility
customers. These are a series of classes designed to teach facilities management staff techniques
to keep their buildings operating as efficiently as possible. The first courses are being held this
week. The class is funded partially by the student’s admission fee an d partially from Utilities Public
Benefits funds.
Vice Chair Danaher asked what types of charges allowed to take advantage of the rebates.
Program Manager Hiromi Kelty said the majority of the chargers would be Level 2. The program
was focused on charging stations that could be used all day. Level 1 chargers were too slow for the
program. Level 3 chargers were very expensive, so it was unlikely many of these would be
installed.
Commissioner Schwartz asked whether they would all require a Chargepoint account.
Kelty said no single product would be required for the rebate. There were many products
available.
Commissioner Schwartz recommended a map making it clear where chargers with different brands
could be found.
Kelty said there was a map available online and that information would be available.
Vice Chair Danaher said he had heard that serving populations in that manner was important and
that Level 2 chargers were a minimum requirement, with Level 3 eventually becoming more and
more important.
COMMISSIONER COMMENTS
None.
UNFINISHED BUSINESS
None.
Utilities Advisory Commission Minutes Approved on: Page 3 of 15
NEW BUSINESS
ITEM 1: DISCUSSION: 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
Senior Resource Planner Shiva Swaminathan gave an overview of the City’s carbon reduction
efforts in the previous decade. Electricity carbon content had been nearly eliminated. Natural gas
and transportation were the remaining major sources of greenhouse gases. Today’s focus was on
natural gas, which primarily was related to building heating and hot water hea ting. He showed the
ten point electrification work plan adopted by Council in August 2015, noting that tonight’s
presentation would focus on items one and four of the work plan relating to evaluating both
mandates and pilot programs related to heat pump water and space heating.
Development Services Director Peter Pirnejad stated that over the previous year staff had been
working to evaluate whether it would be cost-effective and feasible to mandate electrification of
homes and businesses. He described the stakeholder engagement effort associated with the work,
including a working group his team had brought together to provide feedback, including builders,
architects, green building professionals, energy modelers, developers, contractors, and city staff .
He discussed the various aspects of heat pump water and space heaters that needed to be
analyzed to evaluate the mandate, including cost barriers associated with California Energy
Commission (CEC), operational and performance barriers, the knowledge and willingness of
contractors to install them, customer acceptance, and rate - and fee-related barriers. The first step
was to work with the California Energy Commission (CEC) to eliminate regulatory barri ers that
prohibited heat pumps, and to remove the modeling requirement that installers previously had to
undergo prior to installing a heat pump.
Commissioner Trumbull asked what these modeling efforts were and how they affected
electrification.
Pirnejad stated that previously the builder would have to run a full analysis of the building prior to
installing a heat pump water heater to demonstrate compliance with Title 24. This is no longer
required.
Pirnejad continued the presentation, describing the Green Building Code the City recently
adopted, for which it had received several awards, and stated that the Green Building Code
required new buildings in Palo Alto to be more efficient than was required by the base California
Energy Code. Staff had created separate requirements for all electric buildings, since it would be
cost prohibitive for these buildings to comply with the Green Building Requirements.
Commissioner Ballantine asked whether all-electric buildings consumed more electricity.
Pirnejad said they did.
Commissioner Ballantine asked whether the all-electric home would be more efficient than an
equivalent building using both gas energy and electric energy. He was concerned about any waiver
that would enable an all-electric home to be less efficient than other homes.
Utilities Advisory Commission Minutes Approved on: Page 4 of 15
Pirnejad said there were two alternatives for compliance under the Green Building Ordinance,
either installing an all-electric building or making the mixed gas and electric building more efficient
than the base requirements in the California Energy Code.
Senior Resource Planner Shiva Swaminathan said in calculating the efficiency both electric and gas
energy were considered on the same basis, British Thermal Units (BTU) per square foot. He said
that the CEC’s modeling methodology for electric appliances was not yet mature, resulting i n
calculated BTU values that were higher than actual BTU values. Actual all-electric homes met the
efficiency goals the City was aiming for in the Green Building Code, and therefore a carve -out for
these homes had been established.
Commissioner Ballantine said the explanation was helpful.
Pirnejad continued the presentation, stating that in most cases heat pump water heating, space
heating, or all-electric building packages were not cost-effective for the purpose of code
mandates. In addition, there were a number of industry barriers. Contractors were unlikely to have
the skills and willingness to install these appliances, customers were less willing to accept them,
there were performance issues with how quickly the water or space was heated with these
technologies, and there were higher space requirements for installation. As a result, staff did not
believe it was prudent to proceed with a mandate. Instead, staff believed it was better to reduce
barriers and create programs to get the market ready to accommodate these appliances. Staff
would monitor the conditions and consider re-evaluating a mandate within the next five years.
Staff would meanwhile focus on finding ways to achieve deep energy efficiency retrofits in existing
buildings.
Commissioner Ballantine asked whether failure analysis like FMEA had been performed to
determine the consequences of failure of electrified buildings. He said he had been through two
situations in all-electric homes. In one case he had been in an all-electric home during a utility
outage during cold weather, and had needed to burn wood for heat. The other situation had been
similar and if he had not had a backup heat source, pipes would have frozen. He was concerned
about the reduced resiliency of moving to all-electric homes. This topic should be considered prior
to imposing any mandates.
Pirnejad said those types of factors had been considered in addition to the cost -effectiveness
analysis, though resiliency had not been considered in as much detail as an FMEA analysis . Even
cost-effective measures may not be reasonable to mandate due to issues like market readiness
and logistical challenges in installation of heat pumps.
Commissioner Ballantine recommended doing some kind of hazard analysis if a mandate were
considered in the future.
Melanie Jacobson, Consultant, Integrated Design 360, spoke about the scope of the electrification
study. It had considered single-family, low-rise multi-family, and office buildings. She said there
was a protocol required by the CEC to evaluate whether it would be acceptable to mandate a
given technology that differed from the State’s Energy Code. It used a calculation methodology
called Time-Dependent Valuation (TDV). She discussed industry barriers, including the cost of
electrical panel upgrades, the lack of knowledge base in the industry, issues with making space for
these appliances in houses, the fact that contractors handling these small projects were not
Utilities Advisory Commission Minutes Approved on: Page 5 of 15
normally licensed for both electrical and plumbing work, and other factors. She discussed the
results of the study, noting that heat pump water heate rs were generally not cost effective. Heat
pump space heaters were cost effective in some cases, and heat pump packages that involved no
gas connection were generally only cost effective in new construction, particularly in single family
homes. However, even when packages were cost effective, industry barriers were such that
mandating these packages was still not recommended.
Commissioner Forssell asked how cost-effectiveness was calculated in this context
Farhad said the TDV methodology calculated the co st of energy use at different times of day and
times of year. The calculations were done both using the TDV methodology and from the customer
perspective.
Swaminathan said the cost of one BTU of electricity was higher than the cost of one BTU of gas.
This was taken into account in the TDV methodology.
Commissioner Forssell asked whether it would be accurate to say that the TDV methodology
calculated the cost effectiveness from the State of California point of view.
Swaminathan confirmed that was true.
Commissioner Trumbull asked whether there was a climate change impact included in the
calculation.
Swaminathan stated there was a carbon cost included in the methodology.
Commissioner Ballantine asked if the model could deal with the variation in COP by temperature.
Farhad confirmed it did.
Commissioner Schwartz said her neighbor had a heat pump sitting opposite from her front porch,
and it was very load. She asked whether this was factored into the study.
Jacobson said noise was an industry barrier considered in the analysis.
Vice Chair Danaher asked whether the cost analysis had considered the difference between Palo
Alto electricity rates and rates in the rest of the state.
Farhad said the cost effectiveness analysis had also been done using Palo A lto rates and remained
the same, except that the scenario that assumed heat pump space and water heating in a single
family home with the gas connection remaining became cost ineffective.
Swaminathan spoke regarding the Heat Pump Water Heating Pilot Program that had been
operating for the last nine months. It had been created in partnership with members of the
community.
Commissioner Schwartz made clear that the people impacted by heat pump noise were the
neighbors, not the homeowner.
Utilities Advisory Commission Minutes Approved on: Page 6 of 15
Swaminathan said an important goal of the program was efficiency, and heat pump water heaters
installed had to be more efficient than an equivalent gas heater. He discussed the industry barriers
to be reduced in the pilot program, including ensuring it was possible to obtain these appliances,
that contractors were able to install them, and reducing code barriers . He discussed the work the
City did with the CEC to define a minimum efficiency for heat pumps that would eliminate the
requirement for installers to create a model before installing them. Previously, if a gas connection
was available, anyone who wanted to install a heat pump had to complete an expensive modeling
exercise. The City had worked with the CEC to establish an efficiency level for heat pumps that, if
exceeded, would mean the modeling exercise was not required. The CEC had rolled out this rule
statewide. He discussed education and discussions within the community. He described how the
program worked and what resources were available to customers. He also discussed how the
Utilities Department was doing some work to achieve some of the same benefits for heat pump
space heating, working with the CEC to reduce barriers and launching a pilot program. He stated
that these efforts were a small part of staff’s level of effort related to building and vehicle
efficiency electrification. Most time was spent on building efficiency and vehic le electrification. He
reiterated that staff’s overall approach at this time was to defer any mandates for electrification
and instead focus on building efficiency, while spending some time on reducing market barriers to
electrification and establishing pilot programs.
Vice Chair Danaher said there was also a Colleague’s Memo included in this agenda item focused
on just how green the City’s electricity was. He believed the UAC would agree with the staff’s
approach to efficiency and electrification. He asked for public comments.
Bill Conlan, Palo Alto resident, said he was Commissioner Schwartz’s husband and had done the
calculations in the Colleague’s Memo. He said he had redone the calculations, and it was now clear
there was a greenhouse gas (GHG) savings associated with heat pump water heaters, as opposed
to what had been stated in the memo . He showed a series of slides demonstrating that the City’s
load was not always aligned with its energy generation. When the City had a higher load than its
generation, it bought power in the market, and when it had higher generation, it sold power. He
gave an example with a specific day, showing how one could build a solar project that generated
an number of megawatt-hours (MWh) equal to the City’s load on that day, but that they would not
occur at the same time. This created merchant risk. It was premature to pursue electrification until
this problem had been solved.
Gary Lindgren, 505 Lincoln Ave, agreed that there should not be mandates for electrification at
this time. He said heat pumps were not meant to be used when gas was available. Where gas was
not available they saved money, but generally gas was preferable when available. He said that
electricity was five to six times more expensive on an energy basis. Heating bills of pilot program
participants could double, and it was very important to make that clear to participants.
David Coale, Palo Alto resident, said he was a member of Carbon Free Palo Alto, but speaking on
his own behalf. He thanked staff for the hard work reducing barriers. He urged the UAC to
consider some kind of mandate. He said the State’s TDV methodology was outdated. The carbon
cost used in the methodology was based on the cap and trade market carbon cost, but the real
cost of carbon associated with climate change was much higher. He said mandates saved money
and pushed the market to learn how to install them. He said the noise for a heat pump water
heater was in the house, not outside the house. The noise for a heat pump space heater was the
Utilities Advisory Commission Minutes Approved on: Page 7 of 15
same for an air conditioner, and it was not considered a barrier for air conditioner installation. He
said the industry would not adopt these appliances without a push.
Vice Chair Danaher asked what the carbon cost used in the TDV calculation was.
Swaminathan said the current cost was in the $12 -$13 range, but the methodology used a higher
cost than that.
Commissioner Schwartz said she and Vice Chair Danaher wrote this Colleague’s Memo in reaction
to some public sentiment she had heard that it was akin to a moral failing to want to use gas heat
instead of heat pumps. She said that if the electricity purchased in the early morning was going to
be dirtier than what was available during the day, it was not a net benefit. She said if the City had
chosen to use Renewable Energy Credits (RECs) to make an effort to reduce carbon, it was helpful,
but it did not mean there was a real benefit to using more energy in the mornings when
renewable energy was not actually being generated. It should not be considered unless the City
bought renewable energy like geothermal that generated at the same time as the energy being
used. She said that practically, it was hard to consider something like solar hot water heating or
heat pumps when a water heater failed. She thought it was great when people installed these
measures voluntarily, but it was not a good idea to mandate them.
Commissioner Ballantine said it took a lot of work to manage an electric distribution system. He
was concerned that there was not enough consideration on how electrification would affect the
system. It would take a long lead time to prepare the system to accommodate these new
technologies. He wanted to make sure electrification and CO2 reduction did not come at the cost
of resiliency. He thought the pilot program was a good way to evaluate electrification. Storage
could be paired with heat pumps to provide resiliency.
Commissioner Schwartz said she was very supportive of transportation electrification. In Palo Alto
there was strong momentum in adopting electric vehicles. Moving quickly in this area was a way to
have a significant impact. She addressed the issue of fugitive emissions. She thought driverless
cars would be a good way to detect methane leaks.
Assistant Director of Resource Management Jonathan Abendschein emphasized that the City’s gas
utility had an aggressive leak detection and repair program. The entire system was surveyed every
two years, more frequently than the five year survey cycle required by the CEC.
Commissioner Schwartz asked whether leaks were an area of concern for the community.
Chief Operating Officer Dean Batchelor said there was not a problem in this area. Staff detected
and repaired leaks regularly.
Vice Chair Danaher asked how much of Palo Alto’s power supply came from hydroelectric power.
Swaminathan said Palo Alto was probably buying power half the time and selling power half the
time. He said Palo Alto was exposed to the power markets. In the short term, every new unit of
electricity used came from the power markets, but in the long term, the electric utility would
procure renewable energy to match that new unit of electricity.
Utilities Advisory Commission Minutes Approved on: Page 8 of 15
Vice Chair Danaher clarified he wanted to know how much of the City’s energy came from the
market, presumably fossil fuels, and how much came from carbon free energy.
Abendschein said the carbon free energy was normally dispatched when it provided the most
value, normally the middle of the day. During a summer day there was enough carbon free power
to cover most of Palo Alto’s load around the clock, with a small shortfall at night. During a winter
day only a portion of the load was matched with renewable energy at any given hour.
Councilmember Filseth asked whether it was possible to use hydroelectric power to match carbon
free energy to load, rather than geothermal.
Abendschein said most of the hydroelectric power was generated during the summer. It was
easier to redispatch on a daily basis than it was on a seasonal basis.
Councilmember Filseth asked whether it was better for electric vehicles to charge during the day
than to charge at night.
Commissioner Schwartz said if the goal was carbon reduction, it might be better to charge electric
vehicles when the renewable energy was being generated. But from a practical standpoint, people
would charge their vehicles when electricity was available. It was possible to set price signals for
charging at specific times, but only if smart meters are available.
Commissioner Ballantine said electric vehicles were very efficient. Even if those vehicles were
charged when there was no renewable energy, and were powered by a gas plant, it would still be
better than using gasoline.
Vice Chair Danaher said Southern California Edison was in the process of changing its time of use
rate structure. He asked whether Palo Alto had a time of use rate structure.
Swaminathan said there was a pilot program to try advanced metering and there was a pi lot time
of use rate associated with that program. He said carbon and price were considerations, but
distribution impacts were also a consideration. It was not a good idea to have people come home
and turn on all of their appliances and also begin charging their vehicles. Nighttime charging had
lower distribution system impacts.
Commissioner Schwartz said education helped people make voluntary choices to charge at the
proper time, even if they were not presented with price signals.
Abendschein said nighttime prices were still lower for energy. It was an open question about
whether to push people to charge at low carbon times or at low price times.
Commissioner Schwartz said that a negative outcome would be to have people charging at the
time they use other appliances and creating new peak demands on the system.
Vice Chair Danaher asked to clarify whether the overall policy goal was electrification, or simply
carbon reduction.
Utilities Advisory Commission Minutes Approved on: Page 9 of 15
Utilities General Manager Ed Shikada said the staff analysis had explored whet her a mandate was
an effective approach to electrification at this time, and had concluded it was not.
Vice Chair Danaher asked whether it would make sense to have customers charge electric vehicles
during the day during the winter if the goal was carbon reduction.
Commissioner Schwartz said it was more complicated than that.
Vice Chair Danaher said it would be worth exploring whether there was a preferable charging time
for electric vehicles that would reduce carbon emissions.
Abendschein said some of these topics had been discussed at the time the Carbon Neutral
Portfolio goal had been adopted. It might be useful to review some of that discussion.
Commissioner Schwartz said it might be helpful to pilot an application showing the real -time
carbon content of Palo Alto’s energy.
Vice Chair Danaher said it would be helpful to discuss the Carbon Neutral Portfolio at a future
time.
Shikada noted staff would be returning the following month to discuss the Sustainability and
Climate Action Plan Implementation Plans, which included electrification.
Commissioner Forssell said the City had achieved carbon neutral energy, which was a real benefit,
but the next step might be to achieve carbon neutral power, where renewable energy and load
were in sync all of the time. She noted the Council had recently made the choice to make the gas
portfolio carbon neutral. She said based on carbo n accounting methods, both gas and electric
energy were carbon neutral, which played into the debate on electrification. She noted there was
not much geothermal energy available anymore. She said electrification was necessary in the long
term, since at some point the renewable energy and loads would be balanced. She thought it was
worthwhile to continue exploring electrification, but it was not something worth mandating at this
point in time. She also noted that it was worth educating customers that the eve ning was not the
right time to charge electric vehicles. The WattTime API could be a helpful tool for creating those
educational tools.
Commissioner Johnston said the proposal was to not look at mandating electrification for five
years. He asked if that was because that was the next time code amendments would be
considered.
Pirnejad said the codes were considered every three years, but five years was an appropriate
amount of time to allow the market to mature.
Commissioner Johnston said he agreed it was premature to mandate this right now, but if the pilot
programs were successful, he asked whether it would be appropriate to reconsider the mandates
earlier than that.
Utilities Advisory Commission Minutes Approved on: Page 10 of 15
Pirnejad said staff’s planned efforts over the next several years on deep energy efficie ncy
improvements in existing buildings, which would mean less energy would be required to heat and
cool them, would make electrification more feasible.
Commissioner Johnston agreed it would be worthwhile to provide more information about the
right time to charge electric vehicles.
Commissioner Trumbull asked whether it was possible to pursue both building and vehicle
electrification at the same time. The discussion tonight seemed to imply there was some tradeoff.
Swaminathan said both could be pursued at the same time. There was more payoff from efforts
spent on vehicle electrification, since the technology was more mature.
Commissioner Trumbull agreed. He said, though, that it did not make sense to focus on exist ing
buildings for electrification. He said he had experienced a similar issue to what Commissioner
Ballantine had experienced with his own heating system. He had gone for several months in the
winter without a heating system since he had a hydronic heating system that broke and could not
find a contractor who knew how to repair it. He agreed the industry needed some experience with
these systems. He thought that five years was too long a time to wait to re -examine the mandate.
He wanted to see it re-examined for the next code cycle. He said fugitive emissions were a big
issue, given what he knew about fracking. He wanted to mandate some type of electrification right
now. He thought the best choice would be new small office construction, which was listed as c ost-
effective in the staff analysis. He said energy usage in these buildings would be more coincident
with afternoon renewable energy generation.
Commissioner Schwartz spoke to something Commissioner Forssell said earlier, that there was not
much geothermal energy available anymore. She said that there was a lot of geothermal energy
yet to be developed in Southern California in Imperial County.
Pirnejad said that small offices were often voluntarily installing heat pumps already, though only a
handful of buildings had been all-electric. To accomplish a mandate in the next code cycle, the
analysis would have to begin in 2018, since the lead time was about 18 months. The analysis was
very involved. This was not enough time for market changes to occur. Staff was open to a mid-
cycle code change if needed, though this was disruptive for contractors, who preferred stability.
Commissioner Schwartz said that a mandate on small businesses would be burdensome.
Councilmember Filseth said he agreed with Commissioner Trumbull’s assessment of the issue of
mandates was a good one. He did not know when the right time for a mandate was, but he
thought that the right way to approach mandates when the time was right was to pick a specific
market segment, as Commissioner Trumbull had suggested, and make the mandate work in that
segment before expanding it.
Vice Chair Danaher said this had been a good discussion. He hoped to hear more about the carbon
content of the electric portfolio in the future, but that he thought tonigh t’s issues had been well
considered.
ACTION: No Action.
Utilities Advisory Commission Minutes Approved on: Page 11 of 15
ITEM 2: ACTION: 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)
Senior Resource Planner Christine Tam provided a summary of the written report. She described
the benefits of cost effective gas energy efficiency (gas EE), which include reducing the City’s
greenhouse gas emissions and lowering the City’s gas supply cost. Since 2008, the City’s annual gas
EE achievements have surpassed the gas EE goals in most years, particularly for years when the
City introduced new programs. For example, savings were high when the Home Energy Report was
introduced in 2011 and when two new commercial EE programs introduced in 2013.
Tam gave an overview of the gas EE modeling framework, and emphasized that the energy savings
mandated through the state’s building and appliance energy standards are excluded in the gas EE
potential. Tam presented the proposed gas EE goals, which were double the previous gas EE goals
adopted by City Council in 2012. However, in the context of therm savings and the achieved gas EE
savings in the past few years, the proposed 2018-2027 goals were aggressive but not unattainable.
Commissioner Schwartz asked why the City needed to be so aggressive with the proposed goals,
given that there were no advanced gas meters to give feedback to residents. In the absence of
better technology, the City might want to pursue simpler approaches to help customers improve
their envelope rather than setting a standard beyond the state’s requirements.
Tam explained that the proposed goals were developed from the gas EE potential model, which
considered gas EE savings that were feasible, cost effective, and took into account th e likely
uptake from customers.
Assistant Director of Resource Management Jonathan Abendschein also pointed out the proposed
goals were in line with historic gas EE savings achieved by the City. He stated that the proposed
goals were aggressive but achievable.
Commissioner Ballantine clarified that with the electric EE goals, as compared to gas EE, there was
a state requirement to pursue aggressive goals.
General Manager Shikada stated there was some desire to accommodate California Energy
Commission (CEC) goals for gas EE and to be consistent with the mission of the Utilities
Department.
Vice Chair Danaher expressed that he had no doubt that there is much efficiency to be gained
given the existing use patterns.
Commissioner Forssell asked for a description of Residential Behavioral measures.
Tam responded that the City launched the Home Energy Report program in 2011, continuously ran
the program for 4 years, and ended the program in 2015. While residents no longer receive the
Home Energy Reports, some of the behavioral savings such as turning off lights and changing the
thermostat setting persist. Staff was developing a new program, the Energy Lottery, which would
encourage residents to reduce their energy usage through a competition, with an attra ctive prize
for the winner. The Energy Lottery covers both electric and gas savings within households.
Utilities Advisory Commission Minutes Approved on: Page 12 of 15
Commissioner Forssell asked for an explanation of RCx, which was mentioned in the slide showing
the composition of gas EE savings.
Tam explained that RCx stands for Retro-commissioning, which are programs where third-party
energy service providers help facility managers optimize the building’s energy management
system, such as to avoid simultaneous heating and cooling.
Commissioner Forssell also asked about what the percentage of gas EE savings relative to load in
the slide “Gas EE goals & Achievement” represented. She clarified that for 2016, the 1% savings
shown does not mean the City’s gas usage went down by 1%, but instead represents predictable
gas savings associated with the installed measures.
Tam confirmed that the 1% represents gas savings attributed to the gas EE programs based on the
type of EE project rather than measured decreases in citywide gas usage , and that the City uses an
EM&V consultant to evaluate and determine that the reported gas savings are real.
Commissioner Johnston asked how much of the goals will be met by existing gas EE programs
versus new programs.
Tam pointed out that some of the EE programs in 2015 have been discontinued. An example is the
New Construction program, which no longer makes sense given the strict energy requirements of
the Green Building Code. In order to meet the aggressive EE goals, the City will need new
programs as well as counting savings from the Green Building Code.
ACTION: Commissioner Ballantine made a motion to recommend Council approval of the
proposed ten-year gas efficiency goals for 2018 to 2027. Commissioner Forssell seconded the
motion. The motion passed unanimously (6-0, with Vice Chair Danaher and Commissioners
Ballantine, Forssell, Johnston, Schwartz, and Trumbull voting yes and Chair Cook absent ).
ITEM 3: ACTION: 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
Acting Senior Resource Planner Eric Keniston gave a presentation on th e financial forecasts for the
water utility. Forecasted rate increases for July 1, 2017 had decreased from 6% to 4% from the last
year’s forecast. Future year rate increases were projected to be roughly 6% per year. Cost
increases by rising wholesale costs due to major capital expenditures for seismic improvements
and rehabilitation to the Hetch Hetchy water system. Expenditures were projected to be lower
than normal in FY 2017 and FY 2018 due to delays in water main replacement investments. This
would result in an increase in reserves, which would allow rate increases to be phased in over
multiple years. Lastly, water demand had decreased during the drought, but with recent
precipitation and an end to mandatory reduction requirements, demand was beginning t o slowly
rise again. It was not clear whether it would return to pre -drought levels. As a result, staff would
recommend removing the drought surcharge.
Utilities Advisory Commission Minutes Approved on: Page 13 of 15
Commissioner Schwartz said it was important to remove the drought surcharge given the recent
precipitation.
Keniston said that even with the 4% rate increase, the removal of the drought surcharge meant
that customers would see an overall decrease in their bills.
ACTION: Commissioner Schwartz moved, seconded by Commissioner Trumbull to recommend that
the City Council adopt the staff recommendation. The motion carried unanimously (6-0, with Vice
Chair Danaher and Commissioners Trumbull, Forssell, Danaher, Schwartz, Ballantine, and Johnston
voting yes and Chair Cook absent).
ITEM 4. ACTION: 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
Acting Senior Resource Planner Eric Keniston presented on the Wastewater Collection Financial
Plan. He said no rate increase was proposed for the Wastewater Collection Utility. Wastewater
collection capital investment was projected to increase in the future, and wastewater treatment
capital investment and operating costs were proje cted to increase in the future.
Commissioner Trumbull noted citizens were voting for a parcel tax to extend the storm drain. He
asked whether that was reflected in the summary of all rate increases shown in the staff
presentation, and what the impact to residential rates would be if the parcel tax were not
approved.
Keniston said that the numbers were provided for context, but staff did not have information on
hand to address the storm drain rate changes.
Assistant Director of Resource Management Jonathan Abendschein said the ballot for the parcel
tax would be the best source of information.
Commissioner Schwartz asked about basement dewatering. The water went to the storm drain.
She asked whether the storm drain parcel tax was linked to the issue of basement dewatering.
Utilities General Manager Ed Shikada said the two issues were not linked.
Commissioner Danaher said the issue had been discussed at a prior meeting.
ACTION: Commissioner Schwartz moved, seconded by Commissioner Ballantine to recommend
that the City Council adopt the staff recommendation. The motion carried unanimously (6-0, with
Vice Chair Danaher and Commissioners Trumbull, Forssell, Danaher, Schwartz, Ballantine, and
Johnston voting yes and Chair Cook absent).
ITEM 5. DISCUSSION: Utilities Strategic Plan Performance Update (Fiscal Year 2016)
Chief Operating Officer Dean Batchelor discussed the current status of progress towards meeting
the performance measures for the current strategic plan. There were twenty-nine performance
measures in the current plan. He focused on the five performance measures were not being met.
An infrastructure backlog still existed. In the electric utility, there were backlogs in underground
rebuilds and conversions, as well as substation impro vements. In the water utility, backlogs had
Utilities Advisory Commission Minutes Approved on: Page 14 of 15
accumulated in part due to delays in renovating the reservoirs. This was due to the fact that they
were in worse condition than had been anticipated at the start of the project, and staff was doing
a study to evaluate changing the project and possibly rebuilding the reservoirs instead of fixing
them. Wastewater projects had been delayed, but they were in progress and would be completed
in 2017. He said service restoration for the electric system did not meet the performance
benchmark in FY 2016. There had been two large outages and more small outages in 2016 as
compared to 2015. Some were related to underground facility failures, and others due to
equipment failures. This was a result of difficulty in retaining experienced electrical linemen and
deterioration of underground facilities. It was challenging because salaries were lower than at
other utilities and the cost of living in the Bay Area was high , meaning many employees commuted
long distances. The long commutes also affected response times. He noted that in FY 2016 electric
utility operational reserves were below minimum guidelines due to decreases in customer sales
and lower hydroelectric generator output that had led to higher energy costs overall . He noted
that customer satisfaction was not meeting the City’s goal of 85% satisfaction, but satisfaction had
increased significantly to 82% from 74% in 2012, and was well above the average for municipal
utilities of 71%. Another benchmark in the strategic plan was how many strategic initiatives in the
Strategic Plan had been completed. Only 17 of 26 strategic initiatives had been completed, and the
goal was 100%. Initiatives not yet completed included developing a smart grid and technology
strategic plan, which was planned for 2018, improving the website, completing a business case and
plan for a water recycling facility, which was commencing in 2017, and developing a plan for a new
electric transmission interconnection, which was an ongoing effort. This effort was stalled, and
staff was looking for other ways to proceed.
Commissioner Schwartz asked if staff was looking at self -service channels for customers to reduce
operational costs as part of the customer website upgrade.
Batchelor acknowledged staff was doing that given the technology savviness of the community.
Staff had installed an Interactive Voice Response (IVR) system, for example.
Commissioner Schwartz asked if staff used the West Alert system.
Batchelor said staff was not aware of it.
Commissioner Schwartz said she would send forward information on an event for utilities at the
end of March. The topic was using these kinds of technologies in ways that measurably improve
customer satisfaction at the operational level.
Commissioner Forssell asked staff to describe the IVR.
Batchelor said it was an interactive voice response system that allowed people to handle routine
business using an automated phone response system, which reduces the number of calls to the
call center.
Commissioner Forssell asked how many reservoirs the City has.
Batchelor stated there were seven reservoirs. The five in the Foothills were the ones that needed
work.
Utilities Advisory Commission Minutes Approved on: Page 15 of 15
Vice Chair Danaher noted it was sometimes good to have a backlog of capital projects to work on
during downturns in the economy when construction costs were lower.
ACTION: No Action.
ITEM 6. DISCUSSION: 2017 Utilities Strategic Plan Update
Shikada gave an update on the 2017 Utilities Strategic Plan. He noted staff had released an RFP to
find a strategic plan consultant. He hoped to have the contract approved in May 2017. He
appreciated the input he had received on potential consultant candid ates. He said the consultant
would support both the plan development and the communication, both internal and external. He
provided a list of topics and an overview of the schedule. He hoped to have a contract ready for
approval in May 2017.
ACTION: No Action.
ITEM 7. ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting
Utilities General Manager Shikada noted staff had anticipated bringing a discussion of Fiber to the
Premise (FTTP) to the March meeting, but staff anticipated taking it to the April meeting instead.
Vice Chair Danaher suggested briefing the UAC over the summer on emerging issues to be
considered as part of the Utilities Strategic Plan. He also suggested a discussion related to the
carbon content of the City’s electricity. He suggested it be discussed at the same time as the Long -
term Energy Acquisition Plan (LEAP) for the electric utility.
Commissioner Schwartz said the April meeting seemed very crowded.
Vice Chair Danaher noted the UAC had moved quickly through the Financial Plans that night and
could perhaps do the same at the following meeting.
Assistant Director of Resource Management Jonathan Abendschein said a number of the items on
the agenda would move quickly.
ACTION: No Action.
Meeting adjourned at 9:48 p.m.
Respectfully Submitted,
Marites Ward
City of Palo Alto Utilities
Page 1 of 9
1
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 5, 2017
SUBJECT: Discussion of Three Utility-Related Sustainability/Climate Action Plan
Implementation Plan Components: Mobility, Efficiency and Electrification, and
Water Management
RECOMMENDATION
Staff requests that the Utilities Advisory Commission (UAC) discuss and provide feedback on
three Utility-related Sustainability/Climate Action Plan (S/CAP) Implementation Plan
components related to Mobility, Efficiency and Electrification, and Water Management.
EXECUTIVE SUMMARY
On April 17, 2017 the Council is scheduled to discuss a proposed implementation plan draft
staff is working to prepare as a follow up to the S/CAP Framework adopted on November 28,
2016.1 At its November meeting the Council directed staff to return with a detailed
Sustainability Implementation Plan (SIP) for various items identified in the S/CAP Framework.
The SIP components most relevant to the City’s utility operations (Mobility, Efficiency and
Electrification, and Water Management) are the focus of this report.
BACKGROUND
On April 18, 2016 the Council first received and discussed the draft S/CAP and unanimously
(8-0) approved the following motions:
A. Adopt a goal of 80% greenhouse gas (GHG) reduction by 2030, calculated utilizing the
1990 baseline;
B. Direct staff to return within two months with a process for integration of the S/CAP with
the Comprehensive Plan Update;
C. Support the general framework of the S/CAP;
D. Support the S/CAP Guiding Principles, which are to be reviewed and formally adopted
within six months.
1 Staff Report 7304 (Discuss and Approve Sustainability and Climate Action Plan (S/CAP) Framework, Principles &
Guidelines), November 28, 2016
Page 2 of 9
On November 28, 2016 the Council discussed the S/CAP Framework and unanimously (9-0)
approved the following motions
A. Adopt the draft Sustainability/Climate Action Plan (S/CAP) Framework, including its
Guiding Principles, Decision Criteria and Design Principles as the road map for
development of a subsequent Sustainability Implementation Plan (SIP); and
B. Direct Staff to return to Council with a Sustainability Implementation Plan; and
C. Direct Staff to make its best effort to incorporate Council Member comments.
In response to these directives, Staff formed seven inter-departmental teams to jointly develop
a “Sustainability Implementation Plan” covering key S/CAP sections: Mobility, Energy, Water,
Zero Waste, Municipal Operations, Adapting to Climate Change and Sea Level Rise, and Natural
Environment.
DISCUSSION
Excerpts from three of the SIP components are included in Attachment A for UAC review:
Mobility, Energy, and Water Management. These proposed SIP components, once finalized and
adopted (including performance of all necessary environmental reviews) are intended to guide
City actions through 2020, at which point new goals would be established. Programs with a “P”
listed next to them will require further program or policy approvals, and those with a “$” next
to them have new funding proposed in the FY 2018 budget. Sustainability office staff intends to
bring summary drafts of the proposed SIPs to Council for discussion and feedback at Council’s
Earth Day meeting. Proposed SIPs will also need to undergo the requisite environmental review
prior to any Council action.
Mobility
As discussed in the S/CAP, 61% of Palo Alto’s emissions come from road travel. As a result,
reducing road travel is a major component of the S/CAP. The S/CAP framework anticipates
achieving reductions through reducing the number of vehicle trips taken in Palo Alto and
decarbonizing the vehicles themselves by encouraging electric vehicle adoption. The mobility
SIP focuses on both types of strategies, but staff is only requesting UAC comment on the utility-
related SIP key actions associated with electric vehicles (EVs):
Mobility SIP Component – Key Actions related to Electric Vehicles
• Promote EV charger installation.
• Evaluate incentives, policies and funding sources to stimulate ownership/use of EVs.
• Encourage local ownership of 3-5,000 EVs by 2020 through programs such as group buys.
Explore ways to reduce process and other barriers (such as fee- and rate-related barriers).
Electric vehicle adoption in Palo Alto has increased substantially in recent years, with an
estimated 2,000 electric vehicles registered in Palo Alto by the end of the 2016. It is estimated
that about 4% of the passenger vehicles registered in Palo Alto are electric vehicles (as
compared to 2% statewide). Though the early adoption lead compared to the state is expected
Page 3 of 9
to decline, the overall adoption rate is currently projected to continue to increase substantially
to between 3,000 and 5,000 EVs by 2020 as the market matures.
A number of efforts are already in place or are on the Utilities Department’s list of initiatives to
explore, to meet the goal of stimulating EV conversion among Palo Alto residents and visitors.
These efforts include:
• Permit process streamlining for Electric Vehicle Supply Equipment (EVSE).
• Ordinances requiring installation of EVSE in all new single-family homes, installation of
one EVSE outlet for every new multi-family residential unit built as well as EVSE in 25%
of guest parking spaces, and requiring that at least 25% of parking spaces for new non-
residential construction be EVSE-ready (conduit installed), with at least 5% of spaces
containing EVSE outlets, and higher requirements for hotels.
• Palo Alto’s partnership with other Bay Area communities to ‘bulk buy’ EVs at
discounted prices.
Staff has implemented or is in the process of implementing a number of additional programs
using resources that are already covered in the current budget and under existing Council
authority, including:
• A pilot Time of Use (TOU) electric rate that encouraged off-peak EV charging that was
coordinated with the Residential CustomerConnect Smart Meter Pilot Program.
• Using Low-Carbon Fuel Standard (LCFS) funds to provide rebates for EV charger
installation in multi-family and non-residential buildings, reduce the impact of
interconnection charges, and fund education, outreach, and pilot programs.2
• Examining ways to reduce fee- and rate-related disincentives to electric vehicle
adoption while ensuring alignment with cost of service principles.
• Working to install City-owned EVSE on four City-owned parking structures in conjunction
with PaloAltoCLEAN solar projects on those structures.3
Other potential programs under consideration would require additional Council approvals,
which may potentially require approval of contracts, budgets, and/or policy. Programs that staff
may consider prior to 2020 include:
• Exploring additional ways, over and above LCFS rebates, to increase the supply of public
charging facilities and overcome hurdles to installing chargers at multi-family dwellings
in Palo Alto.
• Design and implement pricing policies for public EV charging stations.
2 Program adopted March 14, 2016. See Staff Report 6489, Approval of Master Agreement to Sell Low Carbon Fuel
Standards Credits and Utilize the Revenue for the Benefit of Current or Future Electric Vehicle Customers
3 See Staff Report 6535 (Lease Agreement with Komuna Energy), January 25, 2016
Page 4 of 9
• Explore expanding the current TOU rates to all residential customers, including EV
customers, subject to cost of service principles and availability of staffing and
infrastructure to support such an effort.
Existing and planned initiatives identified above were initiated by Utilities based on direction
provided in the Council-adopted electrification work plan, which staff plans to integrate into
the SIPs at the appropriate point in the process.4
Energy
The SIP Energy component covers building efficiency, building electrification, and facilitating
the adoption and integration of distributed generation and other grid-interactive devices
(commonly referred to under the broad term “Distributed Energy Resources” or “DERs”).
Building efficiency and electrification need to be a significant part of achieving carbon emissions
levels 80% lower than 1990 levels. After transportation, which represents 61% of 2015
emissions, the second largest source of emissions in Palo Alto is natural gas use, at 27% of 2015
emissions. This is primarily related to natural gas use in buildings. GHG emission reduction in
this area can be achieved both through more energy efficient buildings and through electrifying
buildings to take advantage of low carbon electricity sources. The pace and timing of
electrification efforts require consideration of the carbon content of the electricity source,
customer impacts and preferences, and market readiness. Through 2020, the City will focus
primarily on building efficiency, while continuing to reduce barriers for voluntary building
electrification.
The focus on building efficiency is primarily reflected in the following SIP measures, though
other SIP measures support efficiency:
Energy SIP Component – Key Actions related to Building Efficiency
• Develop higher local energy efficiency (& Net Zero) standards for new & existing buildings
through codes & standards.
• Develop a post-occupancy regulatory process for commissioning/retro-commissioning, and
energy benchmarking to improve building design, construction, and performance.
• Explore options for using performance requirements and transparency to increase learning
and accountability of building operators; use data driven decision criteria to improve
building performance.
• Develop a Zero Net Energy (ZNE) Roadmap and baseline energy study for existing buildings.
• Implement utility energy efficiency (EE) programs to achieve cumulative electric and gas EE
savings of 2% by 2020.
4 Staff Report 5961, 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,
approved by Council August 17, 2015
Page 5 of 9
These proposed SIP measures are consistent with a variety of programs already being
implemented under existing Council direction:
• The City has adopted local amendments to the Green Building Ordinance and Energy
Code to mandate higher energy efficiency and solar-ready construction for new
construction.
• Utilities staff continues to implement existing gas and electric efficiency programs and is
adding new programs, such as training of building operators.
Staff is exploring additional efficiency programs that will require additional approvals from
Council. For example, Development Services staff is exploring measures to achieve deep
efficiency savings in existing buildings and move toward net-zero-energy building standards.
Utilities Department staff continues to explore new methods of achieving electric and gas
energy efficiency.
To date, the City’s work on electrification has been driven by a Council-adopted work plan5
developed in response to a Council Colleagues Memo.6 Updates on this work plan have been
provided as part of the City’s annual Earth Day report and at other times for specific issues. The
proposed Energy SIP component is consistent with and may eventually subsume elements of
this work plan. SIP items relevant to building electrification include:
Energy SIP Component – Key Actions related to Building Electrification
• Encourage voluntary electrification of natural gas appliances by reducing barriers where
legally and practically possible (processes, fees, financing, regulation, supply chain, and
other costs or secondary disincentives where legally and practically feasible), educate
consumers and contractors, and implementing utility pilot programs (e.g. heat pump
water heaters and space heaters).
So far, the following efforts have been completed or are in progress to implement the
electrification work plan:
• Utilities and Development Services staff worked with the California Energy Commission
(CEC) to reduce or eliminate barriers in the state’s Building Energy Code to installing
heat pump water heaters.
• Development Services staff analyzed the feasibility of mandating electrification in
buildings through local amendments to the Energy Code. Staff found that most potential
electrification measures were not cost-effective using the CEC assessment methodology
5 Staff Report 5961, 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,
approved by Council August 17, 2015
6 December 15, 2014 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
Page 6 of 9
required for such mandates, and that there were significant market barriers that made
mandates imprudent even for cost-effective measures.7
• Utilities staff launched a pilot program to gain experience with heat pump water heaters
and is working to develop a heat pump space heating pilot program. Public outreach
and training workshops are also being planned.
• Utilities staff is collaborating with other groups to advocate before the CEC and the Air
Resource Board for voluntary building electrification as a strategy to meet the state’s
GHG emissions and energy efficiency goals.
Staff intends to explore the following programs, which would require additional Council
approvals, which may potentially require approval of contracts, budgets, and/or policy:
• Try to identify possible funding sources for electrification incentive programs by
exploring the legal and practical aspects of various possible sources. Many available
funding sources are legally restricted in the way they can be used, while others may face
practical barriers.
• Explore further educational and outreach programs to help develop the market for
electrification, and identify effective intervention times (e.g. water heater end of life) for
informational programs.
• Explore ways to reduce fee- and rate-related disincentives to electrification while
ensuring alignment with cost of service principles.
• Explore the feasibility of district heating.
Another component of the efficiency and electrification SIP relates to DERs. The SIP reflects
current and future utility efforts to encourage DERs and configure the distribution system to
enable their integration. Relevant SIP actions include:
Energy SIP Component – Key Actions related to Distributed Energy Resources
• Facilitate the adoption of local distributed energy resources such as PVs, EVs, and storage
and achieve the Local Solar Plan goal of generating 2% of electricity needs locally by 2020
(and 4% by 2023).
• Ensure Utilities Strategic Plan addresses resource needs and business model changes to
implement sustainability initiatives, including adapting to impacts of distributed energy
resources, new technologies, and other changes to the utility service model.
• Complete assessment of smart grid investment merits and long term electric distribution
system investment needs by 2019 to enable energy and electrification goals.
Activities supporting these SIPs will require additional Council approvals, which may potentially
require approval of contracts, budgets, and/or policy. Work efforts in progress include:
7 See March 1, 2017 Utilities Advisory Commission staff report titled 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
Page 7 of 9
• Developing a work plan to reassess the merits of smart grid investment.
• Developing a work plan to assess DER potential and to integrate DERs.
• Taking into account the impacts of DERs, new technologies, and other utility services in
the Utilities Strategic Plan.
• Continuing to implement the Local Solar Plan, including exploring potential projects and
programs like community solar and group buys and taking them for Council approval.
Water Management
While managing water resources has been an important part of resource planning in California
for decades, the past several years of severe drought conditions and this year’s flooding have
highlighted the need to actively engage in water supply reliability projects as well as watershed
protection.
The S/CAP Framework includes goals to reduce water consumption and, as much as possible,
match the right quality of water to the use of that water through a diversified supply portfolio
that includes water reuse. The Framework also recognizes the need to protect our local
watershed including our groundwater aquifer, the bay, marshlands, salt ponds, sloughs and
creeks. Of course, maintaining the City’s urban canopy is also very important.
Palo Alto is already engaged in a variety of valuable water-related initiatives such as water
conservation and education programs, initiatives to reduce the salinity of the City’s recycled
water, source control efforts to reduce storm water pollution, and a comprehensive Recycled
Water Strategic Plan. The 2015 Urban Water Management Plan was approved by City Council in
May 2016 and includes a per capita water use reduction goal of 20% by 2020 from a historical
benchmark period (average use between years 1995 and 2004). The Water Integrated
Resources Plan (WIRP) was recently approved by Council (Staff Report #7634) and provides a
comparative analysis of potable water supply alternatives, including demand side management,
available to the City. Once the Recycled Water Strategic Plan is complete, the WIRP will be
updated with a comprehensive plan for a combined potable and non-potable water supply
portfolio.
The proposed SIP actions also contemplate more work with regard to water. UAC feedback is
requested on several potential new initiatives including:
• Developing programs and a local ordinance (similar to San Francisco’s) that facilitates
the use of non-traditional non-potable water sources (grey, black and storm water) and
another for net zero water construction;
• Developing a Green Storm Water Infrastructure Plan to better capture and infiltrate
storm water back into the hydrologic cycle and integrate with Urban Forestry Plan;
• Investigating innovative ways to increase recycled water use in and outside of Palo Alto;
and
• Evaluating additional replacement of ornamental turf on public right of ways.
Page 8 of 9
Staff plans to request a one-time expense of $140K in the FY2018 budget for consulting costs to
develop programs to encourage the use of non-traditional water supplies. Some of the other
initiatives highlighted as potential actions here will be proposed in the next 3 years and may
require Council approval of additional funds.
NEXT STEPS
The Council is scheduled to review the proposed S/CAP SIPs on April 17, 2017 and provide
comments and feedback. The UAC’s feedback will be provided to Council for that meeting.
Proposed SIPs will also need to undergo the requisite environmental review prior to any Council
action. Staff will continue to implement existing programs and launch new programs described
in the SIP to the extent there is existing authority to implement and no additional contracts,
budget approvals or environmental review is required. Where new authority is needed, staff
will return to the UAC, as appropriate, and to Council for further action. Necessary
environmental review will be completed, as needed prior to any Council action.
RESOURCE IMPACT
The utility-related portions of the proposed SIPs through 2020 will largely be accomplished by
Staff as part of their ongoing job assignments. Where that is not the case, special requests will
be included in budget requests for FYs 2018, 2019 and 2020. A rough representation of
budgeted Utilities staff efforts towards the building efficiency, building electrification, and
vehicle electrification aspects of these SIPs is reflected in Attachment B.
POLICY IMPLICATIONS
The goal of the proposed draft SIP is to implement the policy goals of the previously approved
S/CAP Framework. Projects and goals initiated under a wide variety of other Council-approved
policies or work plans, as well as under State mandates, are, or will eventually be reflected in
the SIP.
ENVIRONMENTAL REVIEW
The UAC’s discussion of the proposed utility-related S/CAP SIP components does not meet the
California Environmental Quality Act’s definition of a project, pursuant to Public Resources
Code Section 21065, thus no environmental review is required. Numerous aspects of the
proposed SIPs will require and undergo environmental review prior to any Council action on
them.
ATTACHMENTS
A. Sustainability Implementation Plans for Mobility, Efficiency and Electrification, and
Water Management
B. Current Utilities Department Salary and Non-Salary Budgeted Resources for SIP
Implementation
PREPARED BY:
~~~
JONATHAN ABENDSCHEIN, Assistant Director, Resource Management
~HIVA SWAMINATHAN, Senior Resource Planner
KARLA DAILEY, Senior Resource Planner
Gil FRIEND, Chief Sustainability Officer
REVIEWED BY:
APPROVED BY:
~~~
JONATHAN ABENDSCHEIN, Assistant Director, Resource Management
~~
EDSHIKADA
Utilities General Manager
Page 9of9
Attachment A
Page 1 of 3
MOBILITY
Road transportation represents about 61% of Palo Alto’s existing carbon footprint – and a congestion
headache. GHG’s are a function of two factors: Vehicle Miles Traveled (VMT), and the carbon intensity
(GHG/VMT). Reducing GHG/VMT is largely driven by Federal Standards, state policy and vehicle offerings
(including fuel efficiency and EVs). However, VMT and EV adoption can be influenced by local programs.
GOALS
Expand mobility alternatives to single-occupancy vehicle (SOV) travel
Create right incentives for mobility
Use balanced development to reduce single-occupancy vehicle (SOV) travel
Reduce carbon intensity of vehicles
NEW/KEY ACTIONS
Increase bicycle boulevard mileage within Palo Alto from 22 to 35 miles (by 2020), consistent
with the City’s adopted Bicycle & Pedestrian Master Plan.
Upgrade Class II bicycle lanes to separated, protected bikeways integrated with bicycle
boulevards where feasible. P
Reestablish and expand citywide bike share program (350 bikes by 2018). P
Consider adopting a carpool matching app/service with City employees serving as initial pilot.
Explore using city vehicles as "ride share" vehicles, and/or contracting with 3rd party for pool
car management.
Consider institution of paid parking at City-owned parking lots and garages, and evaluate
ways to achieve comparable programs at private parking sites; apply net parking revenues to
non-auto alternatives.
Explore ways to extend universal transit passes to residents and employees in transit served
areas. P
Explore housing strategies that reduce auto trips, including mixed use, transportation
demand management programs, trip caps and parking maximums. P
Consider redesigning existing streets to support active and non-SOV transportation modes.
Prioritize traffic signal timing to reduce GHG emissions as well as travel delays.
Promote EV charger installation. P $
Evaluate incentives, policies and funding sources to stimulate ownership/use of EVs. P
Encourage local ownership of 3-5,000 EVs by 2020 through programs such as group buys.
Explore ways to reduce process and other barriers (such as fee- and rate-related barriers).
Develop “mobility as a service” (MaaS) offerings including flexible, responsive services, apps
and commuter programs. P $
Work with other agencies to expand shuttle routes and other transit services so __% of
households are within ½ mile of stops. P $
Continue education and advocacy to achieve a non-SOV mode share of 40-50% for
neighborhood elementary schools and 35-60% for all middle and high schools.
ADDITIONAL RESOURCES PROPOSED FOR FY 2018
Mobility resource requests to come
The mobility marketplace is changing rapidly: Palo Alto has perhaps the highest EV penetration in the
country; US EV sales are increasing 37%/year; “range anxiety” is softening as 200-300 mile range EVs
hit the market this year; Lyft and Uber are growing in significance; Autonomous Vehicles are on the
way. In addition, land use and mobility interact in substantial and complex ways.
Attachment A
Key actions related to transportation demand
management are in draft form and were still under
review at the time of this report. These key actions
will be presented to Council at a later date. Only key
actions related to electric vehicles are shown.
Sustainability Implementation Plan 2017-2020 Page 2 of 3
GOALS
Reduce GHG emissions and energy consumption in buildings
Increase building developer/owner/operator learning and accountability via performance
requirements
Reduce natural gas use in buildings through electrification
Reduce carbon intensity of natural gas use via purchase of carbon off-sets
NEW/KEY ACTIONS
Develop higher local energy efficiency (& Net Zero) standards for new & existing buildings
through codes & standards. P
Develop a post-occupancy regulatory process for commissioning/retro-commissioning, and
energy benchmarking to improve building design, construction, and performance. P
Explore options for using performance requirements and transparency to increase learning
and accountability of building operators; use data driven decision criteria to improve building
performance.
Encourage voluntary electrification of natural gas appliances by reducing barriers where
legally and practically possible (processes, fees, rates, financing, regulation, supply chain,
etc.), educating consumers and contractors, and implementing utility pilot programs (e.g.
heat pump water heaters and space heaters). P
Facilitate the adoption of local distributed energy resources such as PVs, EVs, and storage
and achieve the Local Solar Plan goal of generating 2% of electricity needs locally by 2020
(and 4% by 2023).
Complete assessment of smart grid investment merits and long term electric distribution
system investment needs by 2019 to enable energy and electrification goals. P
Ensure Utilities Strategic Plan addresses resource needs and business model changes to
implement sustainability initiatives, including adapting to impacts of distributed energy
resources, new technologies, and other changes to the utility service model. P
Develop a ZNE Roadmap and baseline energy study for existing buildings. P $
Explore formation of an eco-district complete with a board and participating members. P
Implement utility energy efficiency (EE) programs to achieve cumulative electric and gas EE
savings of 2% by 2020.
Implement natural gas offset program approved by Council (the Carbon Neutral Gas Plan);
prioritize investment in cost-effective local offset projects, where feasible.
ADDITIONAL RESOURCES PROPOSED FOR FY 2018
$49 K one time for ZNE Roadmap.
ENERGY
Efficiency, renewables and electrification are key to Palo Alto’s—and California’s—low carbon energy strategy, but
pace of implementation will depend on technology evolution and cost-effectiveness as well as market acceptance.
Electrification—and encouraging existing buildings to upgrade to modern energy efficiency levels —may pose
significant strategic and operating challenges for the City of Palo Alto Utilities (CPAU).
Emissions from natural gas use represent ~25% of Palo Alto’s remaining carbon footprint. The
decreasing emissions of California and Palo Alto’s energy supply due to renewable energy
opens the opportunity to reduce natural gas use through electrification in addition to
continued efficiency measures. Palo Alto will first seek to reduce natural gas usage through
energy efficiency and conservation, followed by electrification of water heating and space
heating where cost effective.
Attachment A
Sustainability Implementation Plan 2017-2020 Page 3 of 3
GOALS
Reduce consumption
Explore water supply alternatives to ensure the right water quality for each use
Protect creeks, bay, and groundwater
Lead by example
NEW/KEY ACTIONS
Develop a local ordinance (similar to San Francisco’s) that facilitates the use of non-
traditional non-potable water sources such as gray, black, and storm water. P
Develop programs to encourage more use of non-traditional sources of non-potable
water such as gray, black, and storm water. P $
Develop a policy and local ordinance to facilitate water self-sufficient (net zero)
construction. P
Explore building a new or modifying an existing City facility to be water self-sufficient
(net zero). $
Investigate installation of additional trash capture devices in the storm drain system
to improve storm water quality.
Develop a Green Storm Water Infrastructure Plan to better capture and infiltrate
storm water back into the hydrologic cycle and integrate with Urban Forestry Plan. P $
Develop a long-term Water Integrated Resources Plan that includes potable water
alternatives, demand side management, and recycled water. P
Investigate delivery of recycled water to other agencies for non-potable use.
Investigate delivery of raw water to other agencies for further treatment.
Convert ornamental turf on medians and City parks to conserve water use at existing
facilities, following evaluation of costs.
ADDITIONAL RESOURCES PROPOSED FOR FY 2018
$140 K in consultant costs to develop programs to encourage use of non-traditional
sources of non-potable water
$150 K in consultant costs to develop a Green Storm Water Intrastructure Plan
(both are one-time expenses)
WATER MANAGEMENT
Palo Alto has done an outstanding job of meeting annual water use reduction requirements of
the current drought. But both potable water supplies and hydroelectric needs could be
challenged by long-term shifts in California’s precipitation regime. With shifting climate patterns,
and significant long-term water supply uncertainty, it would be prudent to reduce water
consumption while exploring ways to capture and store water, as well as to increase the
availability and use of recycled water.
Perhaps more than most of the other SIP elements, Water Management will require extensive
public engagement, since many people will assume the drought is over, or bristle at rising
water rates as deeper consumption cuts take hold .
Attachment A
Estimate of Relative Efforts Expended by UTL on S/CAP Projects
- Non-Salary Budget/Cost, FTE, and Sources of Funds
Electricity & Natural
Gas Efficiency
Program
Encourage EV
Adoption
Natural Gas Off-
Set Program
Facilitate
adoption of
HPWH/HPSH
Local PV & other
DERs
$3.2Million
4 FTE
Public Benefits
& Supply Funds$0.4Million
1.5 FTE
PB/R&D
$1.3Million
0.05 FTE Supply
Funds
$0.4Million
0.75 FTE
LCFS Funds, grants
$0.2Million
0.6 FTE
PB/R&D, Grants
text
Federal/State Tax Credits,
Regional EVSE grants,
Citywide efforts
ESTIMATED TOTAL EFFORT
$5.5 Million
7 FTE
PB/R&D, Supply, LCFS, Grants, C&T?Note:
UTL Water Related Projects not shown
Does not show Citywide efforts
text
Federal Tax Credits,
Disbursing SB1 rebates
ATTACHMENT B
EVSE: Electric Vehicle Supply Equipment
DER: Distributed Energy Resources
C&T: Cap and Trade
PB: Public Benefits
LCFS: Low Carbon Fuel Standards
HPWH/SH: Heat Pump Water & Space Heater
Page 1 of 12
2
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 5, 2017
SUBJECT: Utilities Advisory Commission Recommendation that Council Approve a
Recommendation Concerning: (1) Future Plans for Fiber and Broadband
Expansion; and (2) Expand Wi-Fi to Unserved City Facilities; and
Discontinue Consideration of City-Provided Wi-Fi in Commercial Areas
Recommendation
Staff requests that the Utilities Advisory Commission (UAC) recommend that the City Council
approve one of the following three options for the City’s fiber-optic utility:
OPTION 1. Municipally-Owned Fiber-to-the-Premises (FTTP). Explore potential funding
models, such as general obligation bonds requiring a ballot measure with two-
thirds voter approval, or revenue bonds secured by ongoing dark fiber license
revenues and fiber reserves, to build and maintain a ubiquitous, municipally-
owned Fiber-to-the-Premises network; or
OPTION 2. Municipally-Owned Fiber-to-the-Node (FTTN) Network with
Neighborhood/Private Last Mile Provision. Explore design of a Fiber-to-the-
Node network, which may be a platform for Public Safety and Utilities wireless
communication in the field, Smart Grid and Smart City applications, new dark
fiber licensing opportunities; in addition, explore alternative “last mile” funding
models for Fiber-to-the-Premises, including user-financing, creating
Assessment Districts, Mello-Roos/Community Facilities Districts and/or public-
private partnerships; or
OPTION 3. Pause Municipal FTTP Development Efforts; Increase Transparency and
Predictability for Third Party Providers. Direct staff to identify additional
resources and opportunities to assist Internet service providers committed to
deploying gigabit-speed broadband service; in addition, pause internal efforts
to pursue municipal FTTP as the telecommunications industry and associated
technologies rapidly evolve.
Staff’s subsequent exploration would include a more specific analysis of the costs, business
justifications and needs, as well as the legal and practical feasibility of the selected option.
Page 2 of 12
Staff also requests that the Utilities Advisory Commission (UAC) recommend that the City Council
approve the following two recommendations for wireless expansion:
Expand the City’s OverAir Wi-Fi Hotspots to unserved City facilities and request that Council
approve an estimated $165,100 for one-time equipment and installation costs funded by
the Fiber-Optic Fund and allocation of monthly recurring charges of approximately $6,239
to the General Fund; and
Discontinue consideration of building a City-provided public Wi-Fi network in high traffic
commercial areas.
Executive Summary
Fiber Utility
Given the increasingly competitive telecommunications landscape, including new hybrid
fiber/wireless technologies and emerging services and applications requiring access to networks
capable of gigabit-speeds and beyond, staff recommends pursuing one of three identified
incremental approaches to fiber-optic expansion. Staff is requesting feedback, direction and a
recommendation for approval by Council to direct staff work concerning the fiber utility for the
next twenty-four (24) months to best facilitate citywide access to gigabit-speed broadband
services. Staff requests that the UAC select one of the three options proposed above for approval
by Council.
Option #1 (Municipally-Owned FTTP) proposes exploration of different funding models to
raise the $50 million to $78 million staff estimates is necessary to build a municipally-
owned FTTP network.
Option #2 (Municipally-Owned FTTN, with Neighborhood/Private Last Mile Provision)
proposes exploration of a design of a FTTN network with an estimated build-out cost
between $12 million to $15 million, in addition to evaluating alternative funding models
and approaches to build the “last mile” to the premise.1
Option #3 (Pause Municipal FTTP Efforts; Increase Transparency and Predictability for Third
Party Providers) proposes to identify resources and opportunities to better support third-
party network upgrades and pause internal efforts for municipal FTTP.
Wireless Deployment
With respect to wireless deployment, staff recommends expanding the City’s existing Wi-Fi service
to unserved City facilities such as the Cubberley Community Center, Palo Alto Municipal Golf
Course, Lucie Stern Community Center and Lytton Plaza. However, staff does not recommend
pursuing deployment of City-provided public Wi-Fi connectivity in high traffic commercial areas
such as University Avenue and California Avenue.
Background
The dark fiber optic backbone network (“fiber network”) was originally conceived by the City in the
mid-1990s and is maintained and operated by City of Palo Alto Utilities (“CPAU”). Exhibit A – Fiber
1 FTTN is one of several options for providing fiber cable telecommunications services to multiple neighborhood access
points. FTTN helps to provide broadband connections and other data services through a common network box, which is
often called a node. The node provides a neighborhood access point to build out the so -called “last mile” to deliver
services to the customer premise. The last mile is typically the most expensive portion to build in a FTTP network. Fiber-
to the-Node is also called “Fiber-to-the-Neighborhood.”
Page 3 of 12
History and Initiatives provides a comprehensive history of various efforts to expand the network
from 1996 to the present. The most recent activities under the Council’s “Technology and the
Connected City” initiative involved the preparation of a Fiber-to-the-Premises Master Plan (“FTTP
Master Plan”) and a Wireless Network Plan, in addition to working with Google Fiber for more than
two years on a potential citywide FTTP network build. The FTTP Master Plan and Wireless Network
Plan were prepared by the City’s consultant, CTC Technology & Energy (“CTC”). Staff has also
worked closely with a Citizen Advisory Committee (“CAC”) since 2014 on various fiber and wireless
issues. The CAC was recently expanded from six to eleven members. The committee meets
approximately every two months and has provided valuable feedback and guidance to City staff.
Since the FTTP Master Plan and Wireless Network Plan were completed and reviewed by the
Council in September 2015, staff has worked to complete the various tasks in the Council’s
September 28, 2015 (staff report #6104) and November 30, 2015 (staff report #6301) motions. The
status of the Council motion items can be found in Exhibit B – Council Motion Status. In the past
year, the competitive landscape in the industry has changed dramatically throughout the country,
including Palo Alto. The most significant change affecting Palo Alto occurred in July 2016, when
Google Fiber advised staff that it was “pausing” its plans to build a fiber-optic network in Silicon
Valley and other cities where construction had not yet started. Other significant changes include
upgrades to existing wired and wireless networks by AT&T Fiber, Comcast, AT&T Mobility and
Verizon Wireless.
At the November 2, 2016 UAC meeting, staff reviewed several elements of the above-noted
recommendations and provided other information related to network and service improvements
by AT&T Fiber, Comcast and the wireless carriers, in addition to the status of Google Fiber.
Information was also provided about the responses to the Request for Information (“RFI”) for a
partnership for deployment of a citywide FTTP network issued in May 2016. Staff reported that
none of the responses to the RFI completely aligned with the City’s objective for a public-private
partnership. Commissioners provided feedback and suggestions which includes incentivizing the
incumbents to accelerate their network upgrades while providing ubiquitous coverage and
identifying the public benefits of a municipally-owned fiber network. (Exhibit C – Excerpted Final
UAC Minutes of November 2, 2016).
At the November UAC meeting, City Manager James Keene observed that an incremental Fiber-to-
the-Node (“FTTN”) approach has potential because of the need to reinvest in the fiber network and
the cost is manageable. The fiber ring could be expanded in a way to stay competitive. For
example, the fiber network was extended to the school district and there may be other
opportunistic expansions. Also, since staff does not exactly know now where the technology is
headed for fiber and wireless deployments, FTTN may be back-filler for fiber backhaul
opportunities to support ubiquity and possibly facilitate future 5G services.2
In light of the rapidly evolving dynamics in the private marketplace, and the varied community
interest in both private and municipal deployment of fiber in Palo Alto, City staff has attempted to
pursue and keep all options open in a preliminary manner. Nonetheless, this staff report is
designed to allow the UAC to recommend that Council select one of the three options to direct
staff to focus on a single effort over the next 24 months.
2 5th generation mobile networks or 5th generation wireless systems, abbreviated 5G, are the proposed next
telecommunications standards beyond the current 4G/IMT-Advanced standards.
Page 4 of 12
On December 12, 2016, staff provided Council with an informational update regarding fiber and
wireless activities (Staff report #6221):
http://www.cityofpaloalto.org/civicax/filebank/documents/55016
Discussion
FIBER UTILITY
Option 1: Municipally-Owned Fiber-to-the-Premises (FTTP).
The 2015 FTTP Master Plan indicated that the City will require an estimated overall capital
investment of approximately $78 million one-time cost to build and approximately $8 million
annually to operate and maintain the network. The estimated network construction and operating
costs are subject to change based on real-world variables.
Certain challenges inherent to FTTP deployment are especially pronounced in the Palo Alto. The
City’s primary challenge in its pursuit of an FTTP buildout is that its costs will be high compared to
other metropolitan areas for labor and materials. The cost of outside plant (“OSP”)3 and drop
cables4 will be greater than in other metropolitan areas because Bay Area costs tend to be higher.
Additionally, many of the easements where the City must build are privately owned, which may
require every drop cable to be placed in conduit. Additionally, many back yard poles in private
easements will need to be replaced, because they’re too short for new fiber-optic attachments.
The high construction and labor costs result in a higher necessary take rate for the City’s FTTP
enterprise to obtain and maintain positive cash flow. Based on the financial projections (and the
underlying assumptions), a 72 percent take rate is required to financially sustain the network. This
is not only much higher than overbuilders5 have been able to achieve in other communities, but
also higher than the required take rates for other potential municipal fiber enterprises. As a
comparison, other recent analyses performed by CTC for municipalities have shown a required take
rate in the mid-40 percent range in order to maintain positive cash flow.
In the FTTP Master Plan, CTC provided an analysis of potential funding models. A key consideration
for network implementation is how to fund both capital construction costs and ongoing operational
expenses. The importance of factoring in the ongoing cost of operations cannot be overstated;
these expenses fluctuate based on the success of the enterprise, and can vary considerably each
year, and even month to month. The capital and operating costs associated with a full-scale
communitywide build-out will be significant, and the City will have to seek a combination of outside
funding, internal subsidies, and/or other financing alternatives such as user-financing, creating
Assessment Districts or finding a private sector partner to provide additional funding to support
construction and the FTTP network’s startup costs. Each of these potential funding mechanisms
would require a more detailed legal and practical feasibility analysis, should UAC and Council elect
to pursue this option. It’s important to note, however, that some private entities involved in
financing and building municipal broadband networks may require an ownership stake to secure
loans from the private lending markets.
3 OSP is physical assets like overhead and underground fiber, accompanying ducts and splice cases, and other network
components
4 Drop cables connect the fiber optic backbone to the customer premises.
5 An “overbuilder” is a private entity or a government entity that builds a new network in the public rights-of-way that
will operate and compete with existing networks already built by the cable TV and telecom incumbents.
Page 5 of 12
Examples of potential financing models are bond issuances, City subsidies and loans, user-financing
and Assessment Districts. Municipalities typically rely on General Obligation Bond and Revenue
Bond issuances for capital projects; therefore, the City may be able to issue a bond (i.e., borrow
funds) to enable construction of an FTTP network.
General Obligation (“GO”) bonds are directly tied to the City’s credit rating and ability to tax its
citizens. This type of bond is not related to any direct revenues from specific projects, but is
connected instead to citywide taxes and revenues that can be used to repay this debt. GO bonds
can be politically challenging, because it requires approval by two-thirds of the voters. Because GO
bonds can only be used for physical improvements and not for services, they are generally issued
for projects such as libraries, museums, community centers, schools, public parks, roadways and
other infrastructure improvements.
Revenue bonds are directly tied to a specific revenue source to secure the bond and guarantee
repayment of the debt. As of June 30, 2016, the Fiber Optic Fund has accumulated approximately
$25 million dollars in reserves. The Fiber Optic Fund currently generates a positive net income
between $2.5 million to $3.0 million annually depending on the level of capital improvement
activity.
In addition to funding the construction cost, it is also possible that ongoing internal subsidies from
other City funds will be necessary to support regular operations if customer take rates are not
sufficient. Examples of these operational costs include network equipment license fees, ongoing
hardware and software replenishments, labor-intensive customer support, customer acquisition
costs, and network maintenance.
Option 2: Municipally-Owned Fiber-to-the-Node (FTTN) Network with Neighborhood/Private Last
Mile Provision.
To evaluate a potential incremental step for citywide FTTP, staff worked with CTC to develop a
preliminary, high-level analysis of the cost to build a FTTN network.6 A FTTN network would
require construction of approximately 62 miles of fiber plant, compared to 230 miles for a citywide
FTTP network deployment. The FTTN network would provide an access point to connect
neighborhood-area backhaul communications links.7 Building a FTTN network would be an
incremental approach for fiber expansion and may lower the barriers for potential FTTP providers
to build the “last mile” from neighborhood access nodes to individual premises. FTTN would
provide the City with a phased and economically viable deployment approach to push fiber closer
to residential neighborhoods and create a potential “jumping off point” to bring fiber to individual
premises (i.e. building the “last mile”). Ancillary benefits would also occur by expanding the
functionality and the choices of technology that can be implemented for Utilities and Public Safety
and to support Smart City, Smart Grid and wireless applications dependent on fiber-optic
communication links. Additional opportunities to license dark fiber for commercial purposes may
also develop.
6 CTC advises that there are variations of the concept of building some subset of the p hysical plant to entice
private investment. For example, Lincoln, NE used 300 miles of conduit to attract an FTTP provider. Holly
Springs, NC built a middle-mile fiber network to serve their own town sites, but designed it specifically with
capacity and other attributes intended to make it attractive as a backbone for FTTP. This attracted Ting
Internet, who is leasing large quantities of fiber strands (144-count) throughout Holly Spring’s approximately
20 mile backbone.
7 Backhaul communications fiber links are required to transmit data back to a network backbone or central
office.
Page 6 of 12
If fiber was expanded to residential neighborhoods, it would be available to the wireless carriers
who need to build small cell sites in not just commercial areas, but also in residential areas to
improve coverage and capacity for their networks. This is known as “network densification.” These
small cell sites, located primarily on utility and streetlight poles in the public rights-of-way, will
need to be connected to fiber to “backhaul” traffic to a central point in a wireless carrier’s network.
The carriers can build this fiber themselves, but if City fiber is available it could be licensed to the
carriers at a more expedient and cost-effective manner. According to RCR Wireless News, fiber is
expected to be a significant focus on planned 5G network deployments. Similar to 3G and 4G
before it, 5G is the “next generation” of wireless connectivity built specifically to keep up with the
proliferation of devices that need a mobile Internet connection, connecting not just a smartphone
and computer, but home appliances, door locks, security cameras, cars, wearables, and many other
inert devices beginning to connect to the web. This is commonly known as the “Internet of Things”
(“IoT”). In effect, these dark fiber licensing opportunities for the wireless carriers and builders of
shared wireless infrastructure may facilitate a new opportunity to increase revenues under the
existing business model. Additionally, this expansion could also create a communications platform
for Smart City and Smart Grid applications, especially for communication with utility meters,
streetlights, parking, traffic and City news.
The following is a high-level breakdown of the FTTN cost components and total estimated network
costs provided by CTC:
Cost Components Total Estimated Costs
Outside Plant (OSP Engineering) $1,110,000
Quality Control/Quality Assurance 290,000
General OSP Construction Cost 7,110,000
Special Crossings 150,000
Backbone & Distribution Plant Splicing 310,000
Backbone Hub, Termination & Testing 2,410,000
Drop Connections (Tap to WAP) 45,000
Total Estimated Cost
*This estimate does not include any of the network electronics,
wireless or otherwise
$11,425,000
The $11.4 million estimate is within the capacity of the existing $25 million Fiber Fund reserves. At
this time, staff does not know the ongoing costs to operate and maintain a FTTN network since its
contingent on the use(s) of the network.
Under Option 2, staff would likely issue a competitive solicitation(s) for a FTTN design and
concurrently evaluate other last mile funding models to pay for the connections between
Page 7 of 12
neighborhood nodes and homes and businesses. If a certain level of interest is met and property
owners are willing to pay for the connections, fiber and/or wireless technologies could be deployed
to deliver faster broadband services. Potential funding models for the “Last Mile” include:
User-Financing. User-financing which relies on homeowners to pay on a voluntary basis
for some or all of the cost to build-out the City’s existing dark fiber backbone network into
residential neighborhoods. Homeowners would voluntarily finance system build-out costs
by paying a one-time upfront connection fee that could range from $500 to $5,000, or
more. The City would provide a wholesale transport-only service to one or more ISP on an
“open access” basis and the homeowner would directly pay the ISP for Internet
connectivity. The City would be responsible for building and maintaining the core network
while leaving customer service, provisioning, technical support and billing to the ISP.
Property owners could self-organize, or a third party could potentially facilitate
neighborhood participation, or the City could facilitate the formation of Community
Facilities Districts or Assessment Districts.
Assessment Districts; Mello-Roos/Community Facilities Districts (CFDs). City staff could
also explore using Assessment Districts or CFDs to fund Last Mile development. Depending
on UAC and Council interest, using this approach for fiber buildout would be novel and
would require more study to determine whether such districts could be structured in such
a way that would be both practically and administratively feasible and also adhere to all
applicable legal requirements, including statutory requirements for establishing
assessment districts in a charter city and constitutional requirements such as Proposition
218.
Assessment Districts may be used to finance new public improvements or other additions
to the community. Generally speaking, an Assessment District is formed with property
owner mail ballot proceedings involving each property that will be assessed in the district.
Owners vote yes or no, and votes are weighted by the assessed amount. In order for an
assessment to be levied, no votes may not exceed yes votes. Assessment districts are still
subject to Proposition 218, which requires identification of special rather than general
benefit.
Under the Mello-Roos Community Facilities Act of 1982 (Gov. Code §§ 53311, et seq.),
cities and other local government agencies can form a community facilities district to
finance certain facilities and services. These districts can levy a special tax, and issue bonds
secured by that tax, upon approval by two-thirds of the registered voters or property
owners within the district.
Public-Private Partnership for Last Mile Expansion. Explore the potential for a public-
private partnership, where the City and a private entity work together to achieve mutual
goals for an FTTP network. In light of the high cost to build and the extremely high required
take rate, it may seem that there is little incentive for any provider (public or private) to
pursue an FTTP deployment in Palo Alto. A private entity and a public entity could
complement one another by developing a partnership that can take advantage of each
entity’s strengths, which may significantly reduce cost and risk. While this model is newly
emerging, engaging a private partner may enable the City to take advantage of
opportunities to mitigate risk and maximize opportunity. The public and private sectors
each have unique advantages and disadvantages that may impact their ability to undertake
a standalone overbuild.
Page 8 of 12
Option 3. Pause Municipal FTTP Development Efforts; Increase Transparency and Predictability
for Third Party Providers.
In light of the aggressive upgrade plans by the incumbents and the development of emerging
technologies such as gigabit-speed fixed wireless and 5G that will significantly enhance the delivery
of consumer and business broadband services, another potential option is pausing any further
municipal FTTP development efforts at this time. Obtaining viable market share and acquiring new
customers is necessary to financially sustain a City FTTP offering.
A new City FTTP network would compete directly with existing local incumbent cable, telco, and
other Internet service providers (ISPs) to offer services to customers. Generally, fiber overbuilds do
not offer a high rate of return, which is why there are not many private sector providers seeking to
build fiber networks in markets where customers are already served. The likelihood that a
municipally-owned FTTP network could be financially viable is doubtful, unless the City was willing
to subsidize the network indefinitely, or if one of the aforementioned funding approaches was
feasible, or if a partner from the private sector was willing to assume a portion of the financial risk.
The ability of the City to acquire more than 70 percent market share on its own is highly unlikely,
thus the financial risk would be very high. In the FTTP Master Plan a market assessment report was
provided in an appendix. This market assessment provides an overview of providers that currently
offer services with which the City’s potential new fiber-to-the-premises (FTTP) enterprise might
compete (Exhibit D – Palo Alto Existing Market Assessment). The City’s existing dark fiber
enterprise is viable, because it is a niche service with little or no competition. Nonetheless, success
in providing commercial dark fiber does not translate into a feasible business case for the City to
enter a very competitive industry.
In the interest of improving broadband in Palo Alto and based on the concerns noted above,
another approach is to identify resources and improve coordination of City policies and processes
to facilitate network upgrades by third-parties such as AT&T, Comcast and other wired and wireless
ISPs. This will enhance transparency and predictability for third party providers. Municipal
strategies that advance broadband deployment can be grouped into three general categories: (1)
ways to facilitate access to key assets such as fiber, conduit, utility poles, and real estate; (2) ways
to make useful information available to potential broadband service providers; and (3) ways to
streamline and publicize local processes.
Access by third-parties to infrastructure data and assets such as poles, conduits and rights-of-ways
is essential to encouraging broadband improvements. Ensuring efficient and predictable processes
that enhance deployments is equally important, as with any public project. According to a study
published by CTC in 2014,8 local governments balance the needs of broadband providers with the
public cost of the processes necessary to support them and with other priorities that clamor for the
same resources. To balance these competing interests, local processes such as permitting and
inspection can be formalized and publicized. Timelines can be determined based on local needs,
publicized, and then met. Transparency about processes and timelines enables broadband
companies to expeditiously plan and deploy networks, enabling localities to manage the costs and
burdens of the processes necessary to meet broadband providers’ needs.
8 GIGABIT COMMUNITIES - Technical Strategies for Facilitating Public or Private Broadband Construction
in Your Community
http://www.ctcnet.us/wp-content/uploads/2014/01/GigabitCommunities.pdf
Page 9 of 12
The City and broadband providers can cooperatively plan before construction so as to understand
respective schedules and needs, and so that the provider can plan to stage its work around known
and predictable local processes. In order to implement these strategies, staff will need to identify
additional internal and/or external resources to better facilitate planning approvals, environmental
reviews, permitting, inspections and legal reviews. The work to identify resources was well
underway when staff was working with Google Fiber to manage the anticipated large volume of
activities to build a fiber-optic network in Palo Alto.
In relation to the Google Fiber effort, the City Attorney’s Office, Development Center, Public Works,
Planning & Community Environment and Utilities reviewed multiple City policies, practices and
procedures to accommodate these activities. The Google Fiber City Checklist process, which
required all of the above-mentioned departments to work in concert to identify information about
existing infrastructure (e.g. utility poles and available conduit), review various policies and
procedures to facilitate access to the public rights-of-way and utility poles, in addition to reviewing
infrastructure data such as utility routes to make construction speedy and predictable. An example
of this staff review is the “pole intent process” required to manage hundreds of applications to
attach fiber-optic cables and other equipment to utility poles jointly-owned by the City and AT&T.
Another example was a review of construction methods and various construction constraints to
ensure the integrity of the public rights-of-ways and street conditions that would be significantly
impacted by large scale excavations and directional boring required to lay new conduit and fiber-
optic cables in the public rights-of-way, in addition to placing thousands of below-grade vaults
citywide.
The following includes information about current and upcoming third-party upgrades:
AT&T Fiber (formerly GigaPower) plans to install new cabinets next to existing U-verse
cabinets in order to provide gigabit-speed broadband services to the community. AT&T
plans to select neighborhoods with high potential for adoption and will use consumer
demand levels to determine further deployments in the city.
Comcast plans a soft launch of DOCSIS 3.1 technology in the second quarter of 2017 to
offer multi-gigabit service to its residential customers. Data over Cable Service Interface
Specification (“DOCSIS”) is an international telecommunications standard that permits the
addition of high-bandwidth data transfer to an existing cable TV system. DOCSIS technology
is employed by many cable television operators to provide Internet access over their
existing hybrid fiber-coaxial (HFC) infrastructure. DOCSIS 1.0 was released in 1997. The
most recent version of DOCSIS (3.1) was released in 2014. The DOCSIS 3.1 specification
supports Internet speeds of 10 Gigabits per second (Gbps) for downloads downstream and
1Gbps upstream - the level of speeds typically only available with a fiber optic connection.
For business services, bandwidth will be scalable from 1 Mbps to 10 Gbps, and as high as
100 Gbps if specific criteria are met. Comcast also currently offers a 2 Gbps broadband
service called Gigabit Pro when certain conditions are met.
Other Telecommunication Service Providers: Several wireless carriers and builders of
shared infrastructure for the cellular industry are seeking to deploy new communication
facilities such as distributed antenna systems (“DAS”) and small cell technologies in Palo
Alto. In the past few years, AT&T Mobility and Crown Castle have deployed approximately
ninety-five (95) DAS and small cell sites in several areas of the city to improve the coverage
and capacity of the carriers’ mobile networks. These facilities are typically located on City-
owned utility poles and streetlight poles in the public rights-of-way. More deployments are
Page 10 of 12
planned by AT&T Mobility (16 small cell installations), Verizon Wireless (92 small cell
installations) and other carriers, in addition to the builders of shared wireless infrastructure
such as Crown Castle (16 small cell installations to add to the 19 small cell sites built in the
downtown area in 2016).
WIRELESS DEPLOYMENT
The expansion of Wi-Fi technology at unserved City facilities and public areas was evaluated with
the Community Services Department (“CSD”). Most City facilities already have Wi-Fi access
(“OverAir Wi-Fi Hotspot”). The outcome of the evaluation reflected concern from CSD regarding the
deployment of Wi-Fi at Rinconada Pool and City parks due to safety concerns. The potential for
distracted parents in the areas of the City where parents are expected to supervise their children is
the primary concern. In addition to potential safety concerns, parks and other open spaces provide
an important respite from technology, a place to “unplug” and focus on spending time with family
and friends and to connect with the outdoors and nature.
The areas of the City where CSD recommends Wi-Fi deployment are at common areas in Cubberley,
Lucie Stern, the Golf Course Pro Shop and Cafe, and Lytton Plaza. A high-level cost estimate for the
recommended sites is $165,100 for installation and $6,239 for monthly recurring charges. Exhibit E
– Wi-Fi CSD Site Summary provides estimated costs of the individual sites.
Multiple interviews conducted during the assessment for the Wireless Network Plan indicated
there have been no specific requests from the business community or the general public for Wi-Fi
services in high traffic commercial areas. A significant number of Palo Alto businesses already offer
free Wi-Fi service to patrons as an amenity. Additionally, companies such as AT&T and Comcast
have installed and operate Wi-Fi access points for their customers in many areas of the City and are
planning upgrades to these services in 2017.
It should be noted, too, that other cities’ implementations of municipal Wi-Fi services generally did
not develop the anticipated level of acceptance. Part of the problem with those deployments was
related to the speed and reliability of earlier Wi-Fi technology compared to commercial wireless
options. In the same timeframe that those cities implemented municipal Wi-Fi, the commercial
wireless carriers successfully deployed 3G and 4G data access technologies that have develo ped a
high degree of consumer acceptance based on cost, performance, and the convenience of
essentially universal service. In contrast, many municipal Wi-Fi deployments served only a limited
area and performance in many cases fell short of user expectations.
Ongoing Initiatives
Fiber Network Rebuild Project
In fiscal year 2016, the City established a new capital improvement project, Fiber Optic System
Rebuild (CIP FO-16000), to rebuild portions of the dark fiber network for improved reliability and
increased capacity. The rebuild project will install new aerial duct or substructures (conduit and
boxes) and additional fiber backbone cable to increase capacity for sections of the dark fiber ring
that are at or near capacity and allows CPAU to meet commercial customer requests for service.
See Exhibit F - Fiber Optic Network Rebuild Project for project description and current status.
In the FTTP Master Plan, CTC noted that it’s important to recognize that the rebuild reinvestment
does not increase the attractiveness of the fiber to encourage a partner to build FTTP. The current
commercial dark fiber reach would be a relatively small portion of the total FTTP investment, and a
citywide FTTP endeavor will likely benefit little from commercial dark fiber expansion.
Page 11 of 12
Dig Once
The Council’s September 28, 2015 Motion directed staff to develop a “dig once” ordinance. The
basic objective of dig once is to promote broadband by lowering the cost of building infrastructure
by making it unnecessary to tear up the streets every time a company wants to reach new homes
with its underground network. In the above-noted informational update provided to the Council
on December 12, 2016, staff provided a summary of the issues related to developing an ordinance
or policy in view of the changes nationwide and in Palo Alto with the third party
telecommunications providers. The assumption in 2015 was that the City should actively
encourage or require simultaneous underground construction and co-location of broadband
infrastructure in the public rights-of-way with the intention of creating benefits for both the City
and private sector communications providers. Establishing a dig once policy may reduce the long-
term cost of building communications facilities by capitalizing on significant economies of scale as
outlined in the informational update.
At this time, telecommunications providers are not proposing the same citywide, large scale
excavations or builds that the City was anticipating back in 2015 with a Google Fiber build. Instead,
with Google Fiber’s reorganization and apparent retreat from a comprehensive infrastructure build,
the City is finding that incumbent telecommunications providers are more inclined to explore
incremental expansions or, where the scope of a project is larger, above ground builds on utility
poles. As a result, staff is reevaluating the approach to dig once and has met with AT&T, Comcast
and other companies that may propose large scale excavation projects in the future. These
discussions are ongoing. Staff is also reviewing existing Municipal Code provisions governing Third
Party Coordination in the public rights-of-ways and Joint Trench Coordination in Underground
Districts, including specifically an assessment of how cross-departmental teams (Utilities, Public
Works, Development Center and Planning) currently work together on both City-initiated and third
party infrastructure projects to determine if there are other joint opportunities for streamlining
and improvement.
RESOURCE IMPACT
Depending on the option selected for fiber and broadband expansion, staff will develop cost
estimates and work plan and return to Council for approval.
An estimated $165,100 for one-time equipment and installation costs and monthly recurring
charges of $6,239 are required to expand Wi-Fi in unserved City facilities. Funding is available in
the FY 2017 operating and capital budgets for the Fiber Fund for the contract amendment and one -
time installation fees. The monthly recurring charges will be allocated to the respective
departments consistent with the City’s existing chargeback model.
POLICY IMPLICATIONS
The fiber and wireless activities are consistent with the Telecommunications Policy adopted by the
Council in 1997, to facilitate advanced telecommunications services in Palo Alto in an
environmentally sound manner (Reference CMR: 369:97- Proposed Telecommunications Policy
Statements).
ENVIRONMENTAL REVIEW
The UAC’s recommendation that Council approve fiber utility and wireless deployment
recommendations is exempt from the California Environmental Quality Act (“CEQA”) under section
15262 (Feasibility and Planning Studies for possible future action) and section 15301 (Negligible
Expansion of Existing Facilities}. Necessary environmental review will be performed in advance of
any Council action, including approvals, adoptions or funding where required.
PREPARED BY:
REVIEWED BY: J I
DEPARTMENT HEAD:
ATTACHMENTS:
JIM FLEMING, Senior Management Analyst
TODD HENDERSON, Senior Technologist
DAVE YUAN, Strategic Business Manager
JONATHAN REICHENTAL, Chief Information Officer
c:!~·
ED SHIKADA
Utilities General Manager
Exhibit A-Fiber History and Initiatives
Exhibit B -Council Motion Status
Exhibit C-Excerpted Final UAC Minutes of November 2, 2016
Exhibit D -Palo Alto Existing Market Assessment
Exhibit E-Wi-Fi CSD Site Summary
Exhibit F -Fiber Optic Network Rebuild Project
Page 12of12
Fiber-to-Fiber Premises and Wireless Communication Initiative Page 1 of 5 Date Last Updated 02/04/17
HISTORY OF THE CITY OF PALO ALTO DARK FIBER OPTIC BACKBONE NETWORK
FIBER‐TO‐THE‐PREMISES AND WIRELESS COMMUNICATIONS INITIATIVES
This document is intended to provide a summary of the highlights of the City’s dark fiber optic backbone network, in
addition to various initiatives to expand the network for citywide fiber‐to‐the‐premises and wireless services.
City of Palo Alto Dark Fiber Optic Backbone Network
The dark fiber optic backbone network (“fiber network”) was originally conceived by the City in the mid‐1990s and is
maintained and operated by City of Palo Alto Utilities (“CPAU”). The City’s initial telecommunications strategy was to build
a dark fiber ring around Palo Alto that would be “capable of supporting multiple network developers and/or service
providers with significant growth potential.” In the mid‐1990s, most investor‐owned and public utilities invested in fiber
optics to improve command and control of their utility infrastructure. Many of these networks typically had excess
capacity that could be licensed or leased to third parties.
The first phase of the fiber backbone construction occurred in 1996‐1997. The initial portions of the network were
constructed in a backbone ring architecture in existing utility rights‐of‐way. The fiber backbone was routed to pass and
provide access to key City facilities and offices. The majority of the City’s business parks (e.g. Stanford Research Park) and
commercial properties are also passed by the fiber backbone. The original fiber backbone consisted of 33 route miles with
144 or more strands of single‐mode fiber along most routes. Since the late 1990s, the fiber backbone has been expanded
to approximately 49 route miles of mostly 144‐ or 288‐count single‐mode fiber.
Fiber network construction was financed internally by the Electric Enterprise Fund through a 20‐year, $2 million loan at a
0% interest rate. These funds were used to construct the network and to cover operating expenses. At the end of Fiscal
Year 2008, the fiber optics business completed the loan repayment to the Electric Enterprise Fund for all capital and
operating expenses from the beginning of the project. A separate Fiber Optics Enterprise Fund, capable of maintaining its
own capital and operating budgets and financial operating reserve, was also created. In Fiscal Year 2009, a Fiber Optics
Enterprise Fund Rate Stabilization Reserve (RSR) was established.
The fiber network was built in part in response to telecommunications service providers such as emerging Competitive
Local Exchange Carriers (CLECs) that would use available dark fiber to provide various telecom services. In the mid‐1990s,
there was a high demand for fiber transport facilities to support the expansion of bandwidth‐intensive broadband services.
By the late 1990s, many CLECs left the market either through mergers with other CLECs or bankruptcy; the so‐called “dot
com bust” also occurred at roughly the same time. As a result, the anticipated demand for dark fiber in the original target
market proved to be somewhat limited. By the late 1990s there was a glut of available dark fiber in many areas of the
country. Nonetheless, it was evident that a fiber network would be a valuable asset for command and control of City of
Palo Alto Utilities (CPAU) facilities (e.g. electric substations) and other critical City infrastructure such as traffic signals.
The network would also support a wide range of broadband voice, data and video applications for City departments, in
addition to various commercial users, telecommunications service providers, and the community as a whole.
Utilities Department
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EXHIBIT A
Utilities Department
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Fiber-to-Fiber Premises and Wireless Communication Initiative Page 2 of 5 Date Last Updated 02/04/17
In 2000, the City began to license “dark fiber” for commercial purposes. Dark fiber is unused fiber through which no light
is transmitted, or installed fiber optic cable not carrying a signal. The basic business model is to provide dark fiber
connectivity to users requiring access to large amounts of bandwidth. Customers are responsible for providing and
maintaining the equipment to “light‐up” or provision licensed fiber strands. Dark fiber is licensed or leased by a provider
such as the City without the accompanying transmission service. In contrast, traditional telecommunication service
providers only make available certain products (commonly known as “managed services”) within their service options that
may not adequately meet the requirements of the specific applications.
The fiber network has high market share and brand awareness among commercial enterprises and other organizations
that need the quantity and quality of bandwidth provided by direct fiber optic connections.
By connecting to the City’s fiber backbone, the customer gains fiber access to their Internet Service Provider (ISP) of choice.
A dark fiber customer can interconnect communications systems or computer networks across multiple Palo Alto locations
and can also connect directly to their local and/or long distance carrier(s) of choice with a full range of communications
services. Dark fiber customers can also have redundant telecommunication connections for enhanced reliability.
Many of the City’s commercial dark fiber customers gain access to the Internet through the Palo Alto Internet Exchange
(PAIX, now owned by Equinix). PAIX is a carrier‐neutral collocation facility and hosts over 70 ISPs at their facility located
in downtown Palo Alto. Equinix has 21 similar facilities in the United States and other collocation facilities in Asia and
Europe.
The City currently licenses dark fiber connections to 107 commercial customers. The fiber network also serves the
following City accounts: IT Infrastructure Services, Utilities Substations, Utilities Engineering, Public Works, Water Quality
Control Plant and Community Services (Art Center). The total number of dark fiber service connections serving commercial
customers and the City is 219 (some customers have more than one connection). At the end of fiscal year 2016, the
licensing of dark fiber service connections resulted in a fiber reserve of approximately $24 million. There is a separate
$1.0 million Emergency Plant Replacement fund. According to the proposed Fiscal Year 2017 Budget, the fiber reserve is
projected to increase by $2.3 million.
Annual dark fiber license revenues come from the following customer categories:
• City service connections: 27% of gross revenues.
Private sector entities licensing dark fiber from the City:
Resellers: 42% of gross revenues. “Resellers” are telecommunication companies that purchase large amounts of
transmission capacity from other carriers and resell it to smaller end‐users. Examples of resellers are telecom
companies that sell broadband, telephony and video services to the commercial and residential markets.
Various commercial enterprises: 31% of gross revenues. Examples of private end‐users are companies involved in
various technologies, web hosting, social media, finance, medical, pharmaceuticals, research and development,
software, law firms, consulting firms, e‐commerce, etc.
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Service offerings: Dark fiber backbone license fees are based on the number of fiber miles per month. The base license
price is $272.25 per fiber mile, per month. Quantity, route, length, topology, and other discounts are available. The
minimum backbone license fee is $425 per month. Lateral connection (premises to backbone) fees are based on the
length and type of the lateral, with a minimum fee of $210. Available configurations include point‐to‐point and diverse
rings.
The majority of business parks and commercial properties are passed by the fiber backbone. In 2014, CPAU completed a
project to serve all Palo Alto Unified School District facilities with dark fiber service connections.
2016 ‐ 2017: In 2016, CPAU retained Celerity Integrated Services, Inc. to provide a one‐time comprehensive review and
audit of the City dark fiber optic network. Celerity completed the review and audit and provided a physical description of
the network; documented the number of fiber strands, in addition to conducting an inspection of 90 fiber nodes/cabinets
(i.e. network splice points) to identify what is labeled within the individual nodes/cabinets.
CPAU Engineering is currently working with CAD Masters to reconcile the audit data provided by Celerity with various fiber
databases, in addition to rebuilding front‐end databases to facilitate fiber assignments at the engineering level and to
improve network mapping.
In 2017, CPAU initiated a $1.3 million backbone rebuild project that will install new aerial duct or substructure (conduit
and boxes), in addition to fiber backbone cable to increase capacity for sections of the dark fiber ring that are at or near
capacity. This project will allow CPAU to meet customer requests for services. The project areas primarily cover the
Stanford Research Park, Palo Alto Internet Exchange/Equinix at 529 Bryant, and Downtown areas. This project basically
“overlays” new fiber over existing fiber routes in the network. Existing fiber will continue to serve City facilities and
commercial dark fiber customers.
Fiber‐to‐the‐Premises
For more than fifteen years, the City has worked to develop a business case to build a citywide fiber‐to‐the‐premises
(“FTTP”) network to serve homes and business. A number of business models have been evaluated. The following is a
summary of the highlights to develop a network:
1999: A Request for Proposal (RFP) was issued to build citywide FTTP. There were no viable bids.
2000‐2005: The City Council approved a Fiber‐to‐the‐Home (“FTTH”) trial to determine the feasibility of providing citywide
FTTH access in Palo Alto. The FTTH trial passed 230 homes and included 66 participants in the Community Center
neighborhood. The purpose of the trial was to test the concept of fiber‐to‐the‐home. The FTTH trial proved successful
(i.e., proved technical feasibility), but when initial investment and overhead expenditures were included in the calculation
to create a business case, it was not profitable for the City and the trial was ended.
2006‐2009: In 2006, the City issued another RFP and negotiated with a consortium of private firms to build FTTP under a
public‐private partnership model. In 2009, Staff recommended to Council termination of the RFP process and negotiations
due to the lack of financial resources of the private firms.
2010: The City responded to Google Fiber’s Request for Information.
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2011: Staff worked with two telecommunications consulting firm to evaluate the expansion of the existing dark fiber
network for its commercial dark fiber licensing enterprise and also to expand the network on an incremental basis to
attract a “last mile” FTTP builder and operator. This is a link to the staff report provided to the Utilities Advisory
Commission in June of 2011, and the Council Finance Committee in November of 2011:
Subject: Provide Feedback on the Development of a Business Plan for the Citywide Ultra‐High‐Speed Broadband System
Project
http://www.cityofpaloalto.org/civicax/filebank/documents/27421
2012: Staff worked with a telecommunications consulting firm to study the feasibility of an alternative model for citywide
FTTP which would rely on homeowners paying on a voluntary basis for some or all of the cost to build‐out the existing
dark fiber network into residential neighborhoods. The name of this model is “user‐financed” FTTP. The analysis
concluded that an opt‐in FTTP network can be built using a combination of upfront user fees and City financing; however,
there is very little probability of the debt incurred being repaid through operations. Ongoing subsidies would be required,
very likely in excess of surpluses in the Fiber Optics Fund reserve generated by licensing dark fiber. The study was
supported by a market survey which concluded there was limited interest among residents in this model. This is a link to
the staff report provided to the Utilities Advisory Commission in June 2012:
Subject: Request for Feedback Concerning the Dark Fiber Optic Backbone Network
http://www.cityofpaloalto.org/civicax/filebank/documents/30112
2013 ‐ 2015: The City Council started it’s “Technology and the Connected City” initiative and directed staff to prepare a
Fiber‐to‐the‐Premises Master Plan and a Wireless Network Plan. In 2015, staff worked with a telecommunications
consulting firm to prepare these plans and they are provided for your review in this September 28, 2015 Council staff
report:
Summary Title: Discussion of Fiber‐to‐the‐Premises and Direction on Next Steps for Fiber and City Wireless Services
http://www.cityofpaloalto.org/civicax/filebank/documents/49073
At the September 28, 2015 Council meeting, staff and the consultant reviewed these plans with the Council Members. As
a result, a Council Motion directed staff to pursue several initiatives, which are described in this August 16, 2016 staff
report which updated the Council about the various activities from the Motion:
Summary Title: Fiber‐to‐the‐Premises update on City Council Motions and Google Fiber
http://www.cityofpaloalto.org/civicax/filebank/documents/53363
2014 ‐ 2016: Google Fiber announced Palo Alto as a potential “Google Fiber City” for a build‐out of their fiber optic
network. Since early 2014, staff has been engaged with Google personnel to complete an extensive checklist process
regarding City infrastructure and processes, in addition to negotiating agreements for a project description, utility pole
attachments, encroachment permits, environmental reviews and other agreements for cost recovery for use of staff time.
Based on Council direction, staff has also worked with Google to develop a “co‐build” concept which would explore the
feasibility of building a City network in parallel with Google’s network. In July 2016, Google announced a delay in their
plans for up to six (6) months to build a fiber optic network in Silicon Valley, which also included Mountain View, San Jose,
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Santa Clara and Sunnyvale. Google advised staff that they are exploring more innovative ways to deploy their network,
which may include implementing wireless technologies. Co‐build discussions have also been delayed.
In the summer of 2016, the City approved permits for two cabinets so AT&T can begin to deploy their “AT&T Fiber” service.
AT&T is exploring deployment of additional cabinets in 2017. Based on Council direction, staff is also pursuing co‐build
discussions with AT&T.
On December 12, 2016, staff provided Council with an informational update regarding Fiber‐to‐the‐Premises and wireless
initiatives:
Summary Title: Update for Fiber‐to‐the‐Premises and Wireless Initiatives:
http://www.cityofpaloalto.org/civicax/filebank/documents/55016
Wireless Network Plan
Based on the above‐mentioned Wireless Network Plan, Council directed staff to issue an RFP for a Point‐to‐Multipoint
Secure Access Network for Public Safety and Utilities communications, in addition to an RFP for a Mobile Broadband
Network to improve “in‐vehicle” broadband access in Public Safety vehicles. Staff is also working to extend the City’s
existing Wi‐Fi service to other City facilities that are currently unserved. Most key City facilities already have Wi‐Fi available
for staff and public use.
Staff Work Plan Update: City Council Motion from September 28, 2015 (CMR ID #6104) and
status of November 30, 2015 (CMR ID #6301) staff recommendations:
Task Target Date Status
1
Council requests an update to the consultant’s
report including:
a In the FTTP Master Plan:
12/31/2015
Completed. Reviewed
assumptions for outside plant
costs and capital additions in FTTP
Master Plan with CAC and CTC on
1/21/16 and 2/18/16. CAC now in
agreement with CTC’s FTTP
network cost estimates and there
are no discrepancies to report.
Detailed assumptions, and their impacts,
used to forecast the FTTP capital additions
are to be reviewed by Citizen Advisors if
there is a disagreement between the
consultant’s report and the CAC’s
recommendation, the Staff Report to
Council will highlight the discrepancy.
Once this is accomplished, a revised
forecast is to be provided to the Council as
an Action Item;
b In the Wireless Network Report:
i.A 20‐year forecast should be provided
consistent with the FTTP report;12/31/2015 Completed
ii.The description of Scenario 1 lacked
both a price forecast and fiber backhaul
details for the proposed municipal
properties to be served. These details
should be included in an update prior to an
RFP. Evaluate expanding wireless access in
retail areas, with an option for expanding
Wi‐Fi coverage at City facilities and public
areas as part of the RFP (Scenario 1);
9/30/2016
Completed.
City Staff has developed cost
estimates for the extension of
existing City Wi‐Fi to unserved
City facilities & public areas/parks.
The evaluation of expanding Wi‐Fi
access in retail areas showed that
Wi‐Fi coverage in retail areas is
adequately provided by the retail
institutions. Expanding City‐
EXHIBIT B
provided public Wi‐Fi coverage in
these areas is not recommended
by City Staff.
2
Issue RFP to add dedicated wireless
communications to increase communication
for Public Safety and Utilities departments
(Scenarios 3 and 4);
6/30/2017
In progress.
The draft RFP(s) and cost
estimates are near completion for
the following:
1. Citywide Mobile Data Network
for Public Safety
2. Point‐to‐Multipoint Network
for Secure City Enterprise
Access (Public Safety &
Utilities)
3 Direct Staff to bring a Dig‐Once Ordinance;
Winter/Spring
2017
In Progress.
Staff has met with AT&T, Comcast
and other companies that may
propose large scale excavation
projects in the future. These
discussions are ongoing. The
CAO, in consultation with cross‐
departmental staff, is currently
reviewing the existing ordinance
to identify any possible revisions
to better coordinate joint trench
projects.
4
Direct Staff to discuss co‐build with AT&T and
Google how the City can lay its own conduit to
the premise during the buildouts;
a AT&T TBD
On Hold.
The City met with AT&T
representatives to discuss a co‐
build opportunity as AT&T
updates their AT&T Fiber Internet
service in Palo Alto. Follow up
discussions continue to occur
when AT&T begins upgrading
their existing cabinets in Palo
Alto.
b Google TBD
On‐Hold.
At Google’s request, the
discussion regarding deployment
of FTTP for the 5 proposed Bay
Area cities to identify the
feasibility of various joint build
opportunities and the potential
deployment of Google Fiber in
Palo Alto are on hold while they
examine new, innovative methods
for fiber deployment.
5
Move forward with RFI exploring both Muni‐
owned model with contractors for build and
ongoing operations, and Public—private
model with City owned fiber and private
partner (such as Sonic) operating and owning
electronics, considering both Google in the
market and not;
9/30/2016
Completed.
The 8 RFIs received have been
reviewed and CTC provided an
evaluation report of the RFIs in
Exhibit B. 3 of the respondent
firms were interviewed; none of
the respondent’s proposals
completely align with city goals.
6
Approve a temporary contract position for a
Fiber and Wireless Telecommunications
Project Manager, dedicated to Fiber‐to‐the‐
Premises and wireless initiatives, in the
amount of $228,000 annually, $684,000 for a
period up to three (3) years;
TBD
On‐Hold.
A decision was made to put this
position on hold due to the
Google Fiber “pause.” Staff will
evaluate whether a contract
position or professional services
agreement is needed dependent
on City Council’s decision
regarding staff recommendations.
7
Approve and authorize the City Manager or his
designee to execute amendments to two
contracts with Columbia Telecommunications
Corporation dba CTC Technology & Energy
(“CTC”) as follows:
a
Increasing the not‐to‐exceed amount for
Contract No. C15152568 (Wireless
Network Plan) by $94,490 from $131,650
to $226,140 (includes a 10% contingency
for the provision of related additional, but
unforeseen consulting services) and extend
the contract to June 30, 2016 to develop a
Request for Proposal for dedicated wireless
communications for Public Safety and
Utilities, in addition to evaluating the
expansion of wireless access in retail areas
12/31/2015
Completed.
Amendment finalized on 1/6/16.
b
Increasing the not‐to‐exceed amount for
Contract No. C15152569 (FTTP Master
Plan) by $58,850 from $144,944 to
$203,794 (includes a 10% contingency for
the provision of related additional, but
unforeseen consulting services) and extend
the contract to June 30, 2016 to provide
technical analysis of the Request for
Information (RFI) responses and any
consulting services needed to help develop
a “Dig Once” Ordinance for consideration
by the Council
12/31/2015
Completed.
Amendment finalized on 1/6/16.
EXCERPTED FINAL MINUTES OF THE NOVEMBER 2, 2016
UTILITIES ADVISORY COMMISSION
ITEM 4. DISCUSSION: Fiber and Wireless Update
Chief Information Office Jonathan Reichental and Utilities Senior Management Analyst Jim
Fleming provided an update regarding Fiber-to-the-Premises (FTTP) and wireless activities,
including Google Fiber, AT&T Fiber, Comcast, a summary of the public-private partnership
Request for Information, and potential recommendations for discussion.
Reichental reported that Google Fiber is “pausing” its plan to build in the San Jose area,
including in Palo Alto. The delay is indefinite and no target date has been provided by Google
senior personnel. This indefinite delay also applies to a potential “co-build” agreement. AT&T
has rebranded its “GigaPower” high-speed Internet service and it is now called AT&T Fiber. City
staff is currently processing permits for two cabinets submitted by AT&T. AT&T plans to submit
more permits for cabinets in 2017. AT&T has also committed to engaging in continuing
discussions with the City to explore creative and innovative ideas for fiber and wireless.
Comcast is targeting a citywide DOCSIS 3.1 launch starting in the second quarter of 2017.
DOCSIS 3.1 supports Internet speeds of 10 Gigabits per second for downloads downstream and
1Gbps upstream - the level of speeds typically only available with a fiber optic connection.
Comcast informed the City that it has no interest in a co-build partnership.
Fleming provided the highlights of the Request for Information (RFI) issued to determine if
there is any interest from the private sector in partnering with the City to build a citywide FTTP
network. The RFI was distributed to approximately 40 vendors in May 2016 and the City
received eight responses. Two responses were deemed to be incomplete and the other six
responses generally did not align with the City’s objective laid out in the RFI, including City
ownership of the network, ubiquitous service and open access. Based on a recommendation by
the City’s consultant, CTC Technology & Energy, interviews were conducted with three
companies for information collection purposes. The status of Google Fiber at the time the RFI
was issued may have discouraged more responses.
The firms interviewed were Comcast, Axia and N1/UTOPIA:
Comcast’s response was focused on pointing out to the City that they currently offer
advanced telecom services, with plans to upgrade their voice, video and data
products in the near future, including the launch of DOCSIS 3.1 for gigabit Internet.
Axia was closest to the City’s expectations, but largely did not align with the City’s
objective to own the network. Axia’s approach for FTTP entails minimal financial risk
EXHIBIT C
for the City. Axia would finance, build and own the network based on attaining a 40
percent “expression of interest” in the community. Axia is also interested in
acquiring the City’s dark fiber network. Axia has no interest in a co -build agreement
with the City.
N1/UTOPIA’s model would require the City to finance and build an open access FTTP
network, while they would provide design and engineering services under a
consulting agreement. N1/UTOPIA would help the City to operate the network and
facilitate interconnection with Internet Service Providers (ISPs) who would provision
voice, video and data services on the network. N1/UTOPIA’s operational services
would be provided under a revenue sharing agreement with the CIty. The City
would be required to handle customer billing and collection of the transport fees
that would be paid by the ISPs to provide services over the open access network.
Reichental and Fleming reviewed the following potential recommendations for the City Council:
• Explore and identify appropriate funding models to build and operate a municipally-
owned ubiquitous fiber-to-the-premises network;
• Concurrently issue a solicitation to design a Fiber-to-the-Node network, and include
an option for respondents to also quote for building last mile or incent ivize market
to build the last mile;
• Proceed with expanding Wi-Fi deployments for unserved City facilities (e.g. portions
of Lucie Stern and Cubberley);
• Not proceed with Wi-Fi deployments in high traffic retail areas which are already
being served;
• Reevaluate the approach to an implementation of a “Dig Once” ordinance.
City Manager James Keene noted that we have been working on fiber since he arrived eight
years ago. Since the market is constantly changing and Google Fiber has gone dormant, the
Council, UAC and the community need to align their policy and demand for fiber. The
incumbents will continue to compete and upgrade their networks based on customer demand.
If the City goes out again with another partnership RFI, it still may not yield a viable solu tion.
Should the City figure out how to fund the $77M network? The Fiber -to-the-Node concept
could be funded by existing Fiber reserves, but that doesn’t mean it’s a wise decision. It’s time
to have a discussion with Council and UAC to refocus the objectives in the new market
environment.
Vice Chair Danaher asked about AT&T’s willingness to discuss creative ideas. Reichental replied
that Council asked staff to explore with AT&T and Google Fiber ways to incentivize ubiquitous
service. AT&T asked for more clarification about potential scenarios. AT&T is enthusiastic
about their new gigabit offering; they are open to creative discussions with the City. Even
though there aren’t any substantive ideas at this point from either side, AT&T has not closed
the discussion.
Vice Chair Danaher asked what the City wouldn’t get if AT&T didn’t deploy its upgrade.
Reichental replied that deployment is market driven and AT&T will only build cabinets where
there is consumer interest. The current U-verse service does not reach every home in Palo
Alto.
Vice Chair Danaher asked about competition and rates. Fleming replied there are markets
where open access networks create competition and reasonable rates, but the Bay Area market
isn’t one of them. Google Fiber was successful in getting the incumbents to up their game and
accelerate network upgrades. Vice Chair Danaher added that if open access isn’t practical, then
the City’s goal should be ubiquity and to provide incentives for network upgrade s. The City
should focus on incentives and actions to accelerate upgrades and take focus off owning its
own network. Fleming added that the incumbents’ upgrades are easier because it’s more
about upgrading their network equipment and electronics, rather than installing more fiber.
City Manager Keene stated that the City has a propensity for study related to fiber. The UAC
should move with dispatch to give Council its perspective. It is not practical for staff to
continue evaluating several options simultaneously. What content will the City provide with a
city owned network? UAC should let the Council know from a policy perspective about its
current thinking.
Vice Chair Danaher stated that from his point of view spending $77 million to build a city o wned
network was never a great proposition if there is already competitive services available; co -
building or co-owning the network should not be a priority. We should look at what we can do
administratively and logistically to speed upgrades to ensure ubiquity. The RFI was never
compelling and is not surprised by the lack of responses. Instead we should look for speed and
support for the incumbent upgrades.
Commissioner Johnston stated that technology is changing and it may leapfrog whatever we
do. He agrees with Vice Chair Danaher that the incumbents have commercial incentives to
upgrade and the City should press them for speed and to cover everyone.
Commissioner Forssell asked what leverage we have to press AT&T to provide citywide
coverage.
Senior Deputy City Attorney Jessica Mullan responded that it depends on the particular
application that comes before the City and the conditions of approval we can impose at the
time. This is a challenging space for telecom companies in that what the City offe rs to one
company we have to offer to all companies across the board due to federal law. The City
Attorney’s office will have to analyze this in terms of looking at it on a contractual basis.
Reichental added that when the City speaks to AT&T and Comcast t hey certainly want revenue
and the market, but they also want support from the City for faster permitting. Additionally,
some customers may be satisfied with the current level of service they receive. AT&T will
market heavily throughout the City and people can go online or to one of their storefront
locations to express interest; if there’s a critical mass of interest in an area then they will
deploy.
City Manager Keene noted that in trying to negotiate there are usually “no deal” or “walk -
away” options. The challenge in attaining leverage is that there are conditions when the
provider will say they’ll do the best they can to get 100 percent coverage, but if there are other
conditions from the City, they may not come at all. It’s important at this point that the UAC
provide Council with their thoughts from a policy standpoint.
Senior Deputy City Attorney noted that telecom companies have access to the City’s public
rights-of-way, but under State and federal law, the City has the right to regulate “time, place
and manner” of the placement of their facilities in the rights -of-way. The City can only regulate
certain aspects, but we can encourage them to expand to underserved areas.
Commissioner Forssell observed that both AT&T and Comcast are profit -making institutions
beholden to their shareholders. We have an opportunity to look out for all residents, but she is
skeptical that unless we have tangible leverage, she is unconvinced that AT&T and Comcast will
deploy ubiquitously if that’s the Council’s policy goal.
Commissioner Forssell asked to clarify that if we are mulling over the idea of issuing a bond for
$77 million, what services will we provide and do we have a sense of what citizens want? Is it
bundled entertainment, Internet and voice services similar to what AT&T and Comcast offer
and the prices change depending on what bundle you sign-up for? City Manager Keene
responded that even if the City in in this business, it doesn’t preclude the incumbents and
others from competing against the City. Even after capitalizing the expense to build the
network we’d have to get enough customers to get the 72 percent market uptake and the
incumbents in response may be willing to provide more services at a better price. The City
Manager added that we’re not advocating for AT&T and Comcast as the solution, but the
comment Commissioner Forssell’s made about shareholders is an appropriate one since if a City
network is run as a utility the shareholders are the citizens and customers and we need to
acknowledge that relationship, especially if it involves a public-private partnership and the
potential benefits that would be provided to the shareholders.
Chair Cook recognized the market is moving quickly and how much things change each time the
fiber item is reviewed by the UAC and expressed frustration on the lack of progress. Chair Cook
also noted that he has been skeptical of the cost to build and he has heard different cost
numbers. The decision would vary based on a cost of $20 million vs. $70 million; Fiber-to-the-
Node approach may be an idea. Chair Cook asked if there is the potential to expand the
existing fiber backbone infrastructure to increase revenue, but he has a concern about getting
away from the City’s goals for network ownership, ubiquity and open access. Perhaps the
question to the Council is what is the public benefit of fiber for the community in terms of local
control and lower costs (similar to the public benefit of achieving carbon neutrality)? We need
to determine the public benefit aspect of fiber for the community.
Commissioner Trumbull noted that we may have to give up on the notion of fiber a as public
utility due to federal law.
City Manager Keene noted that the Fiber-to-the-Node (FTTN) approach has potential because
of the need to reinvest in the fiber network and the cost is manageable. The fiber ring could be
expanded in a way to stay competitive. For example, the fiber network was extended to the
school district and there may be other opportunistic expansions. Also, since we don’t know
now where the technology is headed for fiber and wireless, FTTN may be back -filler for fiber
backhaul opportunities, ubiquity and support of 5G in the future.
The City Manager added that General Manager of Utilities/Assistant City Manager Ed Sh ikada,
CIO Jonathan Reichental and the Fiber/Wireless Team will have to further flesh out these
concepts for future discussions.
ACTION:
None.
Appendix A: Existing Market Assessment
Final
Prepared for City of Palo Alto
July 2015
EXHIBIT D
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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Contents
1 Existing Market Assessment ................................................................................................... 1
2 Enterprise Market ................................................................................................................... 1
1.1 Dark Fiber Services ........................................................................................................... 1
1.1.1 Integra Telecom ........................................................................................................ 1
1.1.2 Level(3) ...................................................................................................................... 2
1.1.3 Zayo ........................................................................................................................... 3
1.2 Ethernet Services .............................................................................................................. 4
1.2.1 AT&T .......................................................................................................................... 4
1.2.2 CenturyLink ............................................................................................................... 5
1.2.3 Cogent Communications ........................................................................................... 5
1.2.4 Comcast ..................................................................................................................... 5
1.2.5 Level(3) ...................................................................................................................... 6
1.2.6 Megapath .................................................................................................................. 6
1.2.7 Integra Telecom ........................................................................................................ 6
1.2.8 Verizon ...................................................................................................................... 6
1.2.9 Windstream Communications .................................................................................. 7
1.2.10 XO Communications ................................................................................................. 7
1.2.11 Zayo ........................................................................................................................... 7
2 Residential and Small Business Services ................................................................................. 8
2.1 Cable ................................................................................................................................. 8
2.2 DSL .................................................................................................................................... 9
2.2.1 AT&T .......................................................................................................................... 9
2.2.2 EarthLink ................................................................................................................. 10
2.2.3 MegaPath ................................................................................................................ 10
2.2.4 Sonic ........................................................................................................................ 10
2.3 Satellite ........................................................................................................................... 10
2.3.1 HughesNet .............................................................................................................. 10
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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2.3.2 Exede ....................................................................................................................... 11
2.3.3 DishNET ................................................................................................................... 11
2.4 Wireless .......................................................................................................................... 11
2.4.1 Verizon .................................................................................................................... 11
2.4.2 Sprint ....................................................................................................................... 12
2.4.3 AT&T ........................................................................................................................ 12
2.4.4 Cricket Wireless ...................................................................................................... 12
2.4.5 T‐Mobile .................................................................................................................. 12
2.4.6 Etheric Networks ..................................................................................................... 13
Figures
Figure 1: Integra Telecom Network Map ........................................................................................ 2
Figure 2: Level(3) Dark Fiber Routes ............................................................................................... 3
Figure 3: Zayo Fiber Map ................................................................................................................ 4
Tables
Table 1: Overview of Residential and Small Business Data Services in Palo Alto ........................... 8
Table 2: Comcast Residential Internet – Internet Only .................................................................. 9
Table 3: Comcast Small Business Internet – Internet Only ............................................................. 9
Table 4: AT&T Residential Internet – Internet Only ..................................................................... 10
Table 5: Etheric Networks Internet Services ................................................................................ 13
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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1 Existing Market Assessment
This existing market assessment provides an overview of providers that currently offer services
with which the City’s potential new fiber‐to‐the‐premises (FTTP) enterprise might compete. The
information provided here is based on what was publicly available—providers often do not
publish extensive information about their networks (e.g., capacity and other specific details).
2 Enterprise Market
This section summarizes competitors for dark fiber and Ethernet services with respect to the
enterprise customers within the City of Palo Alto.
During the course of our research, we identified 11 service providers in the Palo Alto area that
offer a range of services from dark fiber connectivity to data transport services, with speeds that
range from 1 Megabit per second (Mbps) to 100 Gigabits per second (Gbps). Individual providers
tailor these services to a customer’s requirements, such as speed and class of service. Greater
proximity to the provider’s existing network infrastructure results in lower service pricing.
Providers prefer to offer transport services between locations on their network (On‐Net) and
provision Multiprotocol Label Switching (MPLS) based services for connecting locations that are
Off‐Net.
A trend that we expect to continue is the consolidation of competitors through mergers and
acquisitions. Competitors are discussed in detail in the following sections.
1.1 Dark Fiber Services
In addition to the City of Palo Alto Utilities (CPAU) dark fiber offering,1 our analysis found that
three service providers in the City offer dark fiber services2: Integra Telecom, Level (3) and Zayo.3
There may be other providers that offer dark fiber (e.g., on a case‐by‐case basis), but this analysis
yielded information only about the three discussed here.
1.1.1 Integra Telecom
Integra Telecom offers dark fiber services within the city. They provide flexible options in securing
dark fiber through bundles, lease, and indefeasible rights of use (IRU). The dark fiber routes are
depicted in Figure 1.4,5 Dark fiber pricing varies individually, based on distance from the
1 CPAU is engaged in capital improvements for added capacity and to provide additional dark fiber routes.
2 An assessment of the potential impact of alternative dark fiber provider offerings to City of Palo Alto’s existing
dark fiber enterprise is beyond the scope of this analysis.
3 While this analysis yielded only these three, there may be other providers offering dark fiber—for example, on a
case‐by‐case basis.
4 http://www.integratelecom.com/pages/network‐map.aspx, accessed March 2015.
5 As we noted, carriers typically do not publish details such as whether they directly own the routes depicted on
their publicly‐available maps.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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provider’s fiber ring. A difference in a few tenths of a mile can lead to significant differences in
the price of dark fiber connectivity due to additional construction costs.
Figure 1: Integra Telecom Network Map
1.1.2 Level(3)
Level(3) has multiple dark fiber routes in Palo Alto as depicted in Figure 2.6 Services are offered
only to select customers based on their application requirements.
6 As we noted, carriers typically do not publish details such as whether they directly own the routes depicted on
their publicly‐available maps.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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Figure 2: Level(3) Dark Fiber Routes7
1.1.3 Zayo
Zayo provides dark fiber connectivity over its national network of metro and intercity fiber.8 The
company claims to have proven expertise in deploying major new dark fiber networks and offers
multiple financing options including lease or Indefeasible Rights of Use (IRU). Pricing varies
significantly depending on whether the building is On‐Net or not; if the location is Off‐Net,
construction and splicing costs would apply.9
7 http://maps.level3.com/default/, accessed May 2015.
8 Zayo is also a CPAU Value Added Reseller (VAR), based on conversations with CPAU staff.
9 http://zayofibersolutions.com/why‐dark‐fiber, accessed May 2015.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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Figure 3: Zayo Fiber Map10
1.2 Ethernet Services
Most existing service providers offer enterprise‐grade Ethernet based services. These are
typically classified under two categories: point‐to‐point connectivity and access services, such as
Dedicated Internet Access (DIA) and IP Virtual Private Networks (IP‐VPN). Bandwidths range from
1 Mbps to 100 Gbps. Providers prefer to offer MPLS based IP‐VPN services when the service
locations are Off‐Net to avoid construction and installation costs. MPLS based networks provide
high performance for real‐time applications like voice and video, and are typically priced higher.
The carriers who provide these services in the Palo Alto region are AT&T, CenturyLink, Cogent
Communications, Comcast,11 Integra Telecom, Level (3), Megapath, Verizon, Windstream
Communications, XO Communications and Zayo. Prices depend on the bandwidth, location, and
network configuration, whether the service is protected or unprotected, and whether the service
has a switched or mesh structure.
1.2.1 AT&T
AT&T has four different types of Ethernet products—GigaMAN, DecaMAN, Opt‐E‐MAN, and
Metro Ethernet. GigaMAN provides a native‐rate interconnection of 1 Gbps between customer
end points. It is a dedicated point‐to‐point fiber optic based service between customer locations
which includes the supply of the GigE Network Terminating Equipment (NTE) at the customer
10 http://www.zayo.com/network/interactive‐map, accessed March 2015.
11 It appears Comcast may be pursuing the enterprise market more aggressively through means like going into
wireless backhaul. http://www.fiercetelecom.com/offer/gc_backhaul?sourceform=Organic‐GC‐Backhaul‐
FierceTelecom, accessed July 2015.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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premises. DecaMAN connects the end points at 10 Gbps and is transmitted in native Ethernet
format similar to GigaMAN, only 10 times faster. Opt‐E‐MAN service provides a switched
Ethernet service within a metropolitan area. It supports bandwidths ranging from 1 Mbps to
1,000 Mbps, and configurations such as point‐to‐point, point‐to‐multipoint, and multipoint‐to‐
multipoint. Metro Ethernet service provides various transport capabilities ranging from 2 Mbps
through 1 Gbps while meeting IEEE 802.3 standards.12
1.2.2 CenturyLink
CenturyLink provides point‐to‐point inter‐city and intra‐city configurations for full‐duplex data
transmission.13 The company offers speeds of 100 Mbps to 10 Gbps.14
1.2.3 Cogent Communications
Cogent Communications’ Ethernet services are available at speeds of 1.5 Mbps to 10 Gbps.15 The
company provides middle mile services with the last mile service provisioned through local
exchange carriers (LEC).16 Often, more competitive pricing and better customer support is
available through Cogent even though the company utilizes the LECs’ last‐mile services. Cogent
has two on‐net locations (data centers) in the City.
1.2.4 Comcast
Comcast provides Ethernet Private Line (EPL) services. EPL service enables customers to connect
their Customer premises equipment (CPE) using a lower cost Ethernet interface, as well as using
any Virtual Local Area Networks (VLAN) or Ethernet control protocol across the service without
coordination with Comcast. EPL service is offered with 10Mbps, 100Mbps, 1 Gbps or 10 Gbps
Ethernet User‐to‐Network Interfaces (UNI) and is available in speed increments from 1 Mbps to
10 Gbps.17
It is important to note that Comcast began offering “Gigabit Pro” service in 2015, a 2 Gbps service
priced at $300 per month with installation fees of up to $1,000.18 Given the installation and
monthly fees, this service is priced out of most residential users’ reach. Further, the service does
not have the bells and whistles that traditional Metro Ethernet has—such as committed interface
12
http://www.business.att.com/service_overview.jsp?repoid=Product&repoitem=w_ethernet&serv=w_ethernet&se
rv_port=w_data&serv_fam=w_local_data&state=California&segment=whole, accessed March 2015.
13 CenturyLink is also a CPAU VAR and typically uses ring configuration for redundancy, based on conversations
with CPAU staff.
14 http://www.centurylink.com/business/products/products‐and‐services/data‐networking/private.html, accessed
May 2015.
15 http://www.cogentco.com/en/products‐and‐services, accessed May 2015.
16 Cogent is also a CPAU VAR, based on conversations with CPAU staff.
17 http://business.comcast.com/ethernet/products/ethernet‐private‐line‐technical‐specifications, accessed April
2015.
18 http://www.theverge.com/2015/7/13/8949207/comcast‐gigabit‐pro‐price‐300, accessed July 2015.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
6
rates. However, if Gigabit Pro is successful, it could disrupt the Metro Ethernet market by filling
a mid‐range gap with service and pricing that has not previously existed.
1.2.5 Level(3)
Level (3)’s Metro Ethernet dedicated service is available in bandwidth options of 3 Mbps to 1
Gbps and its Ethernet Virtual Private Line (VPL) offers in speeds ranging from 3 Mbps to 10
Gbps.19 It is an end‐to‐end Layer 2 switched Ethernet service delivered via a Multi‐protocol Label
Switched (MPLS) backbone. Internet services are available in a range of 14 speeds up to 10
Gbps.20
1.2.6 Megapath
Megapath offers business Ethernet services in the Palo Alto area with advertised speeds up to 45
Mbps. Higher speeds are available on a case‐ by‐case basis.21
1.2.7 Integra Telecom
Integra Telecom offers Ethernet services from 1.5 Mbps to 10 Gbps. The point‐to‐point E‐Line
and multipoint ‐to ‐multipoint E‐LAN configurations are available.22
1.2.8 Verizon
Verizon offers Ethernet services under three different product categories—Ethernet Local Area
Network (LAN), EPL, and EVPL. The Ethernet LAN is a multipoint‐to‐multipoint bridging service at
native LAN speeds. It is configured by connecting customer User‐to‐ Network Interfaces (UNIs)
to one multipoint‐to‐multipoint Ethernet Virtual Connection or Virtual LAN (VLAN), and provides
two Class of Service options—standard and real time. The Ethernet Private Line is a managed,
point‐to‐point transport service for Ethernet frames. It is provisioned as Ethernet over SONET
(EoS) and speeds of 10 Mbps to 10 Gbps are available. The EVPL is an all‐fiber optic network
service that connects subscriber locations at native LAN speeds; EVPL uses point‐to‐point
Ethernet virtual connections (EVCs) to define site‐to‐site connections. It can be configured to
support multiple EVCs to enable a hub and spoke configuration and supports bandwidths from 1
Mbps to 10 Gbps.23
19 http://www.level3.com/en/products‐and‐services/data‐and‐internet/vpn‐virtual‐private‐network/evpl/,
accessed March 2015.
20 http://www.level3.com/~/media/files/factsheets/en_ethernet_fs_ethernetmatrix.pdf, accessed April 2015.
21 http://www.megapath.com/data/ethernet/, accessed May 2015.
22 http://www.integratelecom.com/enterprise/products/pages/carrier‐ethernet‐services.aspx, accessed May 2015.
23 http://www.verizonenterprise.com/products/networking/ethernet/, accessed April 2015.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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1.2.9 Windstream Communications
Windstream Communications has a nationwide presence serving major metropolitan areas,
including the City, with private line and MPLS VPN services with speeds up to 10 Gbps.24, 25
1.2.10 XO Communications
XO Communications offers carrier Ethernet services at multiple bandwidth options from 3 Mbps
to 100 Gbps over their Tier 1 IP network.26, 27
1.2.11 Zayo
Zayo delivers Ethernet in three service types with bandwidth ranging from 100 Mbps to 10 Gbps
and options like quality of service (QoS) guarantees and route protection based on customer
needs. The different types of services offered are: Ethernet‐Line, which provides point‐to‐point
and point‐to‐multipoint configurations with reserved bandwidth availability; Ethernet‐LAN, with
multipoint configurations having a guaranteed service level; and Ethernet Private Dedicated
Network (E‐PDN) with a completely private, managed network operated by Zayo with dedicated
fiber and equipment.28 As an example of pricing, Zayo charges a monthly recurring cost of $1,613
to $2,090 (depending on contract term) for 1 Gbps point‐to‐point Ethernet service between On‐
Net sites in the Los Angeles region that are three miles apart.
24 http://carrier.windstreambusiness.com/wordpress/wp‐content/uploads/2014/10/Carrier‐Ethernet‐Ordering‐
Guide‐10.8.14.pdf, accessed April 2015.
25 http://www.windstreambusiness.com/shop/products/ca/palo‐alto, accessed May 2015.
26 http://www.xo.com/carrier/transport/ethernet/, accessed May 2015.
27 http://www.xo.com/network‐services/internet‐access/ip‐transit/100G/, accessed May 2015.
28 http://www.zayo.com/ethernet, accessed April 2015.
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2 Residential and Small Business Services
Residential and small business customers in the Palo Alto region have access to a range of
services, though individual service options are dependent on location. Table 1 lists the service
providers and minimum price for each type of service that is available in at least some part of the
City.
Table 1: Overview of Residential and Small Business Data Services in Palo Alto
Service
Type Provider Minimum Price
(per month)
Cable Comcast
$29.99
DSL
AT&T $29.95
Earthlink $80
MegaPath $45
Sonic $40
Satellite DishNET $49.99
Exede $49.99
HughesNet $49.99
3G/4G/
WISP
AT&T $50
Cricket $35
Sprint $35
Verizon $60
T‐Mobile $20
Etheric Networks $85
2.1 Cable
Comcast offers internet service from 3 Mbps to 150 Mbps download speeds starting at $29.99
per month in the City as illustrated in Table 2. Promotional rates are available for the first year
after which the rates increase. Discounted prices are available if bundled with another service
like voice or TV.29 On the small business side, multiple options are available starting at 16 Mbps
download speeds up to 150 Mbps download speeds as illustrated in Table 3.30 Bundling with
voice introduces a savings of $30‐$40.
29 http://www.comcast.com/internet‐service.html, accessed March 2015.
30 http://business.comcast.com/internet/business‐internet/plans‐pricing, accessed May 2015.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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Table 2: Comcast Residential Internet – Internet Only
PACKAGE INTERNET SPEED REGULAR
PRICE
PROMO
RATE
Economy Up to 3 Mbps download $39.95/mo ‐
Performance
Starter
Up to 6 Mbps download $49.95/mo $29.99/mo
Performance Up to 25 Mbps download $61.95/mo $39.99/mo
Blast! Blast! Internet ‐ up to 105 Mbps download $78.95/mo ‐
Extreme up to 150 Mbps download $114.95/mo ‐
Table 3: Comcast Small Business Internet – Internet Only
PACKAGE INTERNET SPEED PRICE
Starter 16 Mbps download/3 Mbps upload $69.95/mo
Deluxe 50 50 Mbps download/ 10 Mbps upload $109.95/mo
Deluxe 75 75 Mbps download/15 Mbps upload $149.95/mo
Deluxe 100 100 Mbps download/20 Mbps upload $199.95/mo
Deluxe 150 150 Mbps download/20 Mbps upload $249.95/mo
2.2 DSL
Four providers offer DSL services in Palo Alto: AT&T, EarthLink, MegaPath, and Sonic.
2.2.1 AT&T
AT&T offers DSL service for residential customers in Palo Alto starting at as $29.95 per month for
unbundled or standalone DSL service at 3 Mbps with a 12‐month commitment. Additional
options up to 45 Mbps are available as indicated in Table 4.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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Table 4: AT&T Residential Internet – Internet Only
INTERNET SPEED REGULAR PRICE PROMO RATE
Up to 3 Mbps download $42/mo $29.95/mo
Up to 6 Mbps download $52/mo $34.95/mo
Up to 18 Mbps download $62/mo $44.95/mo
up to 45 Mbps download $82/mo $44.95/mo
2.2.2 EarthLink
EarthLink provides DSL based business services in the region starting at $80 per month and
offering speeds up to 6 Mbps with 99.9% network availability.31
2.2.3 MegaPath
MegaPath is an Internet service provider that offers speeds of up to 20 Mbps download and 1
Mbps upload for business customers in certain parts of Palo Alto.32 The lowest plan offered by
them is for 1.5 Mbps download speeds at $45 per month.
2.2.4 Sonic
Sonic offers residential internet services at 20 Mbps and 40 Mbps at a rate of $40 per month and
$60 per month respectively in Palo Alto. The service also includes a phone connection. The
provider is promoting the development of gigabit fiber connectivity on a neighborhood by
neighborhood basis depending on the interest shown by consumers.33 Sonic also offers business
internet and phone service in some locations in Palo Alto for $89.95 per month for speeds of 40
Mbps.
2.3 Satellite
Satellite Internet access is available in the area as well and three providers offer the service:
HughesNet, Exede, and DishNET.
2.3.1 HughesNet
HughesNet has four packages available for residential users: 1) Connect Satellite with speeds up
to 5 Mbps download/1 Mbps upload, a monthly data cap of 5 GB, and 5 GB of “bonus” data (10
GB total) for $49.99 per month2) HughesNet Power with speeds up to 10 Mbps download/1
31 http://www.earthlinkbusiness.com/DSL/, accessed March 2015.
32 http://www.megapath.com/services/, accessed May 2015.
33 https://www.sonic.com/availability ,accessed May 2015.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
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Mbps upload, a 10 GB monthly data cap, and 10 GB of bonus data (20 GB total) for $59.99 per
month; and 3) HughesNet Power Pro with speeds up to 10 Mbps/2 Mbps, a monthly data cap of
15 GB, and 15 GB bonus bytes (30 GB total) for $79.99 per month; and 4) HughesNet Power Max
with speeds up to 15 Mbps/2 Mbps, a monthly data cap of 20 GB, and 20 GB of bonus data (40
GB total) for $129.99 per month.
HughesNet offers two packages for Internet services to small businesses. The Business 50
package provides speeds of up to 5 Mbps download and 1 Mbps upload for $69.99 per month
with a 5 GB per month anytime allowance and 10 GB bonus bytes from 2am to 10 am for a total
monthly data allowance of 15 GB. This package requires a two year agreement and only supports
up to five users. The Business 100 package provides the same download and upload speeds of
the Business 50 package, but offers a higher data allowance threshold of 10 GB per month
anytime and 15 GB bonus bytes from 2 am to 10 am for a monthly data allowance of 25 GB. This
package also requires a two year agreement and is best for 5 to just over 10 users.
2.3.2 Exede
Exede offers three Internet packages in the region each with up to 12 Mbps download and 3
Mbps upload speeds. These packages are: 1) Evolution 5 with a monthly 5 GB data cap (excluding
emails and web pages) for $49.99 per month 2) Evolution 20 with a 20 GB monthly data cap for
$69.99 per month and 3) Freedom with unlimited access for $99.99 per month.
2.3.3 DishNET
DishNET offers three residential Internet packages in the region. These packages are: 1) Up to 5
Mbps download speed with a monthly 5 GB data cap and 5 GB of bonus data for $49.99 per
month with a 24‐month commitment; 2) download speeds up to 10 Mbps with a 10 GB monthly
data cap and 10 GB of bonus data for $59.99 per month with a 24‐month commitment; and 3)
up to 10 Mbps download speed with a 15 GB monthly data cap and 15 GB of bonus data for
$79.99 per month with a 24‐month commitment.
2.4 Wireless
There are six providers that offer wireless Internet services in Palo Alto: Verizon, Sprint, AT&T,
Cricket Wireless, T‐Mobile, and Etheric Networks.
2.4.1 Verizon
Verizon offers two 4G LTE data packages with multiple choices for data allowances and pricing
depending on the desired mobility and equipment chosen. The HomeFusion Broadband Package
is a data‐only 4G LTE service with WiFi connectivity and wired Ethernet for up to four devices.
There are download speeds of 5 Mbps to 12 Mbps and upload speeds of 2 Mbps to 5 Mbps.
Monthly prices range from $60 for a 10 GB data allowance to $120 for a 30 GB data cap. Overages
are charged at $10 per additional GB. A two‐year contract is required with a $350 early
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
12
termination fee. Verizon offers a $10 monthly deduction for every month completed in the
contract. The Ellipsis JetPack provides a mobile solution with download speeds of 5 Mbps to 12
Mbps and upload speeds of 2 Mbps to 5 Mbps. Prices for the 12 options of data allowances range
from $30 per month for a 4 GB data allowance to $335 per month for 50 GB of data, in addition
to a monthly line access charge of $20.The device is $0.99 with a two‐year contract. There is a
$35 activation fee.
2.4.2 Sprint
Sprint offers 4G LTE wireless data in Palo Alto. The three data packages offered range from 100
MB per month data allowance for $15 per month to 6 GB per month data allowance for $50 per
month to 12 GB per month data allowance for $80 per month. Each MB over the limits is billed
at a cost of $.05. A two‐year contract is required as well as an activation fee of $36, and
equipment charges for three different types of devices. There is also an early termination fee of
$200.
2.4.3 AT&T
AT&T also provides 4G LTE wireless data service in the area, but only offers one package type
with a 5 GB per month download allowance for $50 per month. There is an overage fee of $10
per 1 GB over the limit. There are also equipment charges with or without a contract and an
activation fee.
2.4.4 Cricket Wireless
Cricket Wireless, which recently became a subsidiary of AT&T, offers 4G LTE wireless service in
Palo Alto with a download speed of up to 8 Mbps with three options for data allowance packages.
Starting at $35 per month for 1 GB of data allowed there are also options for data allowances of
3 GB ($45) and 10 GB ($55).Data used beyond allowances are at reduced speeds. There is a $79.99
modem fee for an additional device. There is a $15 activation fee, but no contract or early
termination fees.
2.4.5 T‐Mobile
Of the cellular wireless providers in the area, the least expensive wireless data option offered is
from T‐Mobile for $20 per month with a limit of 1 GB per month. T‐Mobile offers additional
capabilities and increasing data limits at incremental costs in a total of six packages up to $70 per
month for up to 11 GB of data. Depending upon current promotions, the $35 activation fee may
be waived.
CTC Report | City of Palo Alto – Appendix A: Existing Market Assessment | July 2015
13
2.4.6 Etheric Networks
Etheric Networks is a wireless internet service provider (WISP) that provides services in Palo Alto
for speeds up to 30 Mbps.34 The range of speeds and pricing available are indicated in Table 5. A
radio and antenna fee of $299 is also charged during setup and installation.
Table 5: Etheric Networks Internet Services
PACKAGE INTERNET SPEED PRICE
Bronze Up to 5 Mbps download $85/mo
Silver Up to 10 Mbps download $99/mo
Gold Up to 20 Mbps download $139/mo
Platinum up to 25Mbps download $179/mo
Diamond up to 30 Mbps download $229/mo
34 http://ethericnetworks.com/residential/. accessed May 2015.
Fiber Exterior WAP Equipment Aerohive WAP NW Equip
Site #Site name: # sites Address:Monthly Install Mount NIU Monthly WAP Cabling Equipment Totals
Proceed with
Deployment
2 Cubberley 1 4000 Middlefield Rd. 2,361$ 4,200$ 3,500$ 142$ 8,500$ 16,200$
Theater waiting area 2 47$ 2,800$ 800$ 3,600$
Classrooms A ‐ H8 560$ 33,600$ 24,000$ 57,600$
Artist Studio 1 70$ 4,200$ 3,000$ 7,200$
Dance Studio U1 23$ 1,400$ 400$ 1,800$
3 Lucie Stern 1 1305 Middlefield Rd. 647$ 2,400$ 6,000$ 8,400$
Children's Theatre Lobby 2 47$ 2,800$ 800$ 3,600$
Courtyard in front of outdoor theatre 2 47$ 2,800$ 800$ 3,600$
4 & 5 Golf course: Pro Shop & Bay Café 2 1875 Embarcadero Rd. 1,351$ 3,900$ 7,000$ 1,000$ 11,900$
Pro Shop 4 93$ 5,600$ 1,600$ 7,200$
Bay Café 4 93$ 5,600$ 1,600$ 7,200$
9 Lytton Plaza: entire plaza 1 202 University Ave. 635$ 21,000$ 4,500$ 3,500$ 123$ 1,400$ 400$ 6,000$ 36,800$
Monthly Total 4,994$ 1,245$ 6,239$
Installation Total 31,500$ 4,500$ 14,000$ 60,200$ 33,400$ 21,500$ 165,100$
Assumptions and notes:Notes
1 Each connection contains two new fibers from specified location to CC Level A.WAP ‐ Wireless Access Point ‐ $1400
2 Established government rate applied NIU‐ Network interface Unit ‐ $3500
3 Prevaling Utility construction costs Splice ‐ tap point into existing fiber
4 CPAU Fiber does not perform substructure work
5 Support during business hours only (8‐5)
6 Estimates use existing poles at all locations
7 These estimates are high level "desktop" estimates. Actual fees to be determined by field investigation and contractor bids.
Construction Fees
Overhead per span is $1,500
Underground is $75/ft.
Small splice box in the sidewalk $5,000+
Palo Alto Wi‐Fi sites Installation & Monthly Costs (City Staff Estimates )
EXHIBIT E
Utilities Department
Version:1.0
Fiber-to-Fiber Premises and Wireless Communication Initiative Page 1 of 1 Date Last Updated
February 1, 2017
Fiber Optic Network Rebuild Project Summary
FIBER-TO-THE-PREMISES AND WIRELESS COMMUNICATIONS INITIATIVES
February 1, 2017
Project Description: The rebuild project will install new aerial duct or substructure (conduit and boxes), in addition to
fiber backbone cable to increase capacity for sections of the dark fiber ring that are at or near capacity . This project will
allow City of Palo Alto Utilities (“CPAU”) to meet customer requests for services. The project areas primarily cover the
Stanford Research Park, Palo Alto Internet Exchange/Equinix at 529 Bryant, and Downtown areas. This project basically
“overlays” new fiber over existing fiber routes in the network. Existing fiber will continue to serve City facilities and
commercial dark fiber customers.
2016: As a first step, CPAU retained Celerity Integrated Services, Inc. to provide a one-time comprehensive review and
audit of the City dark fiber optic network. Celerity completed the review and audit and provided a physical description
of the network; documented the number of fiber strands, in addition to conducting an inspection of 90 fiber
nodes/cabinets (i.e. network splice points) to identify what is labeled within the individual nodes/cabinets.
•CPAU Engineering is currently working with CAD Masters to reconcile the audit data provided by Celerity with
various fiber databases, in addition to rebuilding front-end databases to facilitate fiber assignments at the
engineering level and to improve network mapping.
2017-2021 Capital Improvement Projects: The budget for the rebuild was reduced by the City Council during the Fiscal
Year 2016 budget process. The Fiscal Year 2017 budget reflects this adjustment from $2.4 million to $1.3 million. The
rebuild is a CIP charged to “system improvements.”
Rebuild Work in Progress
o Route from PAIX at 529 Bryant to the Park Boulevard Substation. Substructure work, fiber pulling and
cabinet installation are nearing completion. The new fiber installed for the backbone rebuild is 312-
count single-mode fiber (2 x 144-count single-mode fiber, plus 24-count single-mode fiber).
•Upcoming work scheduled over the next 12 months:
o Route from Park Substation to Hansen Substation
o Route from Hansen Substation to Stanford Research Park
o Additional phases/routes to be determined.
Estimated cost is between $500,000 and up to $1,000,000 for substructure work. Approximately another $250,000 for
the overhead portion of the work. CPAU crews are performing the equipment installation, cable pulling and
terminations. CPAU’s substructure contractor is installing the conduit and boxes.
EXHIBIT F
Page 1 of 4
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 5, 2017
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt a Resolution Approving the Fiscal Year 2018 Gas
Utility Financial Plan with no changes to Gas Distribution Rates
RECOMMENDATION
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council:
Adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Gas Utility
Financial Plan (Attachment B)
EXECUTIVE SUMMARY
The FY 2018 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for
FY 2018 through FY 2027. Gas rates were last adjusted by 8% on July 1, 2016, and the FY 2017
Financial Plan included a tentative rate increase of 9% for FY 2018. However, better than
expected ending Operations reserve levels in FY 2016, coupled with a two year delay in starting
new gas main replacement projects, as well as recovering post-drought sales, have improved
the outlook for the gas fund. Staff proposes utilization of reserves and a series of smaller rate
increases over the next three years to minimize the impact to customers. The proposed FY 2018
Gas Utility Financial Plan includes no gas rate increase on July 1, 2017 followed by rate
increases of 4 to 6 percent over the next four years. In addition, the plan includes proposed
transfers to the Operations Reserve of $1.2 million and $4.8 million from the Rate Stabilization
Reserve in FY 2018 and FY 2019, respectively, to ensure that there are appropriate financial
reserves for contingencies. The Rate Stabilization Reserve is projected to be zero by the end of
FY 2020.
Gas Utility expenses are projected to increase by roughly 3 to 4 percent annually from FY 2017
to FY 2027 due primarily to increased gas supply costs (monthly commodity purchases as well
as carbon neutral plan and cap and trade allowance purchase costs), as well as higher
operations and maintenance expenses. In the short term, some of these costs are related to the
cross-bore inspection program. Capital improvement program (CIP) costs have increased as the
economy has improved, and higher bids have required some redesign of planned projects .
Page 2 of 4
While existing projects are underway and staffing issues are addressed, new main replac ement
projects are not planned until FY 2019.
Gas usage was trending downward over the last several years, most likely due to relatively
warm winter heating seasons, as well as lower hot water usage during the drought, but a cooler
winter and the end of drought restrictions has brought increased usage. Gas usage has started
to recover somewhat, but as with water, it is difficult to determine if changes in behavior will
persist, reducing gas usage long term.
BACKGROUND
Every year staff presents the UAC with Financial Plans for its Electric, Water, Gas, 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 not
revised the preliminary projections presented at that meeting.
DISCUSSION
Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure
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.
Proposed Actions for FY 2017
The FY 2017 Gas Utility Financial Plan includes the following proposed action:
1. Reduce the $5.3 million transfer from the Rate Stabilization Reserve to the Operations
Reserve proposed in the FY 2017 Gas Financial Plan to zero.
Proposed Actions for FY 2018
The FY 2018 Gas Utility Financial Plan also includes the following proposed action:
1. Transfer $1.2 million from the Rate Stabilization Reserve to the Operations Reserve.
The reserve transfers will enable staff to maintain sufficient funds in the Gas Operations
Reserve levels while spreading the required rate increases for the gas utility over several years.
These proposed actions are described in more detail in the FY 2018 Gas Financial Plan
(Attachment B).
Staff proposes no adjustments to gas rates at this time.
Page 3 of 4
FY 2018 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table 1 shows the projected rate adjustments over the next five years and their impact on the
annual median residential gas bill.
Table 1: Projected Rate Adjustments, FY 2017 to FY 2021
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Gas Utility 0% 4% 6% 6% 5%
Estimated Bill Impact ($/mo)* $- $1.79 $2.79 $2.96 $2.61
* estimated impact on median residential gas bill, which is currently $44.72 for CY 2016.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 1, 2017, additional
budget information and changes to usage projections have modified outer years, but the FY
2018 proposal of no rate increase remains the same.
Gas Bill Comparison with Surrounding Cities
Table 2 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of May 2016 (to illustrate a summer month bill) and
March 2017 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2016 was $426.72, about 20% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities
Table 2: Residential Monthly Gas Bill Comparison
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(March
2016)
30 34.88 41.57 -16%
(Median) 54 54.53 74.82 -27%
80 85.50 120.77 -29%
150 180.51 255.05 -29%
Summer
(Jul 2015)
10 19.93 17.77 12%
(Median) 18 21.94 21.46 2%
30 35.13 41.55 -15%
45 52.91 66.66 -21%
Monthly gas bills for commercial customers for various usage levels for rates in effect as of
March 1, 2016 are shown in Table 3. Bills for CPAU customers at the usage levels shown are
around 10% to 33% higher for commercial customers than for PG&E customers. This is a
substantial improvement over the calendar year 2013 bill comparison, when commercial gas
bills for CPAU customers were 27% to 44% higher than for PG&E customers. This is primarily
attributable to PG&E's increased distribution rates as the commodity rates for CPAU and PG&E
are very similar, both being based on spot market gas prices.
Table 3: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect Mar.1, 2017)
Usage I Gas Bill ($/month) " (therms/mo) Palo AltQ PG&E Difference
I
500 616 545 13%
5,000 5,459 4,957 10%
10,000 10,840 8,856 22%
50,000 53,788 40,453 33%
NEXT STEPS
The Finance Committee is scheduled to review the FY 2018 Gas Financial Plan on May 16, 2017.
The City Council will consider adopting the Financial Plan as part of the FY 2018 budget review
and adoption process.
RESOURCE IMPACT
See the attached FY 2018 Gas Financial Plan for a more comprehensive overview of projected
cost and revenue changes for the next ten years.
POLICY IMPLICATIONS
The proposed Gas Financial Plan is consistent with Council-adopted Reserve Management
Practices.
ENVIRONMENTAL REVIEW
The UAC's review and recommendation to Council on the FY 2018 Gas Financial Plans does not
meet the California Environmental Quality Act's definition of a project, pursuant to Public
Resources Code Section 21065, thus no environmental review is required.
ATTACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2018 Gas Utility
Financial Plan
B. Proposed FY 2018 Gas Utility Financial Plan
PREPARED BY: ERIC KENISTON , Acting Rates Manager C ~-~C
REVIEWED BY: J~N ABENDSCHEIN, Assistant Director, Resource Managemen~
L ~-::==:-.-. APPROVED BY:
EDSHIKADA
Utilities General Manager
Page 4 of 4
Attachment A
* NOT YET APPROVED *
170320 jb 6053929
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 Gas 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 Gas Utility Financial Plan.
SECTION 2. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
/ /
/ /
/ /
/ /
/ /
/ /
Attachment A
* NOT YET APPROVED *
170320 jb 6053929
Code Section 21065, and therefore, no environmental assessment is required.
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 GAS
UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 2 | Page
GAS UTILITY FINANCIAL PLAN
FY 2018 TO FY 2027
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 6
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................... 8
Section 4A: Gas Utility History ..................................................................................................... 8
Section 4B: Customer Base ........................................................................................................ 10
Section 4C: Distribution System ................................................................................................. 11
Section 4D: Cost Structure and Revenue Sources ...................................................................... 12
Section 4E: Reserves Structure ................................................................................................... 12
Section 4F: Competitiveness ...................................................................................................... 13
Section 4G: Gas Supply Rates .................................................................................................... 14
Section 5: Utility Financial Projections ................................................................................. 15
Section 5A: Load Forecast .......................................................................................................... 15
Section 5A: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 16
Section 5B: FY 2016 Results ....................................................................................................... 17
Section 5C: FY 2017 Projections ................................................................................................. 18
Section 5D: FY 2018-FY 2027 Projections .................................................................................. 18
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 19
Section 5G: Long-Term Outlook ................................................................................................. 21
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 3 | Page
Section 6: Details and Assumptions ..................................................................................... 22
Section 6A: Gas Purchase Costs ................................................................................................. 22
Section 6B: Operations .............................................................................................................. 23
Section 6C: Capital Improvement Program (CIP) ....................................................................... 24
Section 6D: Debt Service ............................................................................................................ 26
Section 6E: Equity Transfer ........................................................................................................ 27
Section 6F: Revenues ................................................................................................................. 27
Section 6G: Communications Plan ............................................................................................. 28
Appendices ......................................................................................................................... 30
Appendix A: Gas Financial Forecast Detail ................................................................................ 31
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 32
Appendix C: Gas Utility Reserves Management Practices ......................................................... 34
Appendix D: Description of Gas Utility Cost Categories ............................................................ 38
Appendix E: Gas Utility Communications Samples .................................................................... 39
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 4 | Page
SECTION 1: DEFINITIONS AND ABBREVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
CARB: California Air Resources Board
CIP: Capital Improvement Program
CNG: Compressed Natural Gas
CPAU : City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a
portion of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal
boring” construction practices.
Distribution: transportation of gas to customers.
GMR Program: Gas Main Replacement Program
Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from
PG&E City Gate.
Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where
the northern end of PG&E’s Redwood Transmission Pipeline is located.
MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms.
Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers
are typically measured in MMBtu.
O&M: Operations and Maintenance
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas
delivered to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s
Redwood Transmission Pipeline) is said to have been delivered at PG&E Citygate.
PVC: Polyvinyl chloride, a plastic gas main material
Summer: April 1 to October 31
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Therms measure the heating value of the gas, rather than its volume.
Transmission: transportation of gas between major gas delivery hubs via a gas transmission
pipeline, such as PG&E’s Redwood pipeline.
UAC : Utilities Advisory Commission, an appointed body that advises the City Council on CPAU
issues.
Winter: November 1 to March 31
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 5 | Page
SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Gas 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 2A : OVERVIEW OF FINANCIAL P OSITION
From FY 2018 through FY 2027, non-commodity costs are projected to increase at 3% to 4% per
year. In the short term, some of these costs are related to the cross-bore inspection program,
as well as cap-and-trade and carbon neutral allowance purchase costs. Capital improvement
program (CIP) costs have increased as the economy has improved, and while CPAU plans a new
gas main replacement project every year, recent larger than expected bids have required
resizing and redesign of some existing plan projects. Because of this, the next new main
replacement project will take place in FY 2019. As a result, CIP costs for FY 2017 and 2018 will
be lower than normal by around $3.7 million. The Gas Utility expenses over the period of this
financial plan are shown in Table 1 below.
Table 1: Gas Utility 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
Commodity costs 8,127 13,042 15,437 14,931 15,304 15,584 16,021 16,569 17,227 17,909 18,679 19,235
Operations 17,239 21,687 22,587 22,901 22,559 23,022 24,403 25,292 26,221 27,195 28,222 27,982
Capital Projects 5,017 2,214 2,074 5,725 5,960 6,145 6,335 6,525 6,721 6,923 7,130 7,344
TOTAL 30,384 36,943 40,098 43,557 43,823 44,751 46,759 48,386 50,169 52,027 54,032 54,561
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2. No increase is projected for FY 2018.
Table 2: Projected Gas 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 Financial Plan 0% 4% 6% 6% 5% 3% 3% 2% 1% 0%
FY 2017 Financial Plan 9% 7% 4% 1% 1% 1% 1% 1% 1% N/A
FY 2016 Financial Plan 4% 4% 4% 3% 3% N/A N/A N/A N/A N/A
The Gas Rate Stabilization Reserve is used to smooth rate increases over several years. This
Financial Plan projects that these reserves will be exhausted by the end of FY 2020. The Gas CIP
Reserve can be used to offset one-time unanticipated capital costs. Table 3 shows the projected
reserve transfers over the forecast period.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 6 | Page
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 0 (1,208) (4,810)
Operations 0 1,208 4,810
SECTION 2B : SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2017:
1. Amend the proposed $5.3 million transfer from the Rate Stabilization Reserve to the
Operations Reserve, as proposed in the FY 2017 Gas Financial Plan, to no transfer, based
on projected ending Operations Reserve levels.
Staff proposes the following actions for the Gas Utility in FY 2018:
2. No distribution rate increase for FY 2018. See Section 3B: Current and Proposed Rates
for more details.
3. Transfer $1.2 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3C: Proposed Reserve Transfers for more details.
SECTION 3: DETAIL OF FY 2018 RATE AND RESERVE PROPOSALS
SECTION 3 A : RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s current rates are based on the methodology from the April 2012
Gas Utility Cost of Service Study completed by Utility Financial Solutions1. In preparation for an
update to the study, staff discussed a proposed scope with the Utilities Advisory Commission in
October 2016, and the Council in November 2016 2. The updated study is projected to be
completed by the end of FY 2017, and will provide guidance for the next proposed rate action,
currently slated for FY 2019.
SECTION 3 B : CURRENT AND PROPOSED RATES
On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly
to match changes in gas market prices.3 In addition, monthly service charges were increased to
recover the cost of providing gas service to customers. In January 2015, the Council adopted a
new rate component to collect the costs of purchasing allowances for the purpose of
compliance with the State’s cap-and-trade program 4. This component will change depending on
the cost of allowances and gas demand. In October 2016, the Council adopted a resolution
changing the Local Transportation rate (which had been collapsed into the Distribution rate in
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
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2015 to streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to
Wholesale/Resale Customers (G-WSL) charge to Palo Alto.5 This went into effect November 1,
2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a
carbon neutral gas portfolio by FY 2018.6 The plan is for costs associated with the plan to be a
passed through directly to customers as well, although the rate impact is not to exceed $0.10
per therm.
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately
metered residential customers are charged on a tiered basis, differentiated by season. During
the winter months, the first 2 therms per day (60 therms for a 30 day billing period) are charged
a base price per CCF, and all additional units charged a higher price per therm. During the
summer months, the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing
period. Commercial customers pay a uniform price for each therm used.
Table 4 shows the current monthly service charges for all rate schedules. Table 7 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Three
years’ worth of volumetric rate history can be found on Palo Alto’s website.7 Some recent
commodity price history is discussed in Section 6A: Gas Purchase Costs.
Table 4: Current Monthly Service Charges
Rate Schedule Monthly Service Charge ($/month)
Current ( as of 7/1/16)
G-1 (Residential) $10.32
G-2 (Small Commercial) $78.23
G-3 (Large Commercial) $377.43
G-10 (CNG) $52.93
5 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165
6 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882
7 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399
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Table 5: Current Gas Distribution Charges
Current ( as of 11/1/16)
G-1 (Residential)
Tier 1 Rates 0.3933
Tier 2 Rates 0.9319
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.5767
G-3 (Large Commercial)
Uniform Rate 0.5687
G-10 (Compressed Natural Gas)
Uniform Rate 0.0093
No changes to distribution rates are proposed for FY 2018.
SECTION 3 C : PROPOSED RESERVE TRANSFERS
In the FY 2017 Financial Plan, $5.3 million was proposed to be transferred from the Rate
Stabilization Reserve into the Operations Reserve.
Lower actual expenses in FY 2016 as well as projected lower expenses in FY 2017 are expected
to result in higher ending reserve balances than initially projected, so staff recommends not
transferring funds at this time. A tentative transfer of $1.2 million in FY 2018, followed by $4.3
million in FY 2019, is included in the financial projections in this Financial Plan. These will enable
CPAU to maintain adequate Operations Reserve levels while moderating the pace of increase in
gas rates. The impact of these transfers on reserves levels can be seen in Appendix A: Gas 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 : GAS UTILITY HISTORY
On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo
Alto Gas Company and continue it as a municipal enterprise. At the time, the system comprised
21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the gas, which was
synthesized from coal at its Potrero facility. Almost immediately the City faced challenges.
Losses were at nearly 25% according to PG&E’s master meter, and PG&E had filed with the
Railroad Commission (the forerunner to today’s Public Utilities Commission) to increase rates
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by nearly 72.5%. Despite these initial hurdles, Palo Alto’s system grew tremendously, and by
1924 revenues had exceeded those of the electric utility. Sales were such that the annual
reports of the time noted gas usage “appears to be greater than that of any other city in the
state, showing that gas is a very popular form of fuel in Palo Alto.” Just prior to the acquisition
of the neighboring town of Mayfield’s gas system (centered around today’s California Avenue)
in 1929, the miles of main in service and customers connections had doubled.
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased
from Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic
feet (MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year. This would
enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
main replacement rate to ensure a robust gas distribution system, PG&E was underspending on
safety-related infrastructure, according to a past audit.9
In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also
participating in major changes to the structure of the gas industry in California. Until 1988 CPAU
had a formal policy of setting its rates equal to PG&E’s rates and successfully did so with the
exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981)
as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the
wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began
deregulating the natural gas industry in California, the Gas Utility began purchasing gas from
suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”10 which enabled the
Gas Utility (along with other local transportation-only customers) to obtain transmission rights
on PG&E’s Redwood transmission pipeline running from Malin, Oregon into California.
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990
9 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations, Overland Consulting,
made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013
10 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being
Gas Accord V, application A.09-09-013
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In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s
supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001.
The Council approved drawing down reserves to provide ratepayer relief and, for two years
following the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001
the Council approved a hedging practice of buying fixed price gas one to three years into the
future. After reaching a low point in October 2001, prices continued to rise, and as a result the
CPAU hedging strategy frequently resulted in a wholesale supply cost advantage compared to
PG&E until prices began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale
supply costs became higher than market gas prices due to fixed price contracts entered into
prior to 2008. As a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for
several years. In 2012 Council approved a plan to formally cease the hedging strategy and
purchase all gas on the short-term (“spot”) markets. As of July 1, 2012, the commodity portion
of the gas rates changes every month based on the spot market gas price.
SECTION 4 B : CUSTOMER BASE
CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,400 customers are connected to the natural gas system,
approximately 21,700 (93%) of which are residential and 1,700 (7%) of which are non-
residential. Residential customers consume about 10 to 12 million therms of gas per year,
roughly 45% of the gas sold, while non-residential customers consume 55% (about 14 to 15
million therms). Residential customers use gas primarily for space heating (46% of gas
consumed) and water heating (42%), with the remainder consumed for other purposes such as
cooking, clothes drying, and heating pools and spas.11 Non-residential customers use gas for
space and water heating (73% of gas consumed), cooking (20%), and industrial processes
(6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the
PG&E City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s
transmission pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower
priced gas at that location. CPAU does not produce or store any natural gas, and purchases gas
in the monthly and daily spot markets. The cost of the purchased gas is passed through directly
to customers through a rate adjuster that varies monthly with market prices. In a similar
fashion, the cost for local transportation has now been tied to PG&E’s G-WSL rate schedule,
and varies when and if PG&E changes their rate schedule. The cost of purchased gas and PG&E
local transportation service usually account for roughly one third of the utility’s expenditures.
11 http://energyalmanac.ca.gov/naturalgas/overview.html
12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are
for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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SECTION 4 C : DISTRIBUTION SYSTEM
To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas
mains (which transport the gas to various parts of the city) and 23,400 gas services (which
connect the gas mains to the customers’ gas lines). These mains and services, along with their
associated valves, regulators, and meters, represent the vast majority of the infrastructure used
to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over
time, the expense of which normally accounts for around 15 to 20% of the utility’s
expenditures. Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, 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 roughly half of the utility’s expenses. In addition to these ongoing
activities, CPAU has conducted a program to find and replace cross-bores over the last several
years. Currently, $1 million is budgeted per year for the cross-bore program through FY 2019.
However, the ongoing cross-bore investigation may require additional funding, or extend for
longer into the future, as the remaining sewer lines are more difficult to examine than the
majority of the wastewater collection system that has been examined to date.
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Figure 2: Cost Structure (FY 2016)
57%27%
16%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2016)
93%
7%
Sales of Gas
Other Revenue
SECTION 4 D : C OST S TRUCTURE AND R EVENUE S OURCES
As shown in Figure 1, the Gas
Utility receives 93% of its revenue
from sales of gas and the
remainder from capacity and
connection fees, interest on
reserves, and other sources.
Appendix A: Gas Utility Financial
Forecast Detail shows more detail
on the utility’s cost and revenue
structures.
As shown in Figure 2, in FY 2016,
gas purchase costs accounted for
roughly 27% of the Gas Utility’s
costs. This percentage can vary
widely from year to year, as this
cost is based upon market
purchases, but now also includes
costs related to cap and trade. In
FY 2016, Palo Alto received a
large transportation rate
settlement from PG&E, which
lowered costs substantially. This
stemmed from the CPUC’s
findings related to the San Bruno
pipeline explosion. Operational
costs represented roughly 57%, and capital investment was responsible for the remaining 16%.
CIP is normally about 20% of expenses, but this may be lower in times when projects are
deferred, as will happen in FY 2017 and FY 2018.
SECTION 4 E : RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. These
are summarized below, but see Appendix C: Gas 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.
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• 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, Water, 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.
This type of reserve is used in other utility funds (Electric, Water, and Wastewater
Collection) as well.
• Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is
used to manage yearly variances from budget for operational gas costs. This type of
reserve is used in other utility funds (Electric, Water, 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 : COMPETITIVENESS
Table 6 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of May 2016 (to illustrate a summer month bill) and
March 2017 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2016 was $426.72, about 20% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 6: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(March 2017)
30 34.88 41.57 -16%
(Median) 54 54.53 74.82 -27%
80 85.50 120.77 -29%
150 180.51 255.05 -29%
Summer
(May 2016)
10 19.93 17.77 12%
(Median) 18 21.94 21.46 2%
30 35.13 41.55 -15%
45 52.91 66.66 -21%
Table 7 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of March, 2017. Bills for CPAU customers at the usage levels shown are around 10%
to 33% higher for commercial customers than for PG&E customers. This is a substantial
improvement over the calendar year 2013 bill comparison, when commercial gas bills for CPAU
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customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to
PG&E’s increased distribution rates as the commodity rates for CPAU and PG&E are very similar,
both being based on spot market gas prices.
Table 7: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect March, 2017)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 616 545 13%
5,000 5,459 4,957 10%
10,000 10,840 8,856 22%
50,000 53,788 40,453 33%
SECTION 4G : GAS SUPPLY RATES
Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies
with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to
customers on a monthly basis. The actual commodity prices are shown in Figure 3. As shown,
commodity prices have fluctuated by around $0.20 over the last two years, but have generally
been lower than prices seen in 2013 and 2014.
Figure 3: Gas Commodity Rates from July 2012 through March 2017
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SECTION 5: UTILITY F INANCIAL PROJECTIONS
SECTION 5 A : LOAD F O RECAST
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions. As shown
in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year. Usage
dropped dramatically in the 1976/1977 drought when customers saved significant amounts of
(hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage
was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas
prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly
200%. From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer
investments in energy efficiency.
In 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to
tumble to historic lows. In FY 2017, as the drought has eased and a relatively normal winter has
progressed, gas usage has started to increase again.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat
and stay stable over the forecast period, although changes such as replacement of gas
appliances with electric appliances or customer behavior may result in lower long run usage. As
with prior drought/gas usage declines in the past, it is likely that consumption will not come
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back to pre-conservation levels. It is too early to tell, however, where the new ‘normal’ level of
consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5 A : FY 2012 TO FY 2016 COST AND REVENUE TRENDS
Figure 6 and Appendix A: Gas 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 gas utility decreased substantially between 2012 and 2016 due to
lower gas sales. Market prices for gas supplies are shown in Figure 3 above. FY 2014 and 2015
were notable due to the fact that no new funding was added for main replacement projects, to
permit the completion of a backlog of projects which had previously been funded. This allowed
for backlogged gas main replacement projects to be started, and used existing capital reserves.
Starting in FY 2012, additional funding for gas cross-bore inspections increased Operations
costs.
Revenues have generally matched expenses in most years. As shown in Figure 6 below,
revenues were below cost in FY 2011 and FY 2013 and nearly at cost in FY 2016. The absence of
funding for main replacement projects in FY 2014 and FY 2015, as well as the availability of
relatively large reserves, forestalled the need for rate increases until now.
As shown in Figure 6, the last adjustment to gas distributionrates was in July 2016 when rates
were increased by 8%. In FY 2012, commodity rates were changed to a market-based, monthly
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pass-through cost—and commodity rates (and usage) fell, so revenues actually declined in FY
2013 after the rate increase.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2016 and Projections through FY 2027
SECTION 5 B : FY 2016 RESULTS
Sources of funds for FY 2016 were in line with projections, but expenses related to Purchases
and Capital spending came in well below expected budget. Total FY 2016 expenses were $30.4
million compared to projections of $35.9 million in the FY 2017 Financial Plan. Table 8
summarizes the variances from forecast.
Table 8: FY 2016, Actual Results vs. Financial Plan Forecast
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (1,132,000) Cost savings
Operations cost savings and reclass (2,498,000) Cost savings
Capital Improvement cost spending (1,872,000) Cost savings
Operations cost savings (31,000) Cost savings
Net Cost / (Benefit) of Variances $(5,465,000)
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SECTION 5 C : FY 2017 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast.
However, a main replacement projected budgeted for this year will not be started until FY
2019. Table 9 summarizes the current and projected variances from FY 2017 Financial Plan.
Table 9: FY 2017 Projected Results vs. Financial Plan Forecast
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (984,000) Revenue increase
Other revenues and interest higher than forecast (742,000) Revenue increase
Operations & maintenance, Customer service and
purchase cost increases
617,000 Cost increase
Main replacement projects delayed (4,091,000) Cost savings
Net Cost / (Benefit) of Variances ($5,200,000)
SECTION 5 D : FY 2018-FY 2027 PROJECTIONS
As can be seen in Figure 6 above, costs for the Gas Utility are projected to rise in FY 2017, then
are projected to increase at around 3% per year through FY 2026. In Operations, this is due to
an additional continuing $1 million for cross-bore inspections (this expense is projected to
continue for at least three years), as well as general inflationary increases of around 2.6% per
year. Salaries and benefits expenses are projected to rise at nearly 4% per year, per the City’s
Long Range Financial Plan. New CIP main replacement programs are projected to be put on
hold until FY 2019. At that point, CIP spending is projected to return to normal levels (around $6
million), then grow at around 2% per year thereafter. Gas commodity costs are the most
variable component. At the time the budget was developed in December 2016, gas supply
prices were projected to increase by around 3 to 4% per year. Since this is a pass-through cost
to customers, the risk of these costs being higher or lower than expected has a minimal impact
on reserves.
As shown in Figure 7, the Rate Stabilization Reserves are projected to be depleted by FY 2020.
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Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2016 and Projections through FY 2027
SECTION 5 E : RISK ASSESSMENT AND RESERVES ADEQUACY
The Gas Utility’s primary contingency reserve, the Operations Reserve, is projected to be within
guideline levels throughout the forecast period, barring either short-run budget savings and/or
larger future increases. Figure 8 shows the Operations Reserve recovering to the target level by
FY 2027 with the projected rate trajectory.
Figure 8: Operations Reserve Adequacy
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Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 10 summarizes the risk assessment calculation for the Gas Utility through FY 2022. The
same methodology is used for FY 2023 through FY 2027 as well. The risk assessment includes
the revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget
year.
Table 10: Gas Risk Assessment ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total non-commodity revenue $20,465 $21,676 $23,503 $25,557 $27,559
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,282 $3,476 $3,769 $4,098 $4,419
CIP Budget $809 $4,421 $4,617 $4,762 $4,911
CIP Contingency @10% $81 $442 $462 $476 $491
Total Risk Assessment value $3,363 $3,918 $4,231 $4,575 $4,910
Finally, the CIP Reserve was created at the end of FY 2015 to act as a contingency reserve for
capital improvement projects. Current guidelines state that the balance of this reserve should
fall between 12 and 24 months of budgeted CIP expense.
At the end of FY 2016, the sum of the CIP Reserve and existing Commitments was a bit over $10
million, as shown in Figure 7. Based upon FY 2017’s adjusted CIP budget, this is well above the
maximum reserve level of $1.97 million. However, the next two years are anomalous in that a
main replacement project is not scheduled. As a normal year maximum would be between $9
to $11 million, staff does not recommend reducing the CIP reserve at this time, especially in
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light of the fact that CIP project costs have been increasing. Staff will continue to review this
reserve and the appropriateness of the current minimum and maximum guideline levels.
SECTION 5 F : LONG-TERM OUTLOOK
In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity
costs. A variety of long-term trends could affect commodity costs either positively or negatively.
Continuing improvement in gas extraction technology, such as fracking, could continue to
create generous supplies of gas, but these technologies are also under greater scrutiny with
respect to their environmental impacts. On the demand side, a continued shift from coal to
natural gas for electricity generation or an increase in manufacturing in the U.S. might drive up
natural gas prices, but other factors, such as generally more mild winters, might drive gas
demand lower. It is also difficult to predict the magnitude of the additional cost impacts
associated with the State’s cap-and-trade program over the long term. In the face of this
uncertainty, CPAU is able to protect the financial position of the Gas Utility by continuing its
current strategy of passing these costs directly to its customers via month-varying rate
adjustment mechanisms. The City has recently opted to pursue a policy of purchasing offsets to
make gas usage in Palo Alto carbon neutral. The cost is not to exceed $0.10/therm.
Future CIP investment needs for the Gas Utility may be lower than in the past, although costs
per foot for main replacement have been increasing substantially. The Gas Utility has replaced
nearly all of its ABS gas mains and its most problematic steel and PVC mains as well. The PE pipe
being used now is expected to have at least a fifty-year lifetime, and there is growing evidence
that it may last much longer than that. This would result in lower CIP investment over the long
term. CPAU is considering performing a study in the near future to develop its future main
replacements priorities and strategy.
Long-term state or local climate goals could also have a major impact on the Gas Utility. The
Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas
(GHG) emissions to 1990 levels by 2020. In its December 2007 Climate Protection Plan, the City
set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto
achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and
industrial processes. However, to achieve the recently adopted Sustainability and Climate
Action Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s
adopted goal of an 80% reduction in emissions by 2050 some amount of electrification of gas-
using appliances is likely to be necessary. If significant amounts of electrification occurred,
stranded investment and higher rates could be required as the costs of the distribution system
are recovered over a lower sales base. It is instructional that, in the recent discussion draft of its
scoping plan update, CARB says, to meet those goals, natural gas use would have to be “mostly
phased out.”13 Staff intends to begin evaluating how to manage potential impacts of these
trends over the next few years..
13 Climate Change Scoping Plan, First fUpdate, Discussion Draft for Public Review and Comment, California Air
Resources Board, October 2013, pg 88.
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April 1 2 , 2016 22 | Page
SECTION 6: D ETAILS AND A SSUMPTIONS
SECTION 6 A : GAS PURCHASE COSTS
The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always
cheaper than delivery at PG&E City Gate, even including the costs of transmission from Malin to
City Gate. Gas is purchased on a month-ahead and day-ahead basis in the spot market. The last
few years have seen gas prices in a relatively narrow but low band, but prices for the last year
have risen somewhat. High levels of natural gas in storage, along with warmer than normal
weather on the West coast has kept prices low, as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
Gas commodity costs are expected to increase steadily over the next several years. Figure 10
shows the projected gas prices used to generate this forecast. Projections for transmission costs
associated with transporting gas over PG&E’s Redwood transmission pipeline (from Malin,
Oregon to the PG&E Citygate) are based on rates adopted in the most recent update to the Gas
Accord.
Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC
14 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision
12-12-30 regarding the Pipeline Safety Enhancement Plan Adder.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 23 | Page
to more than double local transportation costs. The application was not settled until late 2016.
As these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed
making these costs pass-through charge, similar to the commodity charge, and this became
effective in November, 2016.
Figure 10: Wholesale Gas Price Projections
SECTION 6 B : OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance (including Engineering), Resource Management, and Administration categories in
Figure 11, below. Debt service, rent, and transfers are also included in Operations costs
(excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost
Categories includes detailed descriptions of the activities associated with these cost categories.
Operations costs are projected to increase by 2 to 4% per year. Salary and benefits, inflation,
and other assumptions match those used in the City’s long-range financial forecast.
Operations costs for FY 2017 to FY 2019 include funding for the cross-bore program. In the
1970s CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching
when installing new gas services. This created the possibility of cross-bores, which can happen
when a gas service is bored through a sewer lateral. Though cross-bores are very rare, they can
create a dangerous situation when a contractor attempts to clear a blocked sewer line, because
if the cross-bored gas service is damaged during the line clearing it can result in a gas leak.
CPAU has been inspecting new gas services since 2001, and in 2011 began video inspections of
the sewer laterals at the location of horizontally-drilled gas services installed before 2001. This
inspection program has cost roughly $1 million per year since FY 2012. While a majority of
sewer laterals have been inspected, staff has come across several services which are not able to
be scoped, either due to infiltration by roots or broken/collapsed pipe segments. Staff has
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 24 | Page
included $3 million in additional funding between FY 2017 and FY 2019 for this program, but
the program will likely require additional funding in future years to complete.
Figure 11: Historical and Projected Operational Costs
SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility’s CIP program consists of the following programs and budgets:
• The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains
• Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
• Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other
general improvements.
• Tools and Equipment, which covers the cost of capitalized equipment, such as
directional boring equipment.
• One-time Projects, which represents occasional large projects that do not fall into any
other category.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 25 | Page
Table 11 shows the current status of these project categories and future projected spending.
Table 11: Budgeted Gas CIP Spending
The Gas Main Replacement (GMR) Program is in the process of reaching a major milestone, the
replacement of the last gas mains made from ABS plastic. The program to replace ABS and
other low-performing materials in the system started in the 1990s (see Section 4A: Gas Utility
History for more detail). CPAU temporarily slowed down its new CIP appropriations in this
category in FY 2014 and 2015 in order to finish the last major ABS main replacement project
and to catch up on a backlog of projects that has accumulated due to staffing issues. With the
replacement of all ABS mains with PE plastic, the material most at risk for failure is removed
leaving only PVC plastic, steel (wrapped, with cathodic protection), and PE mains. The next
focus of the GMR program will be PVC mains. CPAU is considering updating the Gas System
Master Plan to determine which areas of the system to prioritize. The plan will help CPAU
determine whether the pace of main replacement (approximately three miles of main each
year, or 1.5% of the system) needs to be increased, decreased, or whether it needs to remain
the same.
The current budgets for gas main replacement might not fully take into account the recent rise
in costs for main replacement, which have increased from the levels seen during the recent
recession. 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 these fields. Newer, more leak resistant pipe
materials may have ongoing greater costs. CPAU has seen the replacement cost per linear foot
increase by 25 to 50% over the last couple of years. Currently CPAU plans to complete as much
main replacement as possible within its current budget, provided there are no safety concerns.
However, if this trend of higher cost continues, the Gas Utility may require larger CIP budgets,
and as a result, larger rate increases.
These increases in cost are 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.
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
One Time Projects 425 (2) 423 109 - - - - -
Gas Main Replacement 4,878 (187) 4,691 - - 3,588 3,759 3,878 4,000
Tools And Equipment 146 - 146 20 - 640 - - -
Ongoing Projects 254 (140) 114 88 809 833 858 884 911
Customer Connections 232 (660) (428) 159 1,265 1,303 1,342 1,383 1,424
TOTAL 5,935 (988) 4,946 375 2,074 6,365 5,960 6,145 6,335
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 26 | Page
Ongoing Projects, Tools and Equipment, and Customer Connections are projected to cost
approximately $0.8 million in FY 2018 and increase by 3% per year through the end of the
forecast period. In practice, these projects can fluctuate dramatically depending on system
conditions and the pace of development and redevelopment in the city. It is worth noting that
the Customer Connections program is paid for through fee revenue, so when costs go up, so
does fee revenue.
Aside from customer connections and some transfers from other funds, the CIP plan for
FY 2018 to FY 2022 is funded by utility rates. The details of the plan are shown in Appendix B:
Gas Utility Capital Improvement Program (CIP) Detail.
SECTION 6 D : DEBT SERVICE
The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A
Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal
remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to
finance various improvements to the distribution systems. $9.4 million of this issuance was
secured by the net revenues of the Gas Utility. Debt service for this bond for the financial
forecast period is shown in Table 12. Debt service on this bond will continue through 2026.
Table 12: Gas Utility Debt Service
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
2011 Utility Revenue
Refunding Bonds, Series A 803 802 800 800 802 804 805 803 800 803
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”15
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 13 and
Table 14.
Table 13: Debt Service Coverage Ratio ($000)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
Revenues 36,643 38,225 39,175 41,695 44,306 46,879 49,025 50,992 52,835 54,530
Expenses
(Excluding CIP and
Debt Service)
(33,926) (37,223) (37,033) (37,063) (37,804) (39,621) (41,057) (42,646) (44,305) (46,100)
Net Revenues 2,717 1,002 2,142 4,632 6,502 7,258 7,968 8,346 8,530 8,430
Debt Service 803 802 800 800 802 804 805 803 800 803
Coverage Ratio 338% 125% 268% 579% 811% 903% 990% 1039% 1039% 1039%
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 27 | Page
Table 14: Debt Service Minimum Reserves ($000)
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
FY
2025
FY
2026
Gas Utilitya 19711 17838 13456 11328 10883 11003 11642 12465 13273 14588
Debt Serviceb 803 804 803 802 801 801 802 803 800 803
Reserves Ratioc 25x 22x 17x 14x 14x 14x 15x 16x 16x 16x
a) CIP, Rate Stabilization, Operations, and Unassigned Reserves
b) Gas Utility’s share of the debt service on the 2011 bonds.
c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the
combined Electric, Gas, and Water Utility reserves and debt service and is higher than shown here.
The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances
listed in Table 15, even though the Gas Utility is not responsible for the debt service payments.
The Gas 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.
Table 15: Other Issuances Secured by Gas Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Gas Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
1999 Utility Revenue
Bonds, Series A
Wastewater Collection
Wastewater Treatment
Storm Drain
$1,207 No Yes
2009 Water Revenue
Bonds (Build America
Bonds)
Water $1,977* No Yes
*Net of Federal interest subsidy
SECTION 6 E : E QUITY T RANSFER
The City calculates the equity transfer from its Gas Utility based on a methodology adopted by
Council in 2009 that has remained unchanged since16. Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
SECTION 6 F : REVENUES
The Gas Fund receives most of its revenues from sales of gas, but about 8% comes from other
sources. The largest of these comes from service connection and capacity fees, followed closely
by sales of allowances related to California’s cap-and-trade program. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to
16 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 28 | Page
cover customers’ natural gas emissions, CPAU must buy allowances at market, and
subsequently passes through the cost of those allowances to customers. The regulations do not
allow the revenue derived from the sale of the free allowances to offset allowance purchases,
thus the pass-through rate component.
Sales revenue projections are based on the load forecast in Section 5A: Load Forecast. Except
where stated otherwise, these load forecasts are based on normal weather. Weather can vary
substantially, however, and this can affect revenues substantially. Also, changes in customer
behavior, as well as changes to more efficient gas appliances, or switching to electric
appliances, will modify these forecasts. Forecasts are continually evaluated to see when new
trends emerge.
SECTION 6 G : COMMUNICATIONS PLAN
The FY 2018 communications strategy covers four primary areas: operations, infrastructure,
safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates,
changes to the commodity rates are posted monthly on the City’s website. Gas use efficiency
incentives are promoted year-round, but most heavily during winter months to impact heating
activities. Promotional methods include community outreach events, print ads in local
publications, utility bill inserts, messaging on the bills and envelopes, website pages, email
blasts, videos for the web and local Comcast channels, Home Energy Reports and the use of
social media.
To keep customers apprised of the status and accomplishments of capital improvement
projects, a network of project web pages are maintained. Traffic is driven to the website via
print and digital ads, social media and email blasts. Safety topics are emphasized year-round.
CPAU is engaging in several campaigns and programs in FY 2018 to promote gas utility
efficiency and renewable energy. The Georgetown University Energy Prize competition is a
friendly, national campaign to encourage communities to reduce energy use. Energy savings
from reduced gas and electric consumption qualify to help Palo Alto compete for a $5 million
prize at the end of a two-year campaign. Since adoption of a carbon neutral electric supply
portfolio, CPAU launched a new voluntary renewable natural gas carbon offsets program,
PaloAltoGreen Gas. Much of our programmatic promotional activity will center around
customer education and encouragement to sign up for participation in PaloAltoGreen Gas.
Other new programs include home efficiency services and online tools to help customers
manage their energy use.
Stepping up efforts to promote gas safety education, staff is focusing outreach around youth,
the importance of calling USA (811) before digging for anyone who may excavate in and around
Palo Alto, such as plumbers and contractors, potential sewer and gas line cross-bores, keeping
fats, oils and greases out of drains, and ensuring clear access to meters. For younger
“customers-to-be,” CPAU created a Home Safety Detective campaign that includes special tool
kits to help them identify home safety problems. Staff provides safety kits to youth and adults
at school presentations, neighborhood safety and emergency preparedness fairs and other
community outreach events. Meter access awareness is highlighted through use of materials
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 29 | Page
featuring photos of some unusual ways people obstruct access to their meters, including using
them as bike racks and building storage sheds around them.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate
adjustment messages through a variety of marketing and media channels. Every year, CPAU
publishes an updated gas safety awareness brochure which is mailed to all customers in Palo
Alto, as well as plumbers, contractors and excavators that may work in and around the area.
Staff talks with business customers at special facilities meetings, attends neighborhood safety
and emergency preparedness fairs and offers presentations to school and community groups.
While print materials and website pages still feature prominently, CPAU is turning the outreach
emphasis to direct mail, newspaper inserts, social media, online videos and cable TV. Copies of
all outreach materials and logs of activities are saved in the Gas Safety Public Awareness Plan
that is reviewed at least once per year by the Department of Transportation.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 30 | Page
APPENDICES
Appendix A: Gas Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Description of Gas Utility Cost Categories
Appendix E: Gas Utility Communications Samples
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 31 | Page
APPENDIX A : GAS FINANCIAL FORECAST D ETAIL
($'000)
Actual Actual Actual Actual Actual
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
1 RATE CHANGE (%)*0%12%0%0%0%8%0%4%6%6%5%3%3%2%1%0%
2 SALES IN THOUSAND THERMS 30,447 28,901 28,117 28,881 26,719 27,829 27,434 27,463 27,623 27,546 27,482 27,432 27,394 27,450 27,510 27,541
3
4 Utilities Retail Sales 41,034 33,759 34,843 29,515 28,065 33,243 33,852 34,339 36,422 38,683 40,918 42,694 44,275 45,736 46,948 47,566
5 Service Connection & Capacity Fees 592 731 654 602 961 1,017 1,048 1,079 1,111 1,145 1,179 1,179 1,179 1,179 1,179 1,179
6 Other Revenues & Transfers In 103 830 313 415 873 1,857 2,965 3,395 3,906 4,251 4,573 4,916 5,266 5,623 6,081 6,043
7 Interest plus Gain or Loss on Investment 1,119 (239)706 450 730 526 361 362 256 227 209 237 272 297 322 338
8 Total Sources of Funds 42,847 35,081 36,517 30,982 30,629 36,643 38,225 39,175 41,695 44,306 46,879 49,025 50,992 52,835 54,530 55,126
9
10 Purchases of Utilities:
11 Supply Commodity 15,356 12,461 12,992 9,537 9,178 10,098 12,106 11,487 11,805 12,097 12,495 13,001 13,616 14,254 14,980 15,468
12 Supply Transportation 879 994 1,333 982 (1,051)2,944 3,331 3,444 3,499 3,487 3,526 3,568 3,611 3,655 3,699 3,767
13 Total Purchases 16,235 13,455 14,325 10,519 8,127 13,042 15,437 14,931 15,304 15,584 16,021 16,569 17,227 17,909 18,679 19,235
14
15 Administration (CIP + Operating)3,473 4,273 3,988 4,007 3,337 3,064 3,147 3,232 3,319 3,408 3,500 3,594 3,691 3,790 3,892 3,997
16 Customer Service 1,270 1,358 1,338 1,195 1,097 1,584 1,644 1,705 1,767 1,830 1,896 1,964 2,034 2,107 2,183 2,261
17 Demand Side Management 614 630 438 632 566 1,471 1,512 1,554 1,597 1,641 1,686 1,732 1,780 1,828 1,879 1,930
18 Engineering (Operating)333 340 352 369 426 529 547 565 584 604 623 644 665 687 710 733
19 Operations and Maintenance 5,032 4,940 4,119 4,403 4,153 5,980 6,189 6,398 5,613 5,807 6,007 6,215 6,429 6,652 6,882 7,120
20 Resource Management 729 506 516 556 472 724 748 772 798 823 850 877 905 934 965 996
21 Debt Service Payments 406 296 805 804 249 803 802 800 800 802 803 804 802 799 802 -
22 Rent 230 219 419 431 443 455 467 480 492 505 519 532 546 561 574 587
23 Transfers to General Fund 6,006 5,971 5,811 5,730 6,194 6,594 7,035 6,888 7,069 7,069 7,974 8,370 8,794 9,248 9,734 9,739
24 Other Transfers Out 170 207 606 151 303 484 496 508 520 533 546 560 573 587 602 617
25 Capital Improvement Programs 7,821 7,620 1,026 1,832 5,017 2,214 2,074 5,725 5,960 6,145 6,335 6,525 6,721 6,923 7,130 7,344
26 Total Uses of Funds 42,320 39,814 33,743 30,629 30,384 36,943 40,098 43,557 43,823 44,751 46,759 48,386 50,169 52,027 54,032 54,561
27
28 Into/ (Out of) Reserves 528 (4,733)2,773 353 245 (300)(1,874)(4,382)(2,127)(446)120 639 823 808 499 565
29
30 Reappropriations + Commitments 19,211 19,363 11,305 6,491 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255 6,255
31 Plant Replacement 1,000 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0
32 CIP Reserve 0 0 0 1,591 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820 3,820
33 Rate Stabilization 15,992 11,318 15,981 7,215 6,018 6,018 4,810 524 0 0 0 0 0 0 0 0
34 Operations Reserve 0 0 0 10,847 10,296 9,873 9,208 9,112 7,508 7,063 7,183 7,822 8,645 9,453 10,768 11,333
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1
36 Total Reserves 36,203 31,681 27,286 26,144 26,389 25,966 24,093 19,711 17,583 17,138 17,258 17,897 18,720 19,528 20,843 21,409
37 (1,142)245 (423)(1,874)(4,382)(2,127)(446)120 639 823 808 1,315 566
38 Short Term Risk Assessment Value 1,226 3,753 3,560 3,363 3,918 4,231 4,575 4,910 5,144 5,340 5,510 5,635 5,659
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,620 5,000 5,821 6,139 6,074 6,039 6,136 6,412 6,622 6,856 7,100 7,357 7,425
42 Target (90 Days Commodity + O&M) 8,429 7,500 8,731 9,208 9,112 9,058 9,204 9,618 9,933 10,284 10,650 11,036 11,137
43 Max (120 Days Commodity + O&M) 11,239 10,000 11,641 12,277 12,149 12,077 12,272 12,824 13,244 13,712 14,201 14,715 14,849
44
City of Palo Alto
Gas Utility
Fiscal Year
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 32 | Page
APPENDIX B : GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
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
ONE TIME PROJECTS
GS-10000 Gas Station 3 Rebuild - - - - - - - - - - -
GS-15001 Security at Receiving Stations 275,000 - 150,000 (1,563) 423,437 109,174 - - - - -
Subtotal, One-time Projects 275,000 - 150,000 (1,563) 423,437 109,174 - - - - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-09002 GMR - Project 19 - - - - - - - - - - -
GS-10001 GMR - Project 20 - - - - - - - - - - -
GS-11000 GMR - Project 21 100,000 - (100,000) - - - - - - - -
GS-12001 GMR - Project 22 3,571,560 - 3,000 (144,495) 3,430,065 - - - - - -
GS-13001 GMR - Project 23 620,650 3,010,000 (2,967,500) (42,500) 620,650 - - 3,588,150 - - -
GS-14003 GMR - Project 24 - 640,000 - - 640,000 - - - 3,100,000 - -
GS-15000 GMR - Project 25 - - - - - - - - 659,000 3,200,000 -
GS-16000 GMR - Project 26 - - - - - - - - - 678,200 3,300,000
GS-20000 GMR - Project 27 - - - - - - - - - - 700,000
GS-20001 GMR - Project 28 - - - - - - - - - - -
Subtotal, Gas Main Replacement Program 4,292,210 3,650,000 (3,064,500) (186,995) 4,690,715 - - 3,588,150 3,759,000 3,878,200 4,000,000
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools 70,106 100,000 (170,106) - - - - - - - -
GS-01019 Global Positioning System - - - - - - - - - - -
GS-03008 Polyethylene Fusion Equip.- - - - - - - - - - -
GS-14004 Gas Distribution System Model 126,365 - 19,574 - 145,939 19,574 - 640,000 - - -
Subtotal, Tools and Equipment 196,471 100,000 (150,532) - 145,939 19,574 - 640,000 - - -
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 33 | Page
Gas 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
GS-11002 Gas System Improvements 202,373 231,913 (173,254) (77,393) 183,639 87,771 238,870 246,036 253,417 261,020 268,851
GS-03009 System Ext. - Unreimbursed 128,690 198,500 (334,679) (62,123) (69,612) - 204,455 210,590 216,908 223,415 230,117
GS-80019 Gas Meters and Regulators 304,927 355,030 (659,957) - - - 365,681 376,652 387,952 399,591 411,579
Subtotal, Ongoing Projects 635,990 785,443 (1,167,890) (139,516) 114,027 87,771 809,006 833,278 858,277 884,026 910,547
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 213,712 1,228,500 (1,209,764) (660,368) (427,920) 158,819 1,265,355 1,303,315 1,342,415 1,382,688 1,424,169
Subtotal, Customer Connections 213,712 1,228,500 (1,209,764) (660,368) (427,920) 158,819 1,265,355 1,303,315 1,342,415 1,382,688 1,424,169
GRAND TOTAL 5,613,383 5,763,943 (5,442,686) (988,442) 4,946,198 375,338 2,074,361 6,364,743 5,959,692 6,144,914 6,334,716
Funding Sources
Connection Fees 1,017,000 (1,209,764) 1,047,510 1,078,935 1,111,303 1,144,642 1,178,981
Utility Rates 4,746,943 (4,232,922) 1,026,851 5,285,808 4,848,389 5,000,272 5,155,735
CIP-RELATED RESERVES DETAIL
6/30/2016
(Actual)
6/30/2017
(Unaudited)
Reappropriations 5,345,914 4,570,860
Commitments 267,469 375,338
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 34 | Page
APPENDIX C : GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas 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. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (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 9 (Unassigned Reserves)
Section 4. Reserve for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund 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 5. Reserve for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Reappropriations will be set to an amount equal to the amount of all remaining capital and
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 35 | Page
non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each
fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. 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 to or removed from the Reserve
for Commitments 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 Council approval to
hold funds in this reserve in excess of the maximum level, if they are held for a specific
future purpose related to the CIP.
Section 7. 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 Gas Utility Financial Plan must result
in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 36 | Page
Section 8. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 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 Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
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 Gas Utility’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas
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
Gas 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.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 37 | Page
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer an amount
equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from
the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa. Such
transfers shall be included in the ordinance closing the budget for the fiscal year.
GAS UTILITY FINANCIAL PLAN
April 1 2 , 2016 38 | Page
APPENDIX D : DESCRIPTION OF GAS UTILITY COST CATEGORIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Gas 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 gas services.
Resource Management: This category includes gas procurement, contract management, rate
setting, and tracking of legislation and regulation related to the gas industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• surveying the gas system (50% of the system each year) and repairing any leaks found;
• investigating reports of damaged mains or services and perform emergency repairs;
• building and replacing gas 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 pipes 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, including certified gas line welding services)
Administration: 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.
Demand Side Management: Includes the cost of administering gas efficiency programs and the
direct cost of rebates paid.
Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX E : GAS UTILITY COMMUNICATIONS SAMPLES
Page 1 of 8
4
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 5, 2017
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt 1) a Resolution Approving the Fiscal Year 2018
Electric Financial Plan, and 2) a Resolution Increasing Electric Rates by
Amending the E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU and E-14
Rate Schedules
REQUEST
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2018 Electric Financial
Plan (Attachment B); and
2. Adopt a resolution (Attachment C) amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Non-Residential Electric Service), E-2-G (Small Non-Residential
Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G
(Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-
Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-
7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-
Residential Time of Use Electric Service), and E-14 (Street Lights).
EXECUTIVE SUMMARY
The FY 2018 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2027. Costs are projected to rise substantially for the next several years for several
reasons. First, costs for electric supply purchases are increasing as a result of new renewable
energy projects coming online. Increases in transmission costs are also projected. Substantial
additional capital investment in the electric distribution system is planned for FY 2018 through
FY 2023, and operational costs are increasing.
Because of these rising costs, an increase in sales revenues is required. A 14% rate increase is
proposed for July 1, 2017, and a 7% increase is projected July 1, 2018. While staff would
normally attempt to spread these rate increases across more than two years to reduce the
single-year ratepayer impact, higher power supply purchase costs due to the drought have
Page 2 of 8
reduced operational and other reserves substantially, making this infeasible. Staff proposes
various reserves transfers to limit the rate impact upon most residential customers to
approximately 10%, as described later in this report.
While 14% is the overall increase in sales revenues, actual rate increases for each customer
class will differ. Actual rate increases are calculated using the cost of service analysis (COSA)
model created for the City by EES Consulting and first implemented on July 1, 2016.
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.
DISCUSSION
Summary of Proposed Actions
The two resolutions recommended for Council adoption will accomplish the following:
1. Increase overall electric rates by 14% effective July 1, 2017;
2. Approve various reserves transfers for FY 2017;
3. Approve the FY 2018 Electric Financial Plan.
Proposed and Projected Sales Revenue Requirement, FY 2018 through FY 2022
Table 1 shows the sales revenue increases needed to recover costs of operation over the
forecast period in the FY 2018 Electric Financial Plan.
Table 1: Projected Electric Rate Adjustments, FY 2017 to FY 2023
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
14% 7% 0% 0% 1% 2%
These sales revenue increases are for the utility as a whole, but the rate changes will differ for
individual customer classes. Proposed rate increases for each customer class are discussed
below.
Changes from Prior Financial Forecasts
This projection has changed since the FY 2017 Electric Utility Financial Plan presented last year.
Table 2 compares current rate projections to those projected in the last two year’s Financial
Plans. As shown, the FY 2018 revenue projections are higher than projected the last two years.
Page 3 of 8
Table 2: Projected Electric Rate Trajectory for FY 2018 to FY 2027
Projection FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Current
(FY 2018 Financial Plan) 14% 7% 0% 0% 1% 2% 1%
Last year
(FY 2017 Financial Plan) 10% 2% 0% 1% 0% 0% 0%
Two years ago
(FY 2016 Financial Plan) 6% 1% 1% 0% 0% 2% 2%
The rate increases are related to several factors: increasing transmission costs and the cost of
renewable projects coming online, substantial additional capital investment in the electric
distribution system is planned through FY 2023, and operations cost increases. Even when large
rate increases are needed, staff typically attempts to keep increases below 10% per year and
increase rates over multiple years. However, due to the impact of the recent drought on
hydroelectric energy generation output, the associated increased energy portfolio costs, and
decreases in customer sales, reserves are lower than forecasted, and cannot be used for rate
stabilization. However, precipitation in early 2017 is likely to lead to higher hydroelectric
output, which may improve reserves and the future financial outlook.
This Financial Plan still contains some measures to mitigate the impact on ratepayers. The July
1, 2017 rate increases would have to be substantially higher without proposed transfers from
the Supply Rate Stabilization Reserve, Hydro Rate Stabilization, and Electric Special Projects
Reserve (see below). In addition, this Financial Plan allows the Supply Operations Reserves to
be up to $3.9 million below the minimum Supply Operations Reserve level for FY 2017 through
FY 2020. To keep the Supply and Distribution Operations Reserves above the minimum
guideline without transfers, rate increases over 20% would be required in FY 2018. Staff
recommends allowing Supply Operations Reserves to temporarily go below minimums for two
reasons: first, heavy rains and an above average snowpack indicate both an end to the drought
and higher hydro production, which may result in higher reserves, and second, the presence of
the $41 million Electric Special Projects Reserve means that a relatively small temporary
shortfall in the Operations Reserves should not affect the Electric Utility’s bond ratings. In the
event the drought resurfaces, staff will re-evaluate its projections for FY 2018 and may
recommend additional rate increases or the adoption of a hydroelectric rate adjuster. Note
that the Financial Plan’s Reserves Management Practices allow the Operations Reserve to fall
below the minimum guideline level as long as the plan provides for replenishing the reserve
over time.
Staff also recognizes the importance of managing operating costs and maximizing efficiency in
order to minimize rate increases. Staff will continue to regularly review opportunities for cost
savings and efficiency improvements, and implement recommendations where practicable.
Page 4 of 8
Rate Changes by Customer Class
Table 3 shows the rates that will be used to recover sale revenues for each customer class. The
Street Lighting (E-14) class and the E-4 and E-7 Time of Use (TOU) rates are not shown in the
table, but can be seen in the attached rate schedules (Attachment D). These schedules are
omitted for various reasons: the E-14 rate schedule is not easy to summarize, E-7 TOU rate is
not easy to summarize and is only used by one customer, and the E-4 TOU rate schedule is both
difficult to summarize and not utilized by any customers at this time.
Table 3: Electric Rates (Current and Proposed)
Current Rates
Proposed Rates
(7/1/17)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.11029 0.12159 0.01130 10%
Tier 2 Energy ($/kWh) 0.16901 0.19001 0.02100 12%
Minimum Bill ($/day) 0.3067 0.2938 (0.0129) -4%
E-2 & E-2-G (Small Non-Residential)
Summer Energy ($/kWh) 0.16845 0.18885 0.02040 12%
Winter Energy ($/kWh) 0.11445 0.13267 0.01822 16%
Minimum Bill ($/day) 0.7657 0.7328 (0.0329) -4%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.10229 0.11673 0.01444 14%
Winter Energy ($/kWh) 0.08049 0.08890 0.00841 10%
Summer Demand ($/kW) 19.68 21.05 1.37 7%
Winter Demand ($/kW) 14.04 15.36 1.32 9%
Minimum Bill ($/day) 16.3216 14.8414 (1.4802) -9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.08749 0.09802 0.01053 12%
Winter Energy ($/kWh) 0.06242 0.07188 0.00946 15%
Summer Demand ($/kW) 18.34 23.84 5.50 30%
Winter Demand ($/kW) 15.65 15.59 (0.06) 0%
Minimum Bill ($/day) 48.5054 42.3648 (6.1406) -13%
Table 4 shows the impact of the proposed July 1, 2017 rate changes on the residential and non-
residential bills for various consumption levels. The overall rate change for the residential class
is roughly 12%.
Page 5 of 8
Table 4: Impact of Proposed Electric Rate Changes on Customer Bills
Rate
Schedule
Usage (kwh/mo)
Bill under
Current Rates
($/mo)
Bill Under Rates
Proposed 7/1/17
($/mo)
Change
$/mo %
E-1 300 33.09 36.48 3.39 10%
(Summer Median) 330 36.40 40.13 3.73 10%
(Winter Median) 453 57.18 63.50 6.31 11%
650 90.48 100.93 10.45 12%
1200 183.43 205.44 22.00 12%
E-2 1,000 141 161 19 14%
E-4 160,000 21,366 23,734 2,368 11%
E-7 500,000 54,473 62,186 7,713 14%
E-7 2,000,000 200,895 229,031 28,136 14%
Cost of Service Analysis and Rate Study
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates. Additional details are provided in the attached memo (Attachment C).
Reserves Transfers, FY 2017 and FY 2018
The FY 2018 Electric Utility Financial Plan includes several proposed reserves transfers, shown
in Table 5. These reserves transfers have a variety of purposes, but overall they enable the
revenue trajectory projected in the Electric Utility Financial Plan. Without these transfers,
additional rate increases would be required.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
Page 6 of 8
Table 5: FY 2017 and FY 2018 Reserves Transfers
Fiscal
Year
Transfer
Amount
Transfer
From
Transfer
To Purpose
FY
2017
Up to $10
million
Special
Projects
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2017.
Up to $9
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
Funds additional market energy purchases that may be
needed if hydroelectric output associated with spring
2017 precipitation is insufficient to offset below-
average summer and fall 2016 output.
Up to $4.5
million
Supply Rate
Stabilization
Reserve
Distribution
Operations
Reserve
Ensures Distribution Operations Reserve is above
minimum guidelines at the end of FY 2017.
Up to $911
thousand
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
Ensures Supply Operations Reserve is above Risk
Assessment level.
FY
2018
Up to
$3.1
million
Supply Rate
Stabilization
Reserve
Supply
Operations
Reserve
To bring Supply Operations Reserve to or above
minimum guidelines at the end of FY 2018.
Up to
$2.4
million
Hydroelectric
Stabilization
Reserve
Supply
Operations
Reserve
To bring Supply Operations Reserve to or above
minimum guidelines at the end of FY 2018.
$500
thousand
Supply Rate
Stabilization
Reserve
Distribution
Operations
Reserve
To bring Distribution Operations Reserve to or above
minimum guidelines at the end of FY 2018.
Electric Bill Comparison with Surrounding Cities
Table 6 compares electric bills under current rates as of March 1, 2017 for residential customers
to those in surrounding communities. Under current rates, CPAU’s customer bills are far below
PG&E’s and are lower than others for non-residential customers, but slightly higher than Santa
Clara’s for higher using residential customers.
Page 7 of 8
Table 6: Average Electric Bill Comparison ($/month)
As of March 1, 2017
Customers
Usage
(KWh/mo)
Palo Alto
(Current)
Palo Alto
(Proposed) PG&E Santa Clara Roseville
Residential
Customers
300 33.09 36.48 57.04 35.18 55.67
330 (Summer
Median) 36.40 40.13 63.85 38.83 58.64
453 (Winter
Median) 57.18 63.50 97.81 53.78 70.80
650 90.48 100.93 154.12 77.73 97.85
1200 183.43 205.44 374.41 144.59 179.96
Non-
Residential
Customers
1,000 142 161 240 181 146
160,000 21,366 23,734 29,108 20,562 21,009
500,000 54,473 62,186 87,015 62,956 55,955
2,000,000 200,895 229,031 333,041 243,390 214,705
NEXT STEPS
The Finance Committee is scheduled to review the FY 2018 Electric Financial Plan in May 2017.
The City Council will consider the recommendations with the FY 2018 budget.
RESOURCE IMPACT
The proposed July 1, 2018 rate changes are projected to increase sales revenues by $16.1
million per year over the forecast period.
POLICY IMPLICATIONS
The proposed electric rate adjustments were developed using a cost of service study and
methodology, and are consistent with the Council adopted Reserve Management Practices that
are part of the Financial Plan.
ENVIRONMENTAL REVIEW
The UAC’s review and recommendation to Council on the FY 2018 Electric Financial Plans and
rate adjustments does not meet the California Environmental Quality Act’s definition of a
project, pursuant to Public Resources Code Section 21065, thus no environmental review is
required.
ATTACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2018 Electric Utility
Financial Plan
B. Proposed FY 2018 Electric Utility Financial Plan
C. 2017 COSA Model and Rate Design Update
D. Resolution of the Council of the City of Palo Alto Adopting an Electric Rate Increase and
Amending Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-G, E-7 TOU, and
E-14
E. Proposed Amendments to Rate Schedules E-1, E-2, E-2-G, E-4, E-4-G, E-4 TOU, E-7, E-7-
G, E-7 TOU, and E-14
PREPARED BY: ERIC KENISTON, Resource Planner ce."1'<-
REVIEWED BY: ~~ ABENDSCHEIN, Assistant Director, Resource Mgmt.
~ APPROVED BY:
EDSHIKADA
Utilities General Manager
Page 8of8
Attachment A
Not Yet Approved
170329 jb 6053933
Resolution No. _____
Resolution of the Council of the City of Palo Alto Approving the
FY 2018 Electric 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 approves the FY 2018 Electric Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $911 thousand from
the Supply Rate Stabilization Reserve to the Supply Operations Reserve in FY 2017, up to $9.0
million from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve in FY
2017, and up to $4.5 million from the Supply Operations Reserve to the Distribution Operations
Reserve in FY 2017, as described in the FY 2018 Electric Utility Financial Plan approved via this
resolution.
/ /
/ /
/ /
/ /
/ /
/ /
Attachment A
Not Yet Approved
170329 jb 6053933
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065, and therefore, no environmental assessment is required.
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 ELECTRIC
UTILITY
FINANCIAL PLAN
FY 2018 TO FY 2027
ATTACHMENT B
2 | Page
F Y 2017 ELECTRIC UTILITY
F INANCIAL PLAN
FY 2018 TO FY 2027
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2018 Rate and Reserves Proposals ....................................................... 7
Section 3A: Rate Design ............................................................................................................... 7
Section 3B: Current and Proposed Rates ..................................................................................... 7
Section 3C: Reserves Management Practices .............................................................................. 8
Section 3D: Proposed Reserve Transfers ..................................................................................... 8
Section 4: Utility Overview .................................................................................................. 10
Section 4A: Electric Utility History ............................................................................................. 11
Section 4B: Customer Base ........................................................................................................ 13
Section 4C: Distribution System ................................................................................................. 13
Section 4D: Cost Structure and Revenue Sources ...................................................................... 14
Section 4E: Reserves Structure ................................................................................................... 15
Section 4F: Competitiveness ...................................................................................................... 16
Section 5: Utility Financial Projections ................................................................................. 17
Section 5A: Load Forecast .......................................................................................................... 17
Section 5B: FY 2012 to FY 2016 Cost and Revenue Trends ........................................................ 19
Section 5C: FY 2016 Results ....................................................................................................... 20
Section 5D: FY 2017 Projections ................................................................................................ 20
Section 5E: FY 2018 – FY 2027 Projections ................................................................................ 21
3 | Page
Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 23
Section 5G: Long-Term Outlook ................................................................................................. 27
Section 6: Details and Assumptions ..................................................................................... 30
Section 6A: Electricity Purchases ............................................................................................... 30
Section 6B: Operations .............................................................................................................. 32
Section 6C: Capital Improvement Program (CIP) ....................................................................... 33
Section 6D: Debt Service ............................................................................................................ 33
Section 6E: Equity Transfer ........................................................................................................ 34
Section 6F: Wholesale Revenues and Other Revenues .............................................................. 34
Section 6G: Sales Revenues ....................................................................................................... 35
Section 7: Communications Plan .......................................................................................... 36
Appendices ......................................................................................................................... 38
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 39
Appendix B: Electric Utility Reserves Management Practices ................................................... 43
Appendix C: Description of Electric utility Operational Activities .............................................. 48
Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 49
4 | Page
SECTION 1 : DEFINITIONS AND ABBREVIATIONS
CAISO California Independent System Operator
CARB California Air Resources Board
CIP Capital Improvement Program
CPAU City of Palo Alto Utilities Department
CPUC California Public Utilities Commission
CVP Central Valley Project
GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for
discussing total monthly or annual electric load for the entire city, or the monthly or
annual output of an electric generator.
kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing
large and mid-size commercial customers.
kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a
section of the distribution system operates. The transmission system operates at
115-500 kV, and this is lowered to 60 kV in the subtransmission section of the
Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution
system, and finally 120, 240, or 480 volts at the electric outlet.
MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum
electricity demand for all customers in aggregate.
PG&E Pacific Gas and Electric
REC Renewable Energy Certificate
RPS Renewable Portfolio Standard
Sub-transmission System: The section of the Electric Utility’s distribution system that operates
at 60 kV and which interfaces with PG&E’s transmission system.
Transmission System: Sections of the electric grid that operate at high voltages, generally 115
kV or more. The voltage at the intersection of the Electric Utility’s distribution system
and PG&E’s transmission system is 115 kV. The Electric Utility does not own or
operate any transmission lines.
UCC Utility Control Center
SCADA Supervisory Control and Data Acquisition system, the system of sensors,
communications, and monitoring stations that enables system operators to monitor
and operate the system remotely.
WAPA, or Western: Western Area Power Administration, the agency that markets power from
CVP hydroelectric generators and other hydropower owned by the Bureau of
Reclamation.
5 | Page
SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS
This document presents a Financial Plan for the City’s Electric Utility for the next ten fiscal
years. This Financial Plan describes how revenues will 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
The Electric Utility’s costs will increase substantially over the next few years, as shown in Table
1. Most of the increases are related to electric supply costs, which are increasing due to
increased transmission costs and the cost of new renewable energy projects coming online.
There are also inflationary increases in Operations costs, and some additional capital
investment costs.
Table 1: Electric Utility Expenses for FY 2016 to FY 2027
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
Power Supply
Purchases 79,115 84,371 87,987 89,066 90,841 90,728 92,221 91,758 92,925 93,904 95,224 96,465
Operations 35,443 54,152 56,307 56,795 58,409 59,238 60,089 61,931 62,507 59,519 60,550 61,610
Capital Projects 21,128 21,490 15,574 15,869 25,150 19,048 17,449 18,354 18,878 19,417 19,972 20,543
TOTAL 135,685 160,013 159,868 161,730 174,400 169,014 169,759 172,042 174,309 172,840 175,746 178,617
To cover these increases in costs, revenues (and therefore rates) need to increase over the next
several years to balance costs and revenues, as shown in Table 2. The table also compares
current rate projections to those projected in last year’s Financial Plan. The rate projections are
higher this year than last year primarily due lower actual and projected sales and increases to
transmission cost projections. In addition, the continued drought has had a greater impact than
expected on hydroelectric supplies. This has affected reserves, making it difficult to phase in
rate increases over multiple years.
Table 2: Projected Electric Rates, FY 2017 to FY 2023
Projection FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
Current 14% 7% 0% 0% 1% 2% 1% 1% 1% 1%
Last Year 10% 3% 0% 1% 0% 2% N/A N/A N/A N/A
Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate
Stabilization Reserve is projected to be drawn down entirely by the end of FY 2018. Funds are
projected to be transferred from the Electric Special Projects (ESP) Reserve to the Operations
Reserve to fund smart grid projects included in the long term CIP budget, but it should be noted
that the smart grid costs included in the forecast are placeholders, as are the transfers from the
ESP Reserve. Any transfers from the ESP Reserve require Council approval.
6 | Page
Staff will request a temporary loan from the ESP reserve of $10 million for the Distribution
Operations reserve, as it is otherwise projected to be critically low. As the intent of the ESP
reserve is to fund projects, not to stabilize rates, this will be a temporary transfer, to be
reversed once distribution rates have increased and stabilized (FY 2020 and 2021) and funds
can be returned to the ESP reserve. Staff is also requesting authority to withdraw funds from
the Hydro Stabilization Reserve in FY 2017 and FY 2018 due to lower than average hydroelectric
generation, though this projection is subject to change with weather conditions. Based on
precipitation to-date, this projection is likely to change, and staff will not perform these
transfers if they become unnecessary.
Table 3: Reserves Transfers for FY 2017 to FY 2027 ($000)
Reserve FY 2017 FY 2018 FY 2019 to FY 2027
Supply Reserves
Electric Special Projects (10,173) 3,000
Hydro Stabilization* (9,000) (2,400) -
Supply Rate Stabilization (5,411) (3,600) -
Supply Operations 10,084 5,500 7,000
Distribution Reserves
Capital Improvement Program
Distribution Operations 14,500 500 (10,000)
* A $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve was
approved by Council when it adopted the FY 2016 Electric Utility Financial Plan
SECTION 2 B : SUMMARY OF PROPOSED ACTIONS
Staff proposes the following actions for the Electric Utility in FY 2017:
1. Complete the proposed FY 2017 reserves transfers described Section 3D: Proposed
Reserve Transfers, as previously requested as part of the FY 2017 Electric Financial Plan
2. Request a new transfer of $10 million from the ESP reserve to the Distribution
Operations Reserve, to be repaid within five years.
Staff proposes the following actions for the Electric Utility in FY 2018:
1. Request the proposed FY 2018 reserves transfers described in Section 3D: Proposed
Reserve Transfers.
2. Increase rates effective July 1, 2017 for a 14% increase in system average rates, and
thereby increase sales revenues by 10% based upon current sales projections.
Note that while the projected rate increases and reserves transfers in this FY 2018 Financial
Plan are adequate to recover costs over the forecast period, the Supply Operations Reserves
are projected to be at or below the minimum Supply Operations Reserve level for FY 2017
through FY 2019, and lower sales have dropped Distribution Operations reserves to very low
levels requiring new transfer requests. While more aggressive increases could be requested,
staff still recommends proceeding with this plan for two reasons: first, recent rains and
7 | Page
favorable snowpack levels may result in favorable hydroelectric production, resulting in higher
reserves, and second, the presence of the Electric Special Projects Reserve with a balance of
$41 million means that a small temporary shortfall in the Operations Reserves should not affect
the Electric Utility’s financial health and bond ratings. In the event drought resurfaces or hydro
fails to materialize, staff will re-evaluate its projections at midyear of FY 2018 and may
recommend additional rate increases or the adoption of a hydroelectric rate adjuster.
SECTION 3 : DETAIL OF FY 2018 RATE AND RESERVES PROPOSALS
SECTION 3 A : RATE DESIGN
The rates discussed in the previous section are based on the cost of service methodology
established in “City of Palo Alto Electric Cost of Service and Rate Study”1 drafted by EES
Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections,
including projected transmission and distribution costs, power supply costs and billing data, in
order for EES to update individual cost of service model components and determine the
proposed rates. The COSA is based on design guidelines adopted by Council on September 15,
2015 (Staff Report 6061).
SECTION 3 B : CURRENT AND PROPOSED RATES
The current rates were adopted on July 1, 2016, when CPAU increased electric rates by 11%.
Table 4, below, summarizes the current and proposed rates for the four largest customer
classes. The Electric Utility also has specialty rates for smaller groups of customers. These
include variations on its primary rates, such as time of use rates, the PaloAltoGreen rates, and
solar net metering. Staff proposes a 14% overall increase in revenue, requiring 14% increase in
system average rates. Different customer classes may see different percentage changes to their
rates, based upon their usage of the system and cost to serve each group.
1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274
8 | Page
Table 4: Current and Proposed Electric Rates
Current Rates
Proposed Rates
(7/1/17)
Change
$ %
E-1 (Residential)
Tier 1 Energy ($/kWh) 0.11029 0.12159 0.01130 10%
Tier 2 Energy ($/kWh) 0.16901 0.19001 0.02100 12%
Minimum Bill ($/day) 0.3067 0.2938 (0.0129) -4%
E-2 & E-2-G(Small Non-Residential)
Summer Energy ($/kWh) 0.16845 0.18885 0.02040 12%
Winter Energy ($/kWh) 0.11445 0.13267 0.01822 16%
Minimum Bill ($/day) 0.7657 0.7328 (0.0329) -4%
E-4 & E-4-G (Medium Non-Residential)
Summer Energy ($/kWh) 0.10229 0.11673 0.01444 14%
Winter Energy ($/kWh) 0.08049 0.08890 0.00841 10%
Summer Demand ($/kW) 19.68 21.05 1.37 7%
Winter Demand ($/kW) 14.04 15.36 1.32 9%
Minimum Bill ($/day) 16.3216 14.8414 (1.4802) -9%
E-7 & E-7-G (Large Non-Residential)
Summer Energy ($/kWh) 0.08749 0.09802 0.01053 12%
Winter Energy ($/kWh) 0.06242 0.07188 0.00946 15%
Summer Demand ($/kW) 18.34 23.84 5.50 30%
Winter Demand ($/kW) 15.65 15.59 (0.06) 0%
Minimum Bill ($/day) 48.5054 42.3648 (6.1406) -13%
These proposed rates were prepared in conformance with the “FY 2017 City of Palo Alto Electric
Cost of Service and Rate Study,” performed by EES Consulting (2016).
SECTION 3 C : RESERVES MANAGEMENT PRACTICES
No changes to the Electric Utility Reserves Management Practices (See Appendix B: Electric
Utility Reserves Management Practices) are proposed at this time.
SECTION 3 D : PROPOSED RESERVE TRANSFERS
In the FY 2017 Electric Financial Plan, Council approved several proposed transfers for FY 2017:
•Transfer up to $1 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve. This transfer is to enable the City to spread necessary long term
rate increases over multiple years to reduce the short-term impact on ratepayers.
Current estimates are that the amount will be closer to $911,000.
•Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset
potential costs associated with low hydroelectric generation. Some or all of this transfer
9 | Page
may be unnecessary if weather conditions change, but current estimates still indicate
the full amount will be needed, since excess generation in the spring of 2017 may not
fully offset below-average generation in the summer and fall of 2016.
•Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution
Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve.
Staff will also request the following for FY 2017:
•Transfer up to $10 million from the ESP Reserve to the Distribution Operations Reserve.
This transfer will be construed as a temporary transfer, to be repaid to the ESP Reserve
within five years.
Proposed transfers for FY 2018 will not be requested by resolution at this time, but will be
requested as part of the FY 2019 Financial Plan, or at FY 2017 year-end should ending reserve
balances require it.
The impact of these transfers on reserves levels can be seen in Figure 8 (for Supply Fund
Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2018 – FY 2027
Projections. Table 5 shows the projected balance of each of the Electric Utility reserves for the
period covered by this Financial Plan. The projected balances are also provided in. Appendix A:
Electric Utility Financial Forecast Detail
Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2016 to FY 2027
Ending Reserve
Balance ($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
Reappropriations - - - - - - - - - - - -
Commitments 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777 3,777
Underground Loan 729 729 729 729 729 729 729 729 729 729 729 729
Public Benefits 1,839 1,331 739 280 95 - - - - - - -
Special Projects 51,838 41,665 41,526 41,192 42,859 46,192 44,665 44,665 44,665 44,665 44,665 44,665
Hydro Stabilization 11,400 2,400 - - - - - - - - - -
Capital - - - - - - - - - - - -
Rate Stabilization 9,011 3,600 - - - - - - - - - -
Operations 21,850 21,570 28,477 31,328 31,984 32,727 36,734 36,600 36,226 38,957 40,471 41,658
Unassigned - - - 916 - - - - - - - -
TOTAL 100,444 75,072 75,248 78,222 79,444 83,425 85,906 85,771 85,397 88,128 89,642 90,830
10 | Page
SECTION 4 : UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information to help readers better understand the forecasts in Section 5: Utility
Financial Projections and
11 | Page
Section 6: Details and Assumptions.
SECTION 4 A : ELECTRIC UTILITY HISTORY
On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest
sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel
engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity
continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E
proved more economical than the diesel engines, and by the late 1920s CPAU was using its own
diesel engines only during peak demand periods. At that time CPAU owned 45 miles of
distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual
consumption. The diesel engines remained in operation until 1948, when they were retired.
From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did
throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the
sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto,
which doubled the number of customers. Some was related to the proliferation of electric
appliances, as evidenced by the fact that residential customers were using three times more
electricity in 1970 than they had been in 1950. But the most notable factor was the growth of
industry in Palo Alto during that time. By 1970, commercial customers were using 20 times
more electricity per customer than they had been in 1950. These decades also saw several
other notable events, including:
• 1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of
Reclamation to purchase power from the Central Valley Project (CVP), a contract which
later was managed by the Western Area Power Administration (WAPA) an office of the
Department of Energy created in the 1970s to market power from various hydroelectric
projects operated by the Federal Government, including the CVP.
• 1965: The City began a long-term program to underground its overhead utility lines
(Ordinance 2231).
• 1968: Palo Alto joined several other small municipal utilities to form the Northern
California Power Agency (NCPA), a joint action agency intended to make the group less
vulnerable to actions by private utilities and to enable investment in energy supply
projects.
Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto
joined other NCPA members to invest in the construction and operation of the Calaveras
Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project
commenced operation in 1990. The 1980s also saw an increased focus on infrastructure
maintenance. In 1987 the UCC was built to house the terminals for a new SCADA system, which
enabled utility staff to monitor the distribution system in real time, improving response time to
outages. CPAU also commenced a preventative maintenance and planned replacement
program for its underground system in the early 1990s.
12 | Page
In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and
in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the
California Independent System Operator (CAISO) to operate the transmission system and the
Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated
to bring lower costs to consumers, and while CPAU was not required to participate in the
industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric
Utility2 that enabled CPAU to sell electricity outside its service territory and allowed customers
within CPAU’s service territory to choose other providers. The utility unbundled its electric
rates, creating separate supply and distribution components, which would enable customers to
receive only distribution service while purchasing the electricity itself from another provider.
The energy crisis in 2000 to 2001 led to the suspension of direct access by the CPUC in
September 2001 as wholesale energy prices skyrocketed. The Electric Utility was less impacted
than other utilities by the 2000 to 2001 energy crisis thanks to the Calaveras project and its
contract with WAPA for CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental
power to balance the monthly and annual variability of CVP generation. The new contract
would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in
CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would
increase and CPAU needed to more actively managine its supply portfolio. CPAU began
purchasing power from marketers and also investigated building a power plant in Palo Alto or
partnering in the development of a gas-fired power plant elsewhere. Climate change was also
becoming more of a concern to the community, and gradually CPAU shifted its focus to the
procurement of renewable energy. In 2002 CPAU adopted a goal of achieving 20% of its energy
supply from renewables by 2015. Subsequently CPAU signed its first contract for renewable
power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the
renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a
plan to make its electric supply 100% carbon neutral, which it achieves through the
combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy
supplies, and short-term renewable energy purchases (RECs) to meet the balance of its needs.
2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
13 | Page
Figure 1: Customer Base (FY 2016)
16%
7%
35%
42%
Residential
Small Comm
Med. Comm
Large Comm
SECTION 4 B : CUSTOMER BASE
The City of Palo Alto’s Electric Utility
provides electric service to the
residents, businesses, and other
electric customers in Palo Alto. There
are roughly 29,750 customers
connected to the electric system,
25,700 (86%) of which are residential
and 4,050 (14%) of which are non-
residential. Residential customers
consumed 148 gigawatt-hours (GWh)
in FY 2016, approximately 16% of the
electricity sold, while non-residential
customers consumed 88% or
759 GWh. Residential customers use
electricity primarily for lighting,
refrigeration, electronics, and air conditioning.3 Non-residential customers use the majority of
their electricity for cooling, ventilation, lighting, office equipment (offices), cooking
(restaurants), and refrigeration (grocery stores).4
As shown in Figure 1 large customer loads represent a larger proportion of sales for the Electric
Utility than they do for the City’s other utilities. The largest customers (the 72 customers on the
E-7 rate schedule) account for over 40% of CPAU’s sales. The next largest customer group (the
835 non-residential customers on the E-4 rate schedule) represents another 35% of sales. In
total, that means that about 3% of customers account for nearly three quarters of the electric
load.
SECTION 4 C : DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 470 miles of
distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are
underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line
transformers, 1,075 underground and substation transformers, and the associated electric
services (which connect the distribution lines to the customers’ homes and businesses). These
lines, substations, transformers, and services, along with their associated poles, meters, and
3 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
4 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
14 | Page
Figure 2: Cost Structure (FY 2016)
58%
34%
8%
Commodity Supply
Operations
Capital
Figure 3: Hydroelectric Variability (FY 2018)
0%
50%
100%
150%
200%
Low Hydro Average High Hydro
Surplus Hydro
(sales)
Market
Power/RECs
Hydro
Renewables
Load
Figure 4: Revenue Structure (FY 2016)
87%
13%
Sales of Electricity
Other Revenue
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto.
SECTION 4 D : COST STRUCTURE AND REVENUE SOURCES
As shown in Figure 2, electric
commodity purchases accounted for
roughly 58% of the Electric Utility’s
costs in FY 2016. Operational costs
represented roughly 34%, and
capital investment was responsible
for the remaining 8%. CPAU’s non-
hydro long-term commodity supply
is heavily dependent on long-term
contracts which have little variability
in price. On average, costs for these
long-term contracts are not
predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller
proportion of the Electric Utility’s costs. Commodity supply costs are projected to be roughly
54% of total costs in FY 2027.
While average year purchase
costs for the electric utility
are predictable due to its
long-term contracts,
variability in hydroelectric
generation can result in
increased or decreased
costs. This is by far the
largest source of variability
the utility faces. Figure 3
shows the difference in costs
under high, projected, and
low hydroelectric generation scenarios for FY 2018. Additional costs associated with a very low
generation scenario can range from $9-11 million per year. For the current hydroelectric risk
assessment see Section 5F: Risk Assessment and Reserves Adequacy.
As shown in Figure 4 the Electric Utility
receives 87% of its revenue from sales of
electricity and the remainder from
connection fees, interest on reserves,
cost recovery transfers from other funds
for shared services provided by the
electric utility, and other sources. Some
15 | Page
revenue sources are primarily accounting entries that reflect things such as CPAU’s
participation in a pre-funding program associated with its contract with WAPA, as well as
accounting entries associated with occasional sales of surplus hydroelectric energy during wet
years. Without these entries sales revenues represent roughly 91% of total revenues. Appendix
A: Electric Utility Financial Forecast Detail
shows more detail on the utility’s cost and revenue structures.
As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales
are to the 900 largest customers, which provide a similar share of the utility’s revenue stream.
The utility’s retail rate schedules have no fixed charges, although about 24% of the utility’s
revenue comes from peak demand charges on large non-residential customers. Due to
moderate weather and the prevalence of natural gas heating, however, loads (and therefore
revenues) are very stable for this utility, without the large seasonal air conditioning or winter
heating loads seen at some other utilities.
SECTION 4 E : RESERVES STRUCTURE
CPAU maintains several reserves for its Electric Utility to manage various types of
contingencies. It also maintains two funds, the Supply Fund and the Distribution Fund, to
manage costs associated with electricity supply and electricity distribution, respectively. This
separation of supply and distribution costs was established as the City prepared to allow its
customers a choice of electricity providers (referred to as “Direct Access”) back in the late
1990s and early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues
to maintain separate funds to facilitate separation of supply and distribution costs in the rates.
This could be important in case California ever decides to reintroduce Direct Access, and may
also be useful for rate design as the nature of utility services evolves in response to higher
penetrations of distributed generation.
The various reserves are summarized below, but see Appendix B: Electric Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserves for Commitments: Reserves equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserves for Reappropriations: Reserves 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. This is currently an important
reserve for all utility funds, but changes in budgeting practices will change that in future
years, as described in Section 3C (Reserves Management Practices).
• Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras
Reserve, which was accumulated during deregulation of California’s electric system to
fund the stranded costs associated primarily with the Calaveras hydroelectric resource
and the California-Oregon Transmission Project. When that reserve was no longer
16 | Page
needed for that purpose, the reserve was renamed and the purpose was changed to
fund projects with significant impact that provide demonstrable value to electric
ratepayers.
• Hydroelectric Stabilization Reserve: This contingency reserve is used for managing
additional costs due to below average hydroelectric generation, or to hold surpluses
resulting from above average hydroelectric generation.
• Underground Loan Reserve: This reserve is an accounting tool used to offset receivables
associated with loans made through the underground loan program. It is adjusted
according to principal payments made on those loans.
• Public Benefits Reserve: CPAU’s electric rates include a separate charge called the
“Public Benefits Charge” which generates revenue to be used for energy efficiency,
demand-side renewable energy, research and development, and low-income energy
efficiency services. Any funds not expended in the current year are added to the Public
Benefits Reserve for use in future years.
• Capital Improvement Program (CIP) Reserve: The CIP reserve is used to provide
working capital and contingency funds for the CIP program, as well as to accumulate
funds for major future one-time expenditures. This type of reserve is used in other
utility funds (Electric, Gas, and Wastewater Collection) as well.
• Supply and Distribution Rate Stabilization Reserves: These reserves are 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 (Gas,
Wastewater Collection, and Water) as well.
• Supply and Distribution Operations Reserves: These are the primary contingency
reserves for the Electric Utility, and are used to manage yearly variances from budget
for operational costs and electric supply costs (aside from variances related to
hydroelectric generation). This type of reserve is used in other utility funds (Gas,
Wastewater Collection, and Water) as well.
• Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves
are for any financial resources not assigned to the other reserves and are normally
empty.
SECTION 4 F : COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2016 was
$551.65 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with
the same consumption and roughly the same as the annual bill for a City of Santa Clara
customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X, which
includes most surrounding comparison communities.
Table 6 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara
(Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown
17 | Page
below were in effect as of March 1, 2017. PG&E rates were recently increased, and their
residential tiers moved from three to two.
Over the next several years low usage customers in PG&E territory are expected to continue to
see higher percentage rate increases than high usage customers as PG&E compresses its tiers
from the highly exaggerated levels that have been in place since the energy crisis. This is likely
to make the bill for the median Palo Alto consumer look even more favorable compared to
most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers
are likely to remain substantially lower than the bills for high usage PG&E customers.
The bill calculations show bills under the existing rates, not the proposed July 1, 2017 rates.
However, even with the proposed rate increases, Palo Alto’s residential bills will remain
substantially below PG&E’s current rates, but slightly above Santa Clara’s.
Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/17, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(March)
300 33.09 57.04 35.18
453 (Median) 57.18 97.81 53.78
650 90.48 154.38 77.73
1200 183.43 374.19 144.59
Summer
(July)
300 33.09 57.04 35.25
(Median) 330 36.40 63.85 38.83
650 90.48 159.66 77.73
1200 183.43 380.43 144.59
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Even with the proposed rate increases, Palo Alto’s commercial bills will remain
substantially below PG&E’s, and below Santa Clara’s for some commercial customers.
Table 7: Commercial Monthly Electric Bill Comparison (3/1/17, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 142 240 181
160,000 21,366 29,108 20,562
500,000 54,473 87,015 62,956
2,000,000 200,895 333,041 243,390
SECTION 5 : UTILITY FINANCIAL PROJECTIONS
SECTION 5 A : LOAD FORECAST
Figure 5 shows a 40-year history of Palo Alto electricity consumption. Average electricity
consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then
electricity consumption has declined slowly as a result of a continuing focus on energy
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efficiency, as well as the adoption of more stringent appliance efficiency standards and energy
standards in building codes.
Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2027. Sales after the July
2016 rate change decreased by 6% from projections. To be conservative, the forecast assumes
that current trends continue and sales through the forecast period decline slightly.
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Figure 6: Forecasted Electricity Consumption
SECTION 5 B : FY 2012 TO FY 2016 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in
Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail.
These decreases were partly related to declines in electricity market prices due to the impact of
shale gas and partly due to above average output from hydroelectric resources. These factors
are discussed in more detail in Section 6A: Electricity Purchases. Since FY 2012, total expenses
for the utility have been increasing as renewable resources come online. In FY 2014 through FY
2015 costs were higher due to lower than average output from hydroelectric resources.
Commodity costs are responsible for most of the changes in the utility’s expenses over the last
six years. Operational costs and capital investment increased at less than 1% per year over that
time.
Actual Projection
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Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2016 and Projections through FY 2027
SECTION 5 C : FY 2016 RESULTS
California’s drought, with its corresponding lower hydroelectric energy output, continued to
increase electricity costs in FY 2016. Offsetting this were lower operations and capital program
spending. FY 2016 expenses were $9.2 million lower than in the FY 2017 Financial plan, with
revenues being roughly equal.
SECTION 5 D : FY 2017 PROJECTIONS
Last year, staff recommended (and Council approved) an 11% rate change for July 1, 2016, the
start of FY 2017. Based on hydroelectric conditions at the time, staff forecasted a roughly $15.2
million deficit for FY 2017. This deficit was primarily related to low hydroelectric output, and
was to be funded from the Rate Stabilization and Hydroelectric Stabilization reserves. Staff’s
current forecast for FY 2017 is for a deficit of $25.4 million, $10.2 million more than forecast
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last year. This change is mainly due to sales decreasing by 6% after the last rate increase,
cutting projected revenues by $11 million. The onset of wet weather and a forecast for a
reversal in hydro conditions has brought down electric purchase cost projections, but the full
impact of better hydro conditions likely won’t be felt until next fiscal year.
With Operations reserves projected to be below minimum, several transfers, including a
temporary loan from the Electric Special Projects Reserve, proposed. These transfers are
discussed in Section 3D: Proposed Reserve Transfers.
SECTION 5 E : FY 2018 – FY 2027 PROJECTIONS
As shown in Figure 7 above, costs for the Electric Utility are projected to increase at a fairly
steady rate through the forecast period. Revenues will have to increase 10% in FY 2018 and
another 7% in FY 2019 to bring revenues in line with expenses. The largest increases are
primarily related to electricity purchase costs, which have been increasing since FY 2013 and
will continue to increase through FY 2018 as new renewable projects come online to fulfill the
City’s environmental goals and as transmission costs increase. Operations costs are expected to
increase at or near the inflation rate (2-4 %/year) through the forecast period. Projected capital
expenses for FY 2018 through FY 2023 are about $4.6 million lower than last year’s forecast as
one large, customer driven project has been put on hold. The project would have been funded
mostly through customer reimbursement. This forecast also assumes that smart grid costs are
funded from the Electric Special Projects Reserves.
Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund
reserves) and Figure 9 (for Distribution Fund reserves), below. The Supply Rate Stabilization
Reserve will be empty by the end of FY 2017. The Distribution Operations reserve will require a
short term transfer of $10 million from the Electric Special Projects reserve to remain adequate
through the forecast period. The $10 million is projected to be transferred back between FY
2020 and FY 2021. The Supply Operations Reserve, however, is forecasted to be below
minimum levels. This is discussed in more detail in Section 5F: Risk Assessment and Reserves
Adequacy. The Hydro Stabilization reserve is projected to be depleted by the end of FY 2017.
Staff will bring plans to Council in spring or summer for a Hydro rate adjustment mechanism to
better utilize, and fund, this particular reserve.
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Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2016 and Projections through FY 2027
Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2016 and Projections through FY 2027
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SECTION 5 F : RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the
reserve minimum for the Distribution Operations Reserve throughout the forecast period.
Reserve levels also exceed the short-term risk assessment level for the Distribution Fund. The
Supply Operations Reserve, however, may end up below minimum levels and below the short-
term risk assessment level.
There are a variety of risks associated with the Supply Fund as are shown in Table 8. Because of
the high range of uncertainty in energy price predictions more than three years in the future,
this risk assessment is only performed for the first two fiscal years of the forecast period. It is
important to note that the likelihood of all of these adverse scenarios occurring simultaneously
and to the degree described in Table 8 is very low.
Table 8: Electric Supply Fund Risk Assessment
Categories of Electric Supply Cost
Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2018 FY 2019
1.Load Net Revenue 0.9 1.0 Revenue loss from load decreases (net of
reduction in energy purchases)
2.Production from Hydroelectric
Resources: Western & Calaveras 9.3 13.7 Lower than forecasted hydro
3.Renewable Production: Landfill &
Wind 0.5 2.0 Additional cost of renewable output that is
higher than forecasted
4.Carbon Neutral Cost 0.0 0.0 Higher than forecasted market prices for RECs
5.Market Price (Energy)0.7 0.6 Higher than forecasted market prices for
energy
6.Local Capacity 0.6 1.5 Higher than forecasted market prices for local
capacity
7.Transmission/CAISO 3.2 3.3 High-end transmission forecast scenario
8.Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
9.Western Cost 2.4 3.5 Risk of rate adjustments from Western
10.Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties
11.Supplier Default 0.2 0.2 Estimate of supplier default risks
Electric Supply Fund Risks $18.8
million
$26.8
million
Projected Supply Operations +
Hydro Stabilization Reserve Levels
$16.0
million
$17.5
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2018, the risk of a dry year with very
low hydroelectric output is normally the largest, accounting for nearly half the total cost of all
adverse outcomes. Since the utility’s costs for its hydroelectric resources are almost entirely
fixed, costs do not decline when the output of those resources are low, but the utility needs to
buy power to replace the lost output. The converse happens when hydroelectric output is
higher than average.
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Of the remaining risks for FY 2018, $3.2 million is related to the projected costs if transmission
cost increases are higher than staff’s current forecast. Another $2.4 million is related to the
possibility of drought-related changes to Western rates for CVP hydropower.
As shown in Figure 10, the Supply Operations Reserve will drop below the minimum reserve
guidelines by as much as $3.9 million over the course of the forecast period. In addition, as
shown in Figure 11, the combined hydro stabilization and supply operations reserves will drop
below the risk assessment level. It is acceptable under the Electric Utility Reserves Management
Practices to drop below minimum reserve guidelines so long as Council approves the Financial
Plan. Staff recommends proceeding with this plan for two reasons: first, due to larger than
normal rains and snowpack to date, there is a chance of better hydro conditions will result in
higher reserves, and second, the presence of the Electric Special Projects Reserve means that a
small temporary shortfall in the Supply Operations Reserve should not affect the Electric
Utility’s bond ratings. In the event drought re-emerges, staff will re-evaluate its projections for
FY 2019 and may recommend additional rate increases or the adoption of a hydroelectric rate
adjuster.
Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 9 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2022. As shown in Figure 12, the Distribution Operations Reserve will stay within the
reserve guidelines over the course of the forecast period. 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 9: Electric Distribution Fund Risk Assessment ($000)
FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Total non-commodity revenue $46,877 $49,044 $48,931 $48,812 $49,612
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,700 $3,871 $3,862 $3,852 $3,916
CIP Budget $15,574 $15,869 $25,150 $19,048 $17,449
CIP Contingency @10% $1,557 $1,587 $2,515 $1,905 $1,745
Total Risk Assessment value $5,257 $5,458 $6,377 $5,757 $5,661
Figure 12: Electric Distribution Operations Reserve Adequacy
As shown in Figure 13, the CIP Reserve is projected to be at or above the proposed revised
minimum and maximum guidelines over the forecast period. While the Reserve is above
maximum levels in later years, CIP Commitments are nearly impossible to project that far out,
and adjustments to the reserve can be made in future years.
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Figure 13: Electric CIP Reserve Adequacy
SECTION 5 G : LONG-TERM OUTLOOK
This forecast covers the period from FY 2018 through FY 2027, but various long-term
developments may create new costs for the utility over the next 5 to 35 years. While it is
challenging to accurately forecast the impact these events will have on the utility’s costs, it is
worth noting them as future milestones and keeping them in mind for long-term planning
purposes.
For the supply portfolio, the 2020s will see a number of notable events. The contract with
Western for power from the CVP will expire in 2024. Determining the future relationship with
Western after 2024 will be important in the years leading up to the contract expiration,
especially because this resource represents nearly 40% of the electric portfolio, and is the
utility’s largest source of carbon-free electricity. The utility’s three earliest and lowest cost
renewable contracts will also begin expiring around that time, with the first contract expiring in
2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently
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provide 17% to 18% of the energy for the utility’s supply portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range (or even lower), and costs
may decrease in the future, current renewable projects also benefit from a wide range of tax
and other incentives that may or may not be available in the 2020s and beyond. However, staff
is in the process of procuring a replacement for the contract expiring in 2021 at a lower price
than any of the City’s current renewable contracts.
The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs
dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032
(assuming no new debt is issued). The project will only be 40 years old at that time. Calaveras
debt service represents roughly 70% of the annual costs of that project (and nearly 7% of the
utility’s total costs), so when the debt is retired, the project could be a low-cost asset for the
utility, providing carbon-free energy equal to 13% of the Electric Utility’s supply needs in an
average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. That revenue source is expected to continue through 2020, but provisions for
whether or not these allocations continue past 2020 are still being discussed. If the Electric
Utility no longer received these allowances, it would have to fund these programs from sales
revenues.
Transmission costs are also continuing to rise. If the State continues to increase mandates or
incentives for renewable energy development, integrating these new projects into the
transmission grid will be an ever increasing challenge, some costs of which will be borne by Palo
Alto. The planned expansion of the CAISO to a larger regional grid control area may result in
additional transmission costs that could further increase CPAU’s transmission costs. In addition
to the costs of new transmission lines that will need to be built, flexible resources will be
required to balance rapid changes in wind or solar output throughout the day. Palo Alto will
likely bear some of the costs of these new lines and resources. CPAU is also currently
investigating installing a second transmission interconnection for Palo Alto, which could be
funded by the Electric Special Projects reserve.
Over the next several years the Electric Utility will continue to execute its usual monitoring,
repair, and replacement routine for the distribution system, but will also begin the rollout of
various smart grid technologies. The utility continues to monitor the growth of electric vehicle
ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these
factors may begin to create notable increases in electric consumption and have a variety of
impacts on the distribution system. As housing stock is turned over, however, stricter building
codes may help to counteract load growth, as may increasing numbers of rooftop solar
installations. The utility has already started to take some of these factors into account in its
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long-term planning processes, but will need to continue to incorporate them into its planning
methodologies.
Over the long term, it is conceivable that electricity could replace natural gas and petroleum
almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another
potential fuel source under development and other technologies might be developed. Initial
analysis of these types of scenarios is being undertaken in the context of the Sustainability and
Climate Action Plan (S/CAP) development process. These types of scenarios require careful
planning for the associated load growth to make sure the distribution system did not end up
overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility
distribution system management to accommodate integration of the various technologies
involved in electrification.
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SECTION 6 : DETAILS AND ASSUMPTIONS
SECTION 6 A : ELECTRICITY PURCHASES
As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just
over 30% of the portfolio in FY 2016, and are projected to rise to roughly 50% starting in FY
2017. The remainder comes from unspecified market sources. Under the City’s Carbon Neutral
Plan, CPAU purchases RECs corresponding to the amount of market energy it purchases.
Figure 14: Electricity Supply by Source
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Figure 15 shows the historical and projected costs for the electric supply portfolio,5 as well as
average and actual hydroelectric generation.6 Electric supply costs increased in FY 2013, FY
2014, and FY 2015 due to the drought, which reduced the amount of generation from
hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market
purchase costs. Even if hydroelectric generation returns to normal levels, costs will increase in
FY 2017 due to increases in renewable energy costs as various renewable projects come online
to fulfill the City’s carbon neutral and RPS goals. Transmission charges are also projected to
increase as new transmission lines are built throughout California to accommodate new
renewable projects. In total, electric supply costs are projected to increase to $77.8 million by
FY 2020, at which point all currently contracted renewable projects will be online. Supply costs
are only projected to change slightly in subsequent years.
Figure 15: Electric Supply Portfolio Costs, Historical and Projected
5 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase
figures shown in Appendix A: Electric Utility Financial Forecast Detail
6 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share
of the output of the CVP Federal hydropower project.
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SECTION 6 B : OPERATIONS
CPAU’s Electric Utility operations include the following activities:
•Administration, including financial management of charges allocated to the Electric
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 Electric 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 C: Description of Electric utility Operational Activities includes detailed descriptions of
the work associated with each of these activities.
From FY 2012 to FY 2015, Operations costs increased by less than 1% per year on average. In
2013 there was a one-time increase in expenses associated with an adjustment to the value of
the City’s investment portfolio. Over the forecast horizon, excluding debt service and transfers,
costs are projected to increase by roughly 2 to 4 % per year.
Figure 16: Historical and Projected Electric Utility Operational Costs
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SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
CIP spending for FY 2018 through FY 2023 is projected to decrease somewhat from last year’s
forecast, primarily due to the removal of some major one-time projects, including service
connection upgrades for a few major customers. Other projects still slated to continue are pole
replacements related to the Fiber to the Home project, and Smart Grid upgrades. Ongoing
capital investment in the electric distribution system is also increasing. This forecast assumes
that smart grid projects are financed from the Electric Special Projects Reserve and with
additional funding from the water and gas funds, but it would also be possible to use bond
financing.
Excluding the one-time projects listed above, the CIP plan for FY 2018 to FY 2022 is primarily
funded by utility rates, but other sources of funds include connection fees (for Customer
Connections), phone and cable companies (primarily for undergrounding), and other funds (for
smart grid). The details of the CIP budget will be available in the Proposed FY 2018 Utilities
Capital Budget. Figure 16 shows the adopted / proposed / projected capital budgets as well as
actual and projected capitalized administrative overhead associated with the program.
Figure 17: Electric Utility CIP Spending
SECTION 6 D : DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. The Electric Utility currently
makes payment on one bond issuance, the 2007 Electric Utility Clean Renewable Energy Tax
Credit Bonds, Series A. This $1.5 million bond issuance was to fund a portion of the construction
costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive
Center, and Cubberley Community Center. The capacity of these projects totaled 250 kW. In
exchange for funding part of the construction costs Electric Utility receives the RECs from these
projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are interest
free (the investors receive a tax credit from the federal government). This bond issuance is
secured by the net revenues of the Electric Utility. Debt service for this bond continues through
2021, and for the financial forecast period is as follows:
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Table 10: Electric Utility Debt Service ($000)
FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
2007 Clean Renewable
Energy Bonds 100 100 100 100 100 -
The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage
ratio of 125% of debt service. The current Financial Plan maintains compliance with these
covenants throughout the forecast period, as shown in Appendix C.
The Electric Utility’s reserves and net revenue are also pledged as security for the bond
issuances listed in Table 11, even though the Electric Utility is not responsible for the debt
service payments. The Electric 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.
Table 11: Other Issuances Secured by Electric Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Electric Utility’s:
Net Revenues Reserves
1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No
1999 Utility Revenue Bonds, Series A Storm Drain
Wastewater Collection
Wastewater Treatment
$1,207 No Yes
2009 Water Revenue Bonds (Build
America Bonds) Water $1,977* No Yes
2011 Utility Revenue Refunding
Bonds, Series A
Gas
Water $1,457 No Yes
*Net of Federal interest subsidy
SECTION 6 E : EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a methodology adopted
by Council in 2009, which has remained unchanged since then.7 Each year it is calculated
according to the 2009 Council-adopted methodology, and does not require additional Council
action.
SECTION 6 F : WHOLESALE REVENUES AND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 13% comes
from other sources. Of these other sources, about a third represent wholesale “revenues” that
are included solely for accounting purposes. These revenues have offsetting electric supply
7 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
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purchase costs, and do not normally affect the utility’s net position. Of the remaining revenues,
the largest revenue sources are interest on reserves, connection fees for new or replacement
electric services, and carbon allowance revenues associated with the State’s cap-and-trade
program. In FY 2016 these sources represented roughly 50% of revenue from sources other
than electricity sales. The remaining FY 2016 revenues consisted of a variety of one-time
transfers.
Revenues from connection fees have more than doubled since FY 2009. Revenue from these
sources decreased slightly during the recession, but has increased substantially since then,
peaking in FY 2014. Staff is forecasting slightly lower revenue from this source in subsequent
years.
Carbon allowance revenues are projected to stay stable through the forecast period, as is
interest income. However, both of these revenue sources are subject to some uncertainty. The
State’s cap-and-trade program regulations only describe the program through 2020. This
forecast assumes the program will remain in place with similar program design following 2020,
but that may not be the case. CARB is in the process of establishing post-2020 rules.
The forecast for interest income assumes current interest rates continue and there are no
major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates
rise, interest income could increase, and if reserves decreased (due to drought or a withdrawal
from the ESP reserve for a major project), interest income would decrease.
SECTION 6 G : SALES REVENUES
Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the
projected rate changes shown in Figure 7. As discussed in Section 5A, sales revenues for this
utility stay relatively stable due to the mild climate in Palo Alto, but decreased significantly in
FY 2017. In addition, Palo Alto is a built out City, with incremental growth in population and
relatively stable commercial customer loads.
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SECTION 7 : COMMUNICATIONS PLAN
CPAU communication methods include use of the Utilities website, utility bill inserts, messaging
on bills and envelopes, email newsletters, print ads in local publications, videos and
participation in community outreach events. The FY 2018 Electric Utility communications
strategy covers these primary areas: rates, efficiency, renewables, operations, infrastructure,
safety, and changes to utility economic conditions in the wake of the drought.
In FY 2018, CPAU is proposing an 12% increase in electric utility rates. Prior to FY 2017, electric
utility rates had not increased since 2009, as the City has been drawing down reserves from the
Electric Fund. The rate increase was necessary last year and again in FY 2018, as these reserves
are below the minimum reserve level. Communications will focus on the reasons why a rate
increase is necessary, and how this percentage has been impacted due to the drought,
renewable projects, capital improvement and other costs. Palo Alto purchases a significant
portion of its electricity from hydroelectric resources. Severe drought conditions over the past
few years reduced available hydroelectric supplies, requiring the City to purchase more costly
replacement electric supplies. Since the State received a great deal of precipitation in the latter
part of FY 2017, communications staff will now focus messaging on how increased hydroelectric
supplies will impact and potentially change the forecast for electric rates moving forward, at
least in the short-term.
Reliability and safety are primary concerns for CPAU and City Council has placed increasing
emphasis on capital improvement investments for utility infrastructure. In order to maintain
system integrity, continued capital improvement costs are necessary. Deferring such costs to
future years would not be prudent, as deferred investment in maintenance, operations and
capital improvement upgrades could potentially jeopardize the safety and reliability of the
electric utility system. Despite these costs and increasing rates, CPAU’s rates remain lower than
the neighboring community average, including for municipal and investor-owned utilities
(PG&E). Keeping costs low is one of the benefits CPAU offers its customers as a public utility
provider.
CPAU will continue to communicate about the City’s carbon neutral electric supply portfolio.
Outreach includes apprising the public of major renewable energy purchase agreements, which
contribute toward Palo Alto’s long-term energy security and commitment to sustainability.
Recent power purchase agreements have allowed CPAU to procure long-term renewable
electric supplies at low costs. While upfront capital costs to bring these renewable projects
online may initially contribute towards some increase in CPAU’s electric rates, these higher
costs are expected to taper off once the projects begin commercial operations. CPAU will
highlight these environmental attributes and value in our communications.
Throughout the year, communications staff promotes CPAU’s electric efficiency services,
rebates and local renewable energy programs. From January 2015 to December 2016, CPAU
encouragedcommunity participation in the Georgetown University Energy Prize competition, a
friendly, national campaign for energy efficiency. This two-year campaign encouraged the
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community to reduce energy use and compete for a $5 million prize. Within the past one to two
years, CPAU launched new programs thatallow customers to better understand and manage
their energy use. These programs include the Home Efficiency Genie; a free utility bill analysis
service with option for a subsidized in-depth home energy assessment; and an online utility
portal for customers to view consumption history, learn about efficiency tips and CPAU
programs they can take advantage of for home energy efficiency.
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APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Reserves Management Practices
Appendix C: Description of Electric utility Operational Activities
Appendix D: Samples of Recent Electric Utility Outreach Communications
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APPENDIX A : ELECTRIC UTILITY FINANCIAL FORECAST DETAIL
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1 FISCAL YEAR FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027
2
3 ELECTRIC LOAD
4 Purchases (MWh)969,519 976,319 980,894 979,005 977,292 945,703 960,601 940,860 938,688 936,402 934,369 934,369 934,369 934,369 934,369 934,369
5 Sales (MWh)942,562 946,841 950,784 936,773 937,157 906,562 908,459 907,858 905,762 903,556 901,594 901,594 901,594 901,594 901,594 901,594
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1156$ 0.1154$ 0.1164$ 0.1158$ 0.1156$ 0.1233$ 0.1407$ 0.1506$ 0.1506$ 0.1506$ 0.1516$ 0.1553$ 0.1568$ 0.1579$ 0.1589$ 0.1600$
9 Change in System Average Rate -1%0%1%0%0%10%14%7%0%0%1%2%1%1%1%1%
10 Change in Average Residential Bill -1%-4%-1%-5%3%10%11%6%-1%-1%0%2%1%0%0%0%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)343,000 1,886,000 305,000 - - - - - - - - - - - - -
14 Commitments (Non-CIP)1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000
15 Restricted for Debt Service - - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - -
17 Central Valley Project Reserve 305,000 314,000 313,000 329,000 - - - - - - - - - - - -
18 Underground Loan Reserve 736,000 742,000 738,000 734,000 730,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000
19 Public Benefits Reserves 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 1,330,970 739,050 279,587 94,959 - - - - - -
20 Electric Special Projects Reserve 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 41,665,260 41,525,693 41,192,360 42,859,027 46,192,360 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260
21 Hydro Stabilization Reserve - - - - 17,000,000 11,400,000 2,400,000 - - - - - - - - -
22 Capital Reserves - - - - - - - - - - - - - - - -
23 Rate Stabilization Reserves 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 9,011,000 3,600,000 - - - - - - - - -
24 Operations Reserves - - - - 22,498,000 21,850,000 21,570,031 28,477,295 31,328,331 31,984,129 32,727,128 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904
25 Unassigned - - - - - - - - 915,938 (0) 0 0 - - - -
26 TOTAL STARTING RESERVES 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,444,000 75,072,262 75,248,039 78,222,216 79,444,115 83,425,489 85,905,601 85,771,388 85,397,337 88,128,265 89,642,164
27
28 REVENUES
29 Net Sales 109,309,318 109,974,337 110,246,264 108,873,377 108,312,917 111,743,300 127,804,839 136,731,078 136,415,457 136,083,191 136,693,648 139,980,910 141,364,099 142,326,185 143,276,966 144,246,140
30 Wholesale Revenues 7,189,218 6,635,790 6,010,409 6,267,000 5,534,000 11,422,865 16,360,219 13,481,291 15,723,490 16,405,058 17,841,074 17,242,448 17,467,779 17,643,588 17,905,633 19,002,541
31 Other Revenues and Transfers In 7,027,230 9,624,213 13,669,185 9,688,480 10,129,274 10,013,826 14,509,829 12,934,637 21,875,693 18,854,966 15,870,577 12,946,907 13,320,702 13,772,401 14,201,802 14,631,713
32 TOTAL REVENUES 123,525,766 126,234,340 129,925,858 124,828,858 123,976,191 133,179,991 158,674,887 163,147,006 174,014,640 171,343,215 170,405,299 170,170,265 172,152,580 173,742,173 175,384,402 177,880,394
33
34 EXPENSES
35 Electric Supply Purchases 58,724,136 61,313,637 68,785,977 80,022,010 79,114,644 84,371,202 87,986,828 89,065,816 90,840,796 90,727,608 92,220,793 91,758,113 92,924,517 93,903,644 95,224,116 96,464,584
36 Operating Expenses
37 Administration
38 Allocated Charges 3,416,423 4,399,674 4,139,837 4,511,222 5,148,470 3,376,852 3,461,365 3,547,989 3,636,783 3,727,743 3,820,946 3,916,481 4,014,404 4,114,776 4,217,658 4,323,112
39 Rent 3,839,201 3,875,836 4,051,044 4,147,742 4,997,101 5,121,102 5,274,735 5,432,977 5,595,966 5,763,845 5,936,761 6,114,864 6,298,310 6,487,259 6,681,877 6,882,333
40 Debt Service 8,902,751 9,265,736 9,020,651 9,037,000 8,985,994 8,889,090 8,868,768 8,471,091 8,480,048 8,444,315 8,453,684 9,299,046 8,893,834 4,898,677 4,896,047 4,894,784
41 Transfers and Other Adjustments 11,603,695 16,797,054 11,329,973 11,003,993 5,920,297 12,078,949 13,226,214 13,275,892 14,159,863 14,163,159 14,166,536 14,169,998 14,173,547 14,177,184 14,180,913 14,184,734
42 Subtotal, Administration 27,762,069 34,338,299 28,541,506 28,699,957 25,051,862 29,465,993 30,831,082 30,727,949 31,872,660 32,099,063 32,377,926 33,500,388 33,380,095 29,677,896 29,976,494 30,284,963
43 Resource Management 2,654,024 3,024,268 3,541,524 2,138,615 2,035,834 3,240,541 3,356,945 3,476,405 3,600,582 3,707,001 3,803,153 3,902,819 4,005,096 4,110,053 4,217,761 4,328,292
44 Demand Side Management 4,541,531 3,529,529 3,187,875 3,491,470 3,723,605 3,690,063 3,773,952 3,639,388 3,357,212 3,297,042 3,255,251 3,339,598 3,384,926 3,431,076 3,478,065 3,525,906
45 Operations and Mtc 9,288,490 9,601,481 9,488,627 10,716,881 11,514,846 13,702,158 14,158,618 14,626,674 15,111,694 15,541,894 15,941,538 16,354,711 16,778,592 17,213,460 17,659,598 18,117,300
46 Engineering (Operating)1,057,783 1,114,945 1,102,008 1,230,160 1,578,022 1,840,073 1,889,674 1,940,499 1,992,737 2,044,182 2,095,630 2,148,473 2,202,649 2,258,191 2,315,133 2,373,512
47 Customer Service 1,908,493 2,007,322 2,032,231 1,548,851 1,538,363 2,212,967 2,297,149 2,383,613 2,473,714 2,549,014 2,615,594 2,684,750 2,755,735 2,828,597 2,903,385 2,980,150
48 Allowance for Unspent Budget - - - - - (1,461,604) (1,508,656) (1,556,914) (1,606,879) (1,651,905) (1,694,232) (1,737,944) (1,782,784) (1,828,782) (1,875,967) (1,924,370)
49 Subtotal, Operating Expenses 47,212,389 53,615,844 47,893,770 47,825,933 45,442,532 52,690,192 54,798,765 55,237,614 56,801,721 57,586,290 58,394,860 60,192,796 60,724,308 57,690,491 58,674,470 59,685,754
50 Capital Program Contribution 13,837,241 15,113,859 13,016,111 14,005,915 11,128,015 21,490,335 15,573,950 15,869,398 25,150,225 19,047,944 17,449,100 18,353,570 18,877,806 19,417,110 19,971,917 20,542,674
51 TOTAL EXPENSES 119,773,766 130,043,340 129,695,858 141,853,858 135,685,191 158,551,729 158,359,542 160,172,828 172,792,742 167,361,841 168,064,753 170,304,478 172,526,631 171,011,245 173,870,503 176,693,012
52 22,058,000.0 26,659,398 15,868,470 16,320,285 16,784,774
53 ENDING RESERVES
54 Reappropriations (Non-CIP)1,886,000 305,000 - - - - - - - - - - - - - -
55 Commitments (Non-CIP)2,737,000 3,528,000 3,164,000 3,102,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000 3,777,000
56 Restricted for Debt Service - - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 - - - - - - - - - - - - -
58 Central Valley Project Reserve 314,000 313,000 329,000 - - - - - - - - - - - - -
59 Underground Loan Reserve 742,000 738,000 734,000 730,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000 729,000
60 Public Benefits Reserves 1,149,000 2,197,000 2,064,000 2,574,000 1,839,000 1,330,970 739,050 279,587 94,959 - - - - - - -
61 Electric Special Projects Reserve 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 41,665,260 41,525,693 41,192,360 42,859,027 46,192,360 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260 44,665,260
62 Hydro Stabilization Reserve - - - 17,000,000 11,400,000 2,400,000 - - - - - - - - - -
58 Capital Reserve - - - - - - - - - - - - - - - -
59 Rate Stabilization Reserve 74,609,000 69,029,000 70,049,000 14,411,000 9,011,000 3,600,000 - - - - - - - - - -
60 Operations Reserve - - - 22,498,000 21,850,000 21,570,031 28,477,295 31,328,331 31,984,129 32,727,128 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904 41,658,286
61 Unassigned - - - - - - - 915,938 (0) 0 0 - - - - -
62 TOTAL ENDING RESERVES 132,757,000 128,948,000 129,178,000 112,153,000 100,444,000 75,072,262 75,248,039 78,222,216 79,444,115 83,425,489 85,905,601 85,771,388 85,397,337 88,128,265 89,642,164 90,829,546
63
64 OPERATIONS RESERVE
65 Min (60 days of non-capital expenses)23,548,140 23,951,699 25,106,757 25,973,915 26,332,908 26,857,109 27,090,134 27,593,969 27,942,086 28,353,037 28,150,419 28,667,754 29,179,891
66 Target (90 days of non-capital expenses)33,151,752 33,702,675 35,379,286 36,622,631 37,102,294 37,828,286 38,116,222 38,808,965 39,266,545 39,816,759 39,444,963 40,151,398 40,848,296
67 Max (120 days of non-capital expenses)42,755,364 43,453,651 45,651,816 47,271,347 47,871,681 48,799,463 49,142,310 50,023,961 50,591,003 51,280,480 50,739,507 51,635,042 52,516,702
68 Risk Assessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
69
70 DEBT SERVICE COVERAGE RATIO
71 Net Revenues (125% of Debt Service)1090% 1140% 1193% 1315%1286% 1442% 1510% 1603% 1641% 1656% 1682% 1534% 1628% 2995% 3043% 3090%
72 Available Reserves (5x Debt Service)*14.4 13.5 14.0 12.1 10.8 8.0 8.1 8.8 8.9 9.4 9.7 8.8 9.2 17.2 17.5 17.8
*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.
6053706
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 88%87%85%87%87%84%81%84%78%79%80%82%82%82%82%81%
5 Other Revenues and Transfers In 12%13%15%13%13%16%19%16%22%21%20%18%18%18%18%19%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 46%46%52%55%54%50%46%47%45%46%46%46%46%47%47%47%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%3%3%3%4%2%2%2%2%2%2%2%2%2%2%2%
13 Rent 3%3%3%3%4%3%3%3%3%3%4%4%4%4%4%4%
14 Debt Service 7%7%7%6%7%6%6%5%5%5%5%5%5%3%3%3%
15 Transfers and Other Adjustments 10%13%9%8%4%8%8%8%8%8%8%8%8%8%8%8%
16 Subtotal, Administration 23%26%22%20%18%19%19%19%18%19%19%20%19%17%17%17%
17 Resource Management 2%2%3%2%2%2%2%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 8%7%7%8%8%9%9%9%9%9%9%10%10%10%10%10%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 2%2%2%1%1%1%1%1%1%2%2%2%2%2%2%2%
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 36%39%34%31%31%31%32%32%31%32%33%33%33%32%32%32%
23 Capital Program Contribution 12%12%10%10%8%14%10%10%15%11%10%11%11%11%11%12%
24 TOTAL EXPENSES 94%96%97%96%93%94%88%89%90%90%89%90%90%90%90%90%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 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
28 1. Load Net Revenue 77,428 652,853 1,208,477
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 3,397,119
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 539,073
31 4. Carbon Neutral Cost 331,630 303,022 114,983
32 5. Market Price 909,196 775,584 1,138,589
33 6. Local Capacity 475,962 408,388 446,695
34 7. Transmission/CAISO 4,555,915 3,741,647 2,806,120
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 2,973,619
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 13,624,674
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 196%172%176%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 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
44 Distribution Revenue Variance 3,244,706 3,260,213 3,146,827 3,699,758 3,870,807 3,861,873 3,852,466 3,915,598 4,175,044 4,368,672 4,527,949 4,602,989 4,679,481
45 10% CIP Program Contingency 1,400,592 1,112,802 2,149,034 1,557,395 1,586,940 2,515,022 1,904,794 1,744,910 1,835,357 1,887,781 1,941,711 1,997,192 2,054,267
46 Total Risk Asssessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
47 Projected Operations Reserve 22,498,000 21,850,000 21,570,031 28,477,295 28,507,266 31,984,129 32,727,129 36,734,340 36,600,128 36,226,077 38,957,005 40,470,904 41,658,286
48 Operations Reserve, % of Risk Value 484%500%407%542%522%502%568%649%609%579%602%613%619%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - - 15,208,552 15,033,113 16,240,825 16,860,400 17,001,701 17,325,251 17,328,711 17,602,415 17,709,305 17,862,689 17,395,887 17,642,251 17,876,454
46 Target (90 days of non-capital expenses)- - - 22,812,829 22,549,669 24,361,237 25,290,599 25,502,552 25,987,877 25,993,067 26,403,622 26,563,958 26,794,033 26,093,831 26,463,376 26,814,681
47 Max (120 days of non-capital expenses)- - - 30,417,105 30,066,225 32,481,649 33,720,799 34,003,403 34,650,502 34,657,422 35,204,830 35,418,611 35,725,378 34,791,775 35,284,501 35,752,908
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - - 8,339,587 8,918,586 8,865,932 9,113,516 9,331,206 9,531,858 9,761,423 9,991,554 10,232,781 10,490,348 10,754,532 11,025,503 11,303,437
51 Target (90 days of non-capital expenses)- - - 10,338,923 11,153,006 11,018,050 11,332,032 11,599,742 11,840,409 12,123,155 12,405,343 12,702,586 13,022,725 13,351,132 13,688,022 14,033,616
52 Max (120 days of non-capital expenses)- - - 12,338,259 13,387,426 13,170,167 13,550,548 13,868,279 14,148,960 14,484,888 14,819,131 15,172,392 15,555,102 15,947,732 16,350,541 16,763,794
53 Risk Assessment Value 4,645,297 4,373,014 5,295,861 5,257,153 5,457,746 6,376,895 5,757,260 5,660,508 6,010,401 6,256,453 6,469,660 6,600,181 6,733,749
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1090%1140%1193%1315%1286%1442%1510%1603%1641%1656%1682%1534%1628%2995%3043%3090%
57 Available Reserves (5x Debt Service)*14.4 13.5 14.0 12.1 10.8 8.0 8.1 8.8 8.9 9.4 9.7 8.8 9.2 17.2 17.5 17.8
58 *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.
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June 16, 2014 43 | Page
APPENDIX B : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
(This section includes the proposed amendments to this section. This section will be finalized
following Council adoption of the final amended version.)
The following reserves management practices are used when developing the Electric 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. Supply Fund Reserves
The Electric Supply Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserve for Commitments)
b)For operating budgets reappropriated from previous years, as described in Section 5
(Reserve for Reappropriations)
c)For special projects for the benefit of the Electric Utility ratepayers, as described in
Section 6 (Electric Special Projects Reserve)
d)For year to year balancing of costs associated with the Electric Utility’s hydroelectric
resources, as described in Section 7 (Hydroelectric Stabilization Reserve)
e)For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
f)For operating contingencies, as described in Section 12 (Operations Reserves)
g)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 13 (Unassigned Reserves).
Section 3. Distribution Fund Reserves
The Electric Distribution Fund Balance is reserved for the following purposes:
a)For existing contracts, as described in Section 4 (Reserves for Commitments)
b)For operating and capital budgets reappropriated from previous years, as described in
Section 5 (Reserves for Reappropriations)
c)As an offset to underground loan receivables, as described in Section 8 (Underground
Loan Reserve)
d)To hold Public Benefit Program funds collected but not yet spent, as described in Section
9 (Public Benefits Reserve)
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June 16, 2014 44 | Page
e) For cash flow management and contingencies related to the Electric Utility’s Capital
Improvement Program (CIP), as described in Section 10 (CIP Reserve)
f) For rate stabilization, as described in Section 1.d) (Rate Stabilization Reserves)
g) For operating contingencies, as described in Section 12 (Operations Reserves)
h) 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 14 (Unassigned Reserves).
Section 4. Reserves for Commitments
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Commitments will be set to an amount equal to the total remaining spending
authority for all contracts in force for the Electric Supply Fund and Electric Distribution
Fund, respectively, at that time.
Section 5. Reserves for Reappropriations
At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund
Reserves for Reappropriations will be set to an amount equal to the amount of all remaining
capital and non-capital budgets that will be reappropriated to the following fiscal year for
each Fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. Electric Special Projects Reserve
The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the
policies and timelines set forth in Resolution 9206 (Resolution of the Council of the City of
Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve
and Adoption of Electric Special Project Reserve Guidelines). These policies and timelines
are included from Resolution 9206 as amended to refer to the reserves structure set forth
in these Reserves Management Practices:
a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b) The ESP Reserve funds must be used for projects of significant impact;
c) Projects proposed for funding must demonstrate a need and value to electric
ratepayers. The projects must have verifiable value and must not be speculative, or
high-risk in nature;
d) Projects proposed for funding must be substantial in size, requiring funding of at least
$1 million;
e) The preferred projects to be funded by the ESP Reserve must be identified by end of
FY 2015;
f) Any uncommitted funds remaining at the end of FY 2020 will be transferred to the
Electric Supply Operations Reserve and the ESP Reserve will be closed; and
g) Funds may be used for analysis and pilot projects which would be the basis for planned
large projects.
Section 7. Hydroelectric Stabilization Reserve
Supply cost savings and surplus energy sales revenue associated with higher than average
generation from hydroelectric resources may be added to the Electric Supply Fund’s
Hydroelectric Stabilization Reserve by action of the City Council and held to offset higher
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June 16, 2014 45 | Page
commodity supply costs during years of lower than average generation. Withdrawal of
funds from the Hydroelectric Stabilization Reserve requires action by the City Council.
Section 8. Underground Loan Reserve
At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the
principal payments made against outstanding underground loans.
Section 9. Public Benefits Reserve
The Public Benefits Reserve will be increased by the amount of unspent Public Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. 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 60 days of budgeted CIP expense
Maximum Level 120 days 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 to or removed from the Reserve
for Commitments 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
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June 16, 2014 46 | Page
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 11. Rate Stabilization Reserves
Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves
by action of the City Council and held to manage the trajectory of future year rate increases.
Withdrawal of funds from either Rate Stabilization Reserve requires action by the City
Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year,
any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from
this Reserve by the end of the Financial Planning Period.
Section 12. Operations Reserves
The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to
manage normal variations in the costs of providing electric service and as a reserve for
contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves
described in Section 4 to d) above will be included in the appropriate Operations Reserve
unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff
will manage the Operations Reserves according to the following practices:
a) The following guideline levels are set forth for the Electric Supply Fund 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 Supply Fund O&M and commodity expense
Target Level 90 days of Supply Fund O&M and commodity expense
Maximum Level 120 days of Supply Fund O&M and commodity expense
b) The following guideline levels are set forth for the Electric Distribution Fund Operations
Reserve. These guideline levels are calculated for each fiscal year of the Financial
Planning Period based on the levels of O&M expense forecasted for that year in the
Financial Plan.
Minimum Level 60 days of Distribution Fund O&M expense
Target Level 90 days of Distribution Fund O&M expense
Maximum Level 120 days of Distribution Fund O&M expense
c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund
or Distribution Fund’s 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 an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 47 | Page
designed to return both Operations Reserves to their target levels by the end of the
forecast period.
e)Maximum Level: If, at any time, either Operations Reserve reaches its maximum level,
no funds may be added to this Reserve. Any further increase in that fund’s Fund
Balance shall be automatically included in the Unassigned Reserve described in Section
13, below.
Section 13. Unassigned Reserves
If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund
reaches its maximum level, any further additions to that fund’s Fund Balance will be held in
the Unassigned Reserve. If there are any funds in either 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 Electric 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 2016, and the next Financial Planning
Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign
the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an
alternative plan that retains these funds or returns them over a longer period of time.
Section 14. Intra-Utility Transfers between Supply and Distribution Funds
Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
ELECTRIC UTILITY FINANCIAL PLAN
June 16, 2014 48 | Page
APPENDIX C : DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Electric 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 electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
•monitoring the substations and performing routine maintenance;
•performing preventative maintenance on the system;
•monitoring the system’s status from the UCC using SCADA;
•maintaining the SCADA system;
•investigating outages and other customer complaints and performing emergency
repairs;
•clearing vegetation near overhead power lines; and
•testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX D : SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
570 Kirkland Way, Suite 100
Kirkland, Washington 98033
Telephone: 425 889-700 Facsimile: 425 889-2725
A registered professional engineering corporation with offices in
Kirkland, WA and Portland, OR
March 29, 2017
TO : Jon Abendschein, City of Palo Alto
Eric Keniston, City of Palo Alto
FROM: Anne Falcon, EES Consulting
SUBJECT: 2017 COSA Model and Rate Design Update
Introduction
The City’s COSA and Rate Design models consist of four components: a FERC Account Model
that translates the City’s budget accounts, a Cost of Service (COS) model that allocates the
budgeted costs to customer classes, a Lighting and Traffic Signal COS and Rate Model that
allocates costs to lighting and traffic signal customers, and a Rate Design Model that generates
the rates for all other customer classes. As part of the annual budget process, the FERC Account
Model, Electric COS Model , Lighting and Traffic Signal Model, and Rate Design models were
updated for the FY 2018 budget year. This update included updating financial and load data as
well as reviewing other inputs that impact the City of Palo Alto’s cost of providing electric
service . The underlying methodology of the COSA was not changed. rather EES assisted the City
of Palo Alto with updating the inputs to the existing methodology to reflect FY 2018 sales and
budget projections, and streamline one rate schedule to remove redundancies (e.g. removing
rate schedule E -18).
Summary of Updates
As part of the update, the City staff provided updated budget and load forecasts for the years
FY 2018 through FY 2020. After reviewing the budget data, the revenue requirement and load
forecast in the FERC Account Model and COSA model were updated based on the projected FY
2018 budget. Projected revenues from current rates were forecast for each rate schedule
based on the updated load data staff provided. Rate schedule 18 (Municipal Electric Service)
was removed as customers historically in that rate schedule have been reclassified, as of July
2017to Rate Schedule E -4 (Medium Commercial Electric Service) and E -7 (Larg e Commercial
Electric Service), to more accurately reflect the costs of serving municipal customers .
ATTACHMENT C
MEMORANDUM TO Jon Abendschein & Eric Keniston
March 29, 2017
Page 2
The Lighting and Traffic Signal Model was updated with FY 2018 transmission and distribution
Operation and Maintenance costs, power supply costs and total overhead costs. This model
determines the total cost of service for the street lighting and traffic lighting rate classes based
on individual bulb type and O&M requirements. This model was then used to determine the
costs associated with providing service to the traffic light rate customers only. The share of
costs associated with traffic lights service will collected as a transfer from the City’s General
Fund to its Electric Utility and is reflected in the Electric COSA model under “Other Revenues”.
The final model update was the rate design model. This model takes the updated COS Model
cost allocation results by rate class and develops rates for each class that meet the allocated
revenue requirement for each rate class . The update s included updated FY 2018 allocated
costs, updated seasonal power cost splits, updated billing data (such as load in each residential
rate tier, Non-Coincident Peaks and energy consumption) and Time of Use (TOU) marginal
costs.
Using the same methodology that was developed in 2016, the following rates were updated:
• E-1: Tier 1 and Tier 2 Energy charges, minimum bill and PBC
• E-1 TOU: TOU energy rates by period and season
• E-2: Energy by season, minimum bill and PBC
• E-4: Energy and dema nd by season, minimum bill and PBC
• E-4 TOU: TOU energy and demand rates by period and season
• E-7: Energy and demand rates by season, minimum bill and PBC
• E-7 TOU: TOU energy and demand rates by period and season
An updated rate comparison is provided below.
Summary of Results
The following provide the updated rates compared to current rates:
Residential
Energy Rates
Existing
($/kWh)
New
($/kWh) Percent Change
Tier 1 $0.11029 $0.12159 10.2%
Tier 2 $0.16901 $0.19001 12.4%
MEMORANDUM TO Jon Abendschein & Eric Keniston
March 29, 2017
Page 3
Please let me know if you have any questions.
Commercial Existing Rates
Demand ($/kW)Energy ($/kWh)
Summer Winter Summer Winter
E-2 $0.16845 $0.11445
E-4 $19.68 $14.04 $0.10229 $0.08049
E-7 $18.34 $15.65 $0.08749 $0.06242
Commercial New Rates
Demand ($/kW)Energy ($/kWh)
Summer Winter Summer Winter
E-2 $0.18885 $0.13267
E-4 $21.05 $15.36 $0.11673 $0.08890
E-7 $23.84 $15.59 $0.09802 $0.07188
Difference (%)
Demand Energy
Summer Winter Summer Winter
E-2 12.1%15.9%
E-4 7.0%9.4%14.1%10.5%
E-7 30.0%-0.4%12.0%15.1%
Attachment D
Not Yet Approved
170329 jb 6053934 1
Resolution No. ____
Resolution of the Council of the City of Palo Alto Adopting an Electric
Rate Increase and Amending Rate Schedules E-1 (Residential Electric
Service), E-2 (Small Commercial Electric Service), E-2-G (Small
Commercial Green Power Electric Service), E-4 (Medium Commercial
Electric Service), E-4-G (Medium Commercial Green Power Electric
Service), E-4 TOU (Medium Commercial Time of Use Electric Service),
E 7 (Large Commercial Electric Service), E-7-G (Large Commercial
Green Power Electric Service), E-7 TOU (Large Commercial Time of
Use Electric Service), and E-14 (Street Lights)
R E C I T A L S
A. 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.
The Council of the City of Palo Alto hereby RESOLVES as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule E-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 E-2 (Small Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-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 E-2-G (Small Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-2-G, 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 E-4 (Medium Commercial Electric Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July
1, 2017.
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4-G (Medium Commercial Green Power Electric Service) is hereby amended to
Attachment D
Not Yet Approved
170329 jb 6053934 2
read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall become
effective July 1, 2017.
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-4 TOU (Medium Commercial Time of Use Electric Service) is hereby amended
to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended, shall become
effective July 1, 2017.
SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 (Large Commercial Electric Service) is hereby amended to read as attached
and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2017.
SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7-G (Large Commercial Green Power Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become
effective July 1, 2017.
SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-7 TOU (Large Commercial Time of Use Electric Service) is hereby amended to
read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become
effective July 1, 2017.
SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule E-14 (Street Lights) is hereby amended to read as attached and incorporated.
Utility Rate Schedule E-14, as amended, shall become effective July 1, 2017.
SECTION 11. The Council makes the following findings:
a. The revenue derived from the adoption of this resolution shall be used only for the
purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto.
b. 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.
c. The adoption of this resolution changing electric 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
Attachment D
Not Yet Approved
170329 jb 6053934 3
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
RESIDENTIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-1-1 dated 7-1-201609 Sheet No E-1-1
A. APPLICABILITY:
This schedule applies to separately metered single-family residential dwellings receiving retail
energy services from the City of Palo Alto Utilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides electric service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Tier 1 usage
$0.0660588
3
$0.05164795 $0.0039151 $0.1102912159
Tier 2 usage
Any usage over Tier 1
0.11253097
28
0.0682207358 0.0039151 0.169001
Minimum Bill ($/day) 0.30672938
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 electricity usage shall be calculated and billed based upon a level of 11 kWh per
day, prorated by meter reading days of service. As an example, for a 30-day bill, the Tier
1 level would be 330 kWh. For further discussion of bill calculation and proration, refer
to Rule and Regulation 11.
{End}
ATTACHMENT E
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-1 dated 7-1-201609 Sheet No E-2-1
A. APPLICABILITY:
This schedule applies to non-demand metered electric service for small non-
residentialcommercial customers and master-metered multi-family facilities.
B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides electric service.
C. UNBUNDLED RATES:
Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total
Summer Period
$0.105910909
4
$0.0740007903
$0.0039151
$0.1684518885
Winter Period
0.0641707520
0.0467705356
0.0039151
0.132671445
Minimum Bill ($/day)
0.7328657
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. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-2 dated 7-1-201609 Sheet No E-2-2
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum demand meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that if in case the Customer’s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type demand meter which does not reset after a definite time interval
may be used at the City's option.
The billing demand to be used in computing charges under this schedule will be the
actual maximum demand in kilowatts for the current month. An exception is that the
billing demand for customers with Thermal Energy Storage (TES) will be based upon the
actual maximum demand of such customers between the hours of noon and 6 pm on
weekdays.
{End}
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL
ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-1 dated 7-1-201609 Sheet No E-2-1
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL
GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-1 dated 7-1-20164 Sheet No E-2-G-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Electric Service from the City of
Palo Alto Utilities under the Palo Alto Green Program:
1. Small non-residentialcommercial Customers receiving Non-Demand Metered electric
service; and
2. Customers with accounts at Master-metered multi-family facilities.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Palo Alto
Green
Charge Total
Summer Period
$0.10591090
94
$0.07903400
$0.003915
1 $0.0020
$0.170451
9085
Winter Period
0.075206417
0.053564677
0.0035191 0.0020
$0.116451
3467
Minimum Bill ($/day)
0.7328657
2. 1000 kWh Block Purchase Option:
Per kilowatt-hour (kWh) Commodity Distribution
Public
Benefits
Total
Summer Period
$0.09094105
91
$0.07903074
00
$0.003915
1
$0.168451
8885
Winter Period
0.064170752
0
0.053564677
0.0039151
0.1144513
467
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL
GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-2 dated 7-1-20164 Sheet No E-2-G-2
Minimum Bill ($/day)
0.7328657
Palo Alto Green Charge (per 1000 kWh block) $2.00
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. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use in both the Summer
and Winter Periods, usage will be prorated based upon the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewable
sources, and create a transparent and sustainable market that encourages new
development of wind and solar power.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIALCOMMERCIAL
GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-2-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-2-G-3 dated 7-1-20164 Sheet No E-2-G-3
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a maximum Demand Meter will be installed as promptly as is practicable and
thereafter continued in service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that ifin case the Customer-s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand Meter which does not reset after a definite time
interval may be used at the City's option.
The billing Demand to be used in computing charges under this schedule will be the
actual maximum Demand in kilowatts for the current month. An exception is that the
billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-1 dated 27-51-20136 Sheet No E-4-1
A. APPLICABILITY:
This schedule applies to Demand metered secondary Electric Service for customers with a
Maximum Demand below 1,000 kilowatts. This schedule applies to three-phase Electric
Service and may include Service to master-metered multi-family facilities or other facilities
requiring Demand-metered services, as determined by the City.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $2.533.38 $17.1467 $19.6821.05
Energy Charge (per kWh)
0.0821809526 0.0166101756 0.0035100391 0.1022911673
Winter Period
Demand Charge (per kW) $1.9355 $12.4913.43 $14.0415.36
Energy Charge (per kWh)
0.0603706743 0.016610176 0.0035100391 0.0804908890
Minimum Bill ($/day) 16.321614.8414
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.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-2 dated 27-51-20136 Sheet No E-4-2
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive
months, a Maximum Demand meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kWh for twelve consecutive months, whereupon, at the option of the City, it may be
removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that if in case the Customer-s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand meter which does not reset after a definite time interval
may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such customers between the hours of noon and 6 pm on
weekdays.
4. Power Factor
For new or existing customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
metering to calculate a Power Factor. The City may remove such metering from the
Service of a customer whose Demand has been below 200 kilowatts for four consecutive
months.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-3 dated 27-51-20136 Sheet No E-4-3
When such metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the
customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day metering
is installed, the monthly Power Factor shall be the Power Factor coincident with the
customer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any City of Palo Alto full-
service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage
profile.
6. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the customer's electrical requirements, as determined in the
City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any customer receiving a the discount in this
sectionhereunder and affected by such change. The customer then has the option to
change his system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-4 dated 27-51-20136 Sheet No E-4-4
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-5 dated 27-51-20136 Sheet No E-4-5
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-1 dated 7-1-20164 Sheet No E-4-G-1
A. APPLICABILITY:
This schedule applies to Demand Metered Secondary Electric Service for Customers with a
Maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green
Program. This schedule applies to three-phase Electric Service and may include Service to
Master-metered multi-family facilities or other facilities requiring Demand-Metered Services, as
determined by the City.
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES: 1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge (per kW) $2.533.38 $17.6714
$19.6821.05
Energy Charge (per kWh)
0.0821809526 0.01756661 0.0039151 0.0020
0.118730429
Winter Period
Demand Charge (per kW) $1.5593 $12.4913.43
$15.3614.04
Energy Charge (per kWh)
0.0603706743 0.01756661 0.0039151 0.0020
0.090908249
Minimum Bill ($/day) 16.321614.8414
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-2 dated 7-1-20164 Sheet No E-4-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.382.53 $17.6714 $21.0519.68
Energy Charge (per kWh) 0.095268218 0.01756661 0.0039151 0.116730229
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.9355 $12.4913.43 $15.3614.04
Energy Charge (per kWh) 0.06743037 0.01756661 0.0039151 0.08890049
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 14.841416.3216
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. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-3 dated 7-1-20164 Sheet No E-4-G-3
option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case if the Customer’s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand Meter, which does not reset after a definite time
interval, may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill will include a “Power Factor
Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
5. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full-service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-4 dated 7-1-20164 Sheet No E-4-G-4
6. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the Customer's electrical requirements, as determined in the
City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any Customer receiving a the discount in
this sectionhereunder and affected by such change. The Customer then has the option to
change the system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
MEDIUM NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-4-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-G-5 dated 7-1-20164 Sheet No E-4-G-5
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-1 dated 27-51-20136 Sheet No E-4-TOU-1
A. APPLICABILITY:
This voluntary rate schedule applies to Demand metered secondary Electric Service for
customers with Demand between 500 and 1,000 kilowatts per month and who have sustained
this level of usage for at least three consecutive months during the most recent 12 month period.
This schedule applies to three-phase Electric Service and may include Service to master-
metered multi-family facilities or other facilities requiring Demand-metered services, as
determined by the City. In addition, this rate schedule is applicable for customers who did not
pay Power Factor Adjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.121.52 $6.095.91 $8.217.42
Mid-Peak 0.6654 6.095.91 6.7644
Off-Peak 0.6654 6.095.91 6.7644
Energy Charge (per kWh)
Peak $0.1014408819 $0.01756661 $0.0039151 $0.122910830
Mid-Peak 0.098358367 0.01756661 0.0039151 0.119820378
Off-Peak 0.087487332 0.01756661 0.0039151 0.1089509344
Winter Period
Demand Charge (per kW)
Peak $1.070.87 $7.496.96 $8.567.83
Off-Peak 1.070.87 7.496.96 8.567.83
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-2 dated 27-51-20136 Sheet No E-4-TOU-2
Commodity Distribution Public Benefits Total
Energy Charge (per kWh)
Peak $0.081646566 $0.01756661 $0.0039151 $0.1031108577
Off-Peak 0.057386167 0.01756661 $0.0039151 0.078858178
Minimum Bill ($/day) 16.321614.8414
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. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Years Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day,
Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays
are legally observed.
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-3 dated 27-51-20136 Sheet No E-4-TOU-3
SEASONAL RATE CHANGES: When the billing period includes use in both the
Summer and the Winter periods, the usage will be prorated based on the number of days
in each seasonal period, and the charges based on the applicable rates therein.. For
further discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Demand meter will be installed as promptly as is practicable and
thereafter continued in Service until the monthly use of energy has fallen below 6,000
kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it
may be removed.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the
designated Time periods as defined under Section D.2.
4. Power Factor Adjustment
Time of Use customers must not have had a Power Factor Adjustment assessed on their
Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month, and must not have fallen
below 95% to avoid the Power Factor Adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should
be subject to Power Factor Adjustments, the Customer will be removed from the E-4-
TOU rate schedule and placed on another applicable rate schedule as is suitable to their
kilowatt Demand and kilowatt-hour usage.
5. Changing Rate Schedules
Customers electing to be served under E-4 TOU must remain on said schedule for a
minimum of 12 months. Should the Customer so wish, at the end of 12 months, the
Customer may request a rate schedule change to any applicable City of Palo Alto full-
service rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage.
6. Primary Voltage Discount
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-4 dated 27-51-20136 Sheet No E-4-TOU-4
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the Customer's electrical requirements, as determined in the
City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any Customer receiving a the discount in
this sectionhereunder and affected by such change. The Customer then has the option to
change his system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
7. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(7)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.69 $15.23 $15.92
Winter Period $0.63 $9.04 $9.67
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more
of the non-utility generators on the Customer’s side of the City’s revenue meter
are not operating, the Maximum Demand will be reduced by the sum of the
Maximum Generation of those non-utility generators, but in no event shall the
Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
MEDIUM NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-4 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-4-TOU-5 dated 27-51-20136 Sheet No E-4-TOU-5
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-1 dated 27-51-20163 Sheet No E-7-1
A. APPLICABILITY:
This schedule applies to Demand metered secondary Service for non-residentialcommercial
Customers with a Maximum Demand of at least 1,000KW per month per site, who have
sustained this Demand level at least 3 consecutive months during the last twelve months.
B. TERRITORY:
This rate schedule applies anywhere the City of Palo Alto provides Electric Service.
C. RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (kWh) 0.093538311 0.0005887 0.0039151 0.098028749
Winter Period
Demand Charge (kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (kWh) 0.067395804 0.0005887 0.0039151 0.071886242
Minimum Bill ($/day) 42.364848.5054
D. SPECIAL NOTES:
1. Calculation of Charges
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.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-2 dated 27-51-20163 Sheet No E-7-2
2. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the summer
and in the winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Request for Service
Qualifying Customers may request Service under this schedule for more than one account
or one meter if the accounts are on one site. A site shall be defined as one or more utility
accounts serving contiguous parcels of land with no intervening public right-of-ways
(e.g. streets) and have a common billing address.
4. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has fallen
below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of
the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month provided that in case if the Customer’s
load is intermittent or subject to violent fluctuations, the City may use a 5-minute
interval. A thermal-type Demand meter which does not reset after a definite time interval
may be used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 pm on
weekdays.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-3 dated 27-51-20163 Sheet No E-7-3
5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option to install applicable
metering to calculate a Power Factor. The City may remove such metering from the
Service of a Customer whose Demand has been below 200 kilowatts for four consecutive
months.
When such metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent (0.25%) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt
hours to kilovolt-ampere hours consumed during the month. Where time-of-day metering
is installed, the monthly Power Factor shall be the Power Factor coincident with the
Customer's Maximum Demand.
6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile.
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered,allowed provided but the City is not required to supply Service at a particular line
voltage where it has, or will install, ample facilities for supplying at another voltage
equally or better suited to the Customer's electrical requirements , as determined in the
City’s sole discretion. The City retains the right to change its line voltage at any time
after providing reasonable advance notice to any Customer receiving a the discount in
this section hereunder and affected by such change. The Customer then has the option to
change his system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kVA size limitation.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-4 dated 27-51-20163 Sheet No E-7-4
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection
D(8)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.4) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-5 dated 27-51-20163 Sheet No E-7-5
Section 2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
{End}
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-1 dated 7-1-20164 Sheet No E-7-G-1
A. APPLICABILITY:
This schedule applies to Demand Metered Service for large non-residentialcommercial
Customers who choose Service under the Palo Alto Green Program. A Customer may qualify
for this rate schedule if the Customer’s Maximum Demand is at least 1,000KW per month per
site, who have sustained this Demand level at least 3 consecutive months during the last twelve
months
B. TERRITORY:
The rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
1. 100% Renewable Option:
Commodity Distribution Public Benefits
Palo Alto Green Charge Total
Summer Period
Demand Charge ( per kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (per kWh) 0.093538311 0.0005887 0.0039151 0.0020 0.1000208949
Winter Period
Demand Charge (per kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (per kWh) 0.067395804 0.0005887 0.0039151 0.0020 0.073886442
Minimum Bill ($/day) 42.364848.5054
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-2 dated 7-1-20164 Sheet No E-7-G-2
2. 1000 kWh Block Purchase Option:
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW) $3.492.50 $20.3515.85 $23.8418.34
Energy Charge (per kWh) 0.093538311 0.0005887 0.0039151 0.098028749
Palo Alto Green Charge (per 1000 kWh block) $2.00
Winter Period
Demand Charge (per kW) $1.9053 $13.6914.11 $15.5965
Energy Charge (per kWh) 0.067395804 0.0005887 0.0039151 0.071886242
Palo Alto Green Charge (per 1000 kWh block) $2.00
Minimum Bill ($/day) 42.364848.5054
D. SPECIAL NOTES:
1. Calculation of Charges
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. Seasonal Rate Changes
The Summer Period is effective May 1 to October 31 and the Winter Period is effective
from November 1 to April 30. When the billing period includes use both in the Summer
and the Winter Periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates therein. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Maximum Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three
consecutive months, a Maximum Demand Meter will be installed as promptly as is
practicable and thereafter continued in Service until the monthly use of energy has
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-3 dated 7-1-20164 Sheet No E-7-G-3
dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the
option of the City, it may be removed.
The Maximum Demand in any month will be the maximum average power in kilowatts
taken during any 15-minute interval in the month, provided that in case if the load is
intermittent or subject to violent fluctuations, the City may use a 5-minute interval. A
thermal-type Demand Meter which does not reset after a definite time interval may be
used at the City's option.
The Billing Demand to be used in computing charges under this schedule will be the
actual Maximum Demand in kilowatts for the current month. An exception is that the
Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon
the actual Maximum Demand of such Customers between the hours of noon and 6 PM on
weekdays.
4. Request for Service
Qualifying Customers may request Service under this schedule for more than one
Account or one Meter if the Accounts are at one site. A site shall be defined as one or
more utility Accounts serving contiguous parcels of land with no intervening public right-
of-ways (e.g. streets) and have a common billing address.
5. Power Factor
For new or existing Customers whose Demand is expected to exceed or has exceeded 300
kilowatts for three consecutive months, the City has the option of installing applicable
Metering to calculate a Power Factor. The City may remove such Metering from the
Service of a Customer whose Demand has dropped below 200 kilowatts for four
consecutive months.
When such Metering is installed, the monthly Electric bill shall include a “Power Factor
Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to
the computation of any primary voltage discount. The Power Factor Adjustment is
applied by increasing the total energy and Demand charges for any month by 0.25
percent or (1/4) for each one percent (1%) that the monthly Power Factor of the
Customer’s load was less than 95%.
The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-
hours to kilovolt-ampere hours consumed during the month. Where time-of-day
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-4 dated 7-1-20164 Sheet No E-7-G-4
Metering is installed, the monthly Power Factor shall be the Power Factor coincident with
the Customer's Maximum Demand.
6. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable full service
rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile
7. Palo Alto Green Program Description and Participation
Palo Alto Green provides for either the purchase of enough renewable energy credits
(RECs) to match 100% of the energy usage at the facility every month, or for the
purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the
production of renewable energy, increase the financial value of power from renewal
sources, and creates a transparent and sustainable market that encourages new
development of wind and solar.
Customers choosing to participate shall fill out a Palo Alto Green Power Program
application provided by the Customer Service Center. Customers may request at any
time, in writing, a change to the number of blocks they wish to purchase under the Palo
Alto Green Program.
8. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be
offered, butallowed; provided, however, the City is not required to supply Service at a
qualified line voltage where it has, or will install, ample facilities for supplying at another
voltage equally or better suited to the Customer's Electrical requirements , as determined
in the City’s sole discretion. The City retains the right to change its line voltage at any
time after providing reasonable advance notice to any Customer receiving a the discount
in this section hereunder and affected by such change. The Customer then has the option
to change the system so as to receive Service at the new line voltage or to accept Service
(without voltage discount) through transformers to be supplied by the City subject to a
maximum kilovolt-ampere size limitation.
9. Standby Charge
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-5 dated 7-1-20164 Sheet No E-7-G-5
a. Applicability: The standby charge, subject to the exemptions in subsection
D(9)(e), applies to Customers that have a non-utility generation source
interconnected on the Customer’s side of the City’s revenue Meter and that
occasionally require backup power from the City due to non-operation of the non-
utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76
c. Meters: A separate Meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit:
(1) In the event the Customer’s Maximum Demand (as defined in Section
D.3) occurs when one or more of the non-utility generators on the Customer’s
side of the City’s revenue Meter are not operating, the Maximum Demand will be
reduced by the sum of the Maximum Generation of those non-utility generators,
but in no event shall the Customer’s Maximum Demand be reduced below zero.
(2) If the non-utility generation source does not operate for an entire billing
cycle, the standby charge does not apply and the Customer shall not receive the
Maximum Demand credit described in this Section.
e. Exemptions:
(1) The standby charge shall not apply to backup generators designed to operate
only in the event of an interruption in utility Service and which are not used to
offset Customer electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code
Section 2827(b)(4), as amended.
(3) The applicability of these exemptions shall be determined at the discretion of
the Utilities Director.
LARGE NON-RESIDENTIALCOMMERCIAL GREEN POWER ELECTRIC SERVICE
UTILITY RATE SCHEDULE E-7-G
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No E-7-G-6 dated 7-1-20164 Sheet No E-7-G-6
{End}
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-1 dated 72-15-20163 Sheet No E-7-TOU-1
A. APPLICABILITY:
This voluntary rate schedule applies to Demand metered secondary Service for non-
residentialcommercial customers with a Maximum Demand of at least 1,000KW per month per
site, who have sustained this Demand level at least 3 consecutive months during the last twelve
months. In addition, this rate schedule is applicable for customers who did not pay Power
Factor Adjustments during the last 12 months.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Rates per kilowatt (kW) and kilowatt-hour (kWh):
Commodity Distribution Public Benefits Total
Summer Period
Demand Charge (per kW)
Peak $2.221.48 $6.845.33 $9.066.80
Mid-Peak 0.6451 6.845.33 7.485.84
Off-Peak 0.6451 6.845.33 7.485.84
Energy Charge (per kWh)
Peak $0.1017709267 $0.0005887 $0.0039151 $0.1062609705
Mid-Peak 0.098688792 0.0005887 0.0039151 0.1031609230
Off-Peak 0.087777705 0.0005887 0.0039151 0.092268143
Winter Period
Demand Charge (per kW)
Peak $0.9678 $6.937.15 $7.892
Off-Peak 0.9678 6.937.15 7.892
Energy Charge (per kWh)
Peak $0.080366009 $0.0005887 $0.0039151 $0.084846447
Off-Peak 0.056473 0.0005887 0.0039151 0.0609681
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-2 dated 72-15-20163 Sheet No E-7-TOU-2
Minimum Bill ($/day) 42.364848.5054
D. SPECIAL NOTES:
1. Calculation of Charges
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. Definition of Time Periods
SUMMER PERIOD (Service from May 1 to October 31):
Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)
Mid Peak: 8:00 a.m. to 12:00 noon Monday through Friday (except holidays)
6:00 p.m. to 9:00 p.m.
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday
All day Saturday, Sunday, and holidays
WINTER PERIOD (Service from November 1 to April 30):
Peak: 8:00 a.m. to 9:00 p.m. Monday through Friday (except holidays)
Off-Peak: 9:00 p.m. to 8:00 a.m. Monday through Friday (except holidays)
All day Saturday, Sunday, and holidays
HOLIDAYS: “Holidays” for the purposes of this rate schedule are New Year’s Day,
President’s Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving
Day, and Christmas Day. The dates will be those on which the holidays are legally observed.
SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and
the Winter periods, the usage will be prorated based on the number of days in each seasonal
period, and the charges based on the applicable rates therein. For further discussion of bill
calculation and proration, refer to Rule and Regulation 11.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-3 dated 72-15-20163 Sheet No E-7-TOU-3
3. Request for Service
Qualifying customers may request Service under this schedule for more than one account or one
meter if the accounts are on one site. A site shall be defined as one or more utility accounts
serving contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and
have a common billing address.
4. Demand Meter
Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive
months, a Demand meter will be installed as promptly as is practicable and thereafter continued
in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve
consecutive months, whereupon, at the option of the City, it may be removed.
The Billing Demand to be used in computing charges under this schedule will be the actual
Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated
Time periods as defined under Section D.2.
5. Power Factor Adjustment
Time of Use customers must not have had a Power Factor Adjustment assessed on their Service
for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt-
ampere hours consumed during the month, and must not have fallen below 95% to avoid the
Power Factor Adjustment.
Should the City of Palo Alto Utilities Department find that the Customer’s Service should be
subject to Power Factor Adjustments, the Customer will be removed from the E-7-TOU rate
schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand
and kilowatt-hour usage.
6. Changing Rate Schedules
Customers electing to be served under E-7 TOU must remain on said schedule for a minimum of
12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a
rate schedule change to any applicable City of Palo Alto full-service rate schedule as is suitable
to their kilowatt Demand and kilowatt-hour usage.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-4 dated 72-15-20163 Sheet No E-7-TOU-4
7. Primary Voltage Discount
Where delivery is made at the same voltage as that of the line from which the Service is
supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered,
butallowed provided the City is not required to supply Service at a particular line voltage where
it has, or will install, ample facilities for supplying at another voltage equally or better suited to
the Customer's electrical requirements , as determined in the City’s sole discretion. The City
retains the right to change its line voltage at any time after providing reasonable advance notice
to any Customer receiving a the discount in this section hereunder and affected by such change.
The Customer then has the option to change his system so as to receive Service at the new line
voltage or to accept Service (without voltage discount) through transformers to be supplied by
the City subject to a maximum kilovolt-ampere size limitation.
8. Standby Charge
a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e),
applies to Customers that have a non-utility generation source interconnected on the
Customer’s side of the City’s revenue meter and that occasionally require backup power
from the City due to non-operation of the non-utility generation source.
b. Standby Charges:
Commodity Distribution Total Standby Charge (per kW of Reserved Capacity)
Summer Period $0.84 $12.55 $13.39
Winter Period $0.72 $6.04 $6.76
c. Meters. A separate meter is required for each non-utility generation source.
d. Calculation of Maximum Demand Credit.
(1) In the event the Customer’s Maximum Demand occurs when one or more of the
non-utility generators on the Customer’s side of the City’s revenue meter are not
operating, the Maximum Demand will be reduced by the sum of the Maximum
Generation of those non-utility generators, but in no event shall the Customer’s
Maximum Demand be reduced below zero.
LARGE NON-RESIDENTIALCOMMERCIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-7 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No E-7-TOU-5 dated 72-15-20163 Sheet No E-7-TOU-5
(2) If the non-utility generation source does not operate for an entire billing cycle, the
standby charge does not apply and the Customer shall not receive the Maximum Demand
credit described in this Section.
e. Exemptions.
(1) The standby charge shall not apply to backup generators designed to operate only in
the event of an interruption in utility Service and which are not used to offset Customer
electricity purchases.
(2) The standby charge shall not apply if the Customer meets the definition of an
“Eligible Customer-generator” as defined in California Public Utilities Code Section
2827(b)(4) , as amended.
(3) The applicability of these exemptions shall be determined at the discretion of the
Utilities Director.
{End}
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No. E-14-2 dated 7-1-200916 Sheet No. E-14-2
A. APPLICABILITY:
This schedule applies to all street and highway lighting installations.
B. TERRITORY:
Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City.
C. RATES:
Per Lamp Per Month
Class A: Utility supplies energy
and switching service only.
Lamp Rating:
High Pressure Sodium Vapor Lamps
100 watts 8.599.66
200 watts 15.8717.83
250 watts 19.5021.92
310 watts 24.1327.12
400 watts 31.0734.92
STREET LIGHTS
UTILITY RATE SCHEDULE E-14
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20167
Supersedes Sheet No. E-14-2 dated 7-1-200916 Sheet No. E-14-2
Per Lamp Per Month –
Class C: Utility supplies energy
and switching service and
maintains entire system,
including lamps and glassware.
Lamp Rating:
Mercury-Vapor Lamps
400 watts 32.5834.94
High Pressure Sodium Vapor Lamps
70 watts 28.6130.48
100 watts 30.7932.93
150 watts 34.4337.02
250 watts 41.7045.19
Light Emitting Diode (LED) Lamps
70 watts-equivalent 23.7925.06
100 watts-equivalent 25.4426.91
150 watts-equivalent 26.9628.62
250 watts 31.1233.30
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No. E-14-14 dated 7-1-200916 Sheet No. E-14-14
D. SPECIAL CONDITIONS:
1. Type of Service: This schedule is applicable to series circuit and multiple street lighting
systems to which the Utility will deliver current at secondary voltage. Unless otherwise
agreed, multiple current will be delivered at 120/240 volts, three-wire, single-phase. In
certain localities the Utility may supply service from 120/208 volt star-connected poly-phase
lines in place of 240-volt service. Single phase service from 480-volt sources will be
available in certain areas at the option of the Utility when this type of service is practical
from the Utility's engineering standpoint. All currents and voltages stated herein are
nominal, reasonable variations being permitted. New lights will normally be supplied as
multiple systems.
2. Point of Delivery: Delivery will be made to the customer's system at a point or at points
mutually agreed upon. The Utility will furnish the service connection to one point for each
group of lamps, provided the customer has arranged his system for the least practicable
number of points of delivery. All underground connections will be made by the customer or
at the customer's expense.
3. Switching: Switching will be performed by the Utility (on the Utility's side of points of
delivery) and no charge will be made for switching provided there are at least 10 kilowatts of
lamp load on each circuit separately switched, including all lamps on the circuit whether
served under this schedule or not; otherwise, an extra charge of $2.50 per month will be
made for each circuit separately switched unless such switching installation is made for the
Utility's convenience or the customer furnishes the switching facilities and, if installed on the
Utility's equipment, reimburses the Utility for installing and maintaining them.
4. Annual Burning Schedule: The above rates apply to lamps which will be turned on and off
once each night in accordance with a regular burning schedule agreeable to the customer but
not exceeding 4,100 hours per year.
5. Maintenance: The rates under Class C include all labor necessary for replacement of
glassware and for inspection and cleaning of the same. Maintenance of glassware by the
Utility is limited to standard glassware such as is commonly used and manufactured in
reasonably large quantities. A suitable charge will be made for maintenance of glassware of a
type entailing unusual expense. Under Class C, the rates include maintenance of circuits
between lamp posts and of circuits and equipment in and on the posts, provided these are all
of good standard construction; otherwise, the Utility may decline to grant Class C rates.
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Effective 7-1-20176
Supersedes Sheet No. E-14-24 dated 7-1-200916 Sheet No. E-14-24
Class C rates applied to any agency other than the City of Palo Alto also include painting of
posts with one coat of good ordinary paint as required to maintain good appearance but do
not include replacement of posts broken by traffic accidents or otherwise.
10. . System Owned In-Part by Utility : Where, at customer's request, the Utility installs, owns,
and maintains any portion of the lighting fixtures, supports, and/or interconnecting circuits,
an extra monthly charge of one and one-fourth percent of the Utility's estimate of additional
investment shall be made.
11. Rates For Lamps Not on Schedule: In the event a customer installs a lamp which is not
presently represented on this schedule, the Utility will prepare an interim rate reflecting the
Utility's estimated costs associated with the specific lamp size. This interim rate will serve as
the effective rate for billing purposes until the new lamp rating is added to Schedule E-14.
{End}