HomeMy WebLinkAbout2015-04-01 Utilities Advisory Commission Agenda Packet
NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I. ROLL CALL
II. ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable
time restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from
discussing or acting upon any topic initially presented during oral communication.
III. APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Meeting held on March 4, 2015
IV. AGENDA REVIEW AND REVISIONS
V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI. DIRECTOR OF UTILITIES REPORT
VII. UNFINISHED BUSINESS
None.
VIII. NEW BUSINESS
1. Sustainability/Climate Action Plan Update and Implication for the City of Palo Alto Presentation
Utilities Long Range Planning
2. Update on Fiber-to-the Premise (FTTP) Master Plan Presentation
3. Staff Recommendation that the Utilities Advisory Commission Recommend that Action
the City Council Adopt a Resolution Identifying Projects to be Funded by the Electric
Special Project Reserve
4. Staff Recommendation that the Utilities Advisory Commission Recommend that Action
the City Council Adopt a Resolution Approving the Fiscal Year 2016 Gas Financial
Plan, Including no Recommended Rate Changes for July 1, 2015, and Amending
the Gas Utility Reserve Management Practices
5. Staff Recommendation that the Utilities Advisory Commission Recommend that Action
the City Council Adopt a Resolution Approving the Fiscal Year 2016 Electric
Financial Plan, Including no Recommended Rate Changes for July 1, 2015, and
Amending the Electric Utility Reserve Management Practices
6. Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
7. Update and Discussion on Impacts of Statewide Drought on Water and Discussion
Hydroelectric Supplies
IX. COMMISSIONER COMMENTS
X. NEXT SCHEDULED MEETING: May 6, 2015 – Special Daytime Meeting
UTILITIES ADVISORY COMMISSION
WEDNESDAY, APRIL 1, 2015 – 7:00 P.M.
COUNCIL CHAMBERS
Palo Alto City Hall – 250 Hamilton Avenue
Chairman: Jonathan Foster Vice Chair: Asher Waldfogel Commissioners: Audrey Chang, James F. Cook, Steve Eglash, Garth Hall, and John Melton Council Liaison: Gregory Scharff
Utilities Advisory Commission Minutes Approved on: Page 1 of 11
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MARCH 4, 2015
CALL TO ORDER
Chair Foster called to order at 7:03 p.m. the meeting of the Utilities Advisory Commission
(UAC).
Present: Commissioners Chang, Eglash, Hall, Melton, Chair Foster, Vice Chair Waldfogel, and
Council Liaison Scharff
Absent: Commissioner Cook
Note that Commissioner Hall excused himself and left the meeting at 8:48 p.m., just after the
discussion of Item #5 (Wastewater Collection Financial Plan) and before the UAC returned to
discuss the water-related portion of Item #1 (Strategic Plan Updates).
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Commissioner Eglash moved to approve the minutes from the February 4, 2015 UAC meeting as
presented and Commissioner Melton seconded the motion. The motion carried unanimously
(6-0 with Chair Foster, Commissioners Chang, Eglash, Melton and Vice Chair Waldfogel voting
yes, Commissioner Hall voting yes for all except the water-related items and abstaining for
those items, and Commissioner Cook absent).
AGENDA REVIEW AND REVISIONS
Chair Foster announced that the water-related items of New Business Item #1 (Utilities
Strategic Plan Updates) would be discussed after the Commission discussed New Business Items
2, 3, 4, and 5 to allow Commissioner Hall to leave the meeting after Item 5 (Wastewater
Collection Financial Plan) to avoid participating in the discussion or actions related to water.
REPORTS FROM COMMISSION MEETING/EVENTS
None.
UTILITIES DIRECTOR REPORT
1. Community Solar Program - In order to address feedback from the UAC at its December
2014 meeting, staff continues to work on an in-depth risk assessment concurrently with the
negotiation of the program agreements. Given that any identified risks could only be
DRAFT
Utilities Advisory Commission Minutes Approved on: Page 2 of 11
effectively mitigated through specific measures incorporated into the program agreements,
the risk assessment and negotiations are inter-dependent and must be completed in
concert. Staff will complete the risk assessment once the program agreements are in
substantial form and plan to return to the UAC in June 2015 with a new recommendation
on the program.
2. Marketing Services Update
The City entered into a one-year partnership agreement with the Palo Alto Medical
Foundation (PAMF) to support PAMF’s linkAgesTM TimeBank program. The program
matches Palo Alto residents (especially senior citizens) who are interested in receiving
energy efficiency and waste reduction services with volunteers who can provide these
services. The City will coordinate quarterly training for volu nteers and help publicize the
program. There is no monetary exchange between PAMF and the City. Look for
information on the program in the March utility bills.
City facilities will subscribe to PaloAltoGreen Gas to offset 100% of the greenhouse gas
emissions associated with facilities’ natural gas use. This will reduce the greenhouse gas
emissions related to municipal operations by about 25%. Since mid -February, about 800
customers have signed up for PaloAltoGreen Gas, including Mitchell Park Library, the
International School of the Peninsula and Pete Moffat Construction.
3. Communication Updates
CPAU Scores Top Marks for Customer Satisfaction – In a nationwide survey conducted
by leading utility energy efficiency research group, E Source, CPAU ranked number three
for large business customer satisfaction. This is the fourth year in a row CPAU has
finished in a top three ranking. Large business customers were particularly pleased with
their account representatives’ effective communication skills and customer ser vice.
Construction Begins on New Solar Farm - Developers of the Hayworth Solar Farm,
8minutenergy and sPower, announced in February that construction began on the
project in Kern County, which will be fully operational later this summer. The Hayworth
project is one of five large-scale solar projects that CPAU has entered into a Power
Purchase Agreement to supply almost one-third of the City’s electricity supplies.
Hayworth will provide about 6% of the City’s total electric supplies, adding to Palo Alto’s
existing carbon neutral energy portfolio.
Mayor’s “Green Leader” Business Awards –Mayor Karen Holman honored four
businesses with the Mayor’s “Green Leader” Business Award for their leadership in
energy efficient building management. Palo Alto businesses that benchmark building
energy consumption through EPA’s Portfolio Manager and receive a high ENERGY STAR
rating are eligible for an award. For the past 12 months, six buildings totaling over a half
million square feet of office space qualified for the award.
City Launches Commercial Benchmarking Pilot Program with GreenTraks – In February,
CPAU announced its multi-year agreement with GreenTraks to provide energy and
sustainability benchmarking services for CPAU customers, including City facilities.
Participating businesses will receive free services from the City to assist in their
benchmarking efforts and earn ENERGY STAR ratings. Concluding the pilot program,
Utilities Advisory Commission Minutes Approved on: Page 3 of 11
CPAU will use this information to identify and measure the performance of a portfolio of
energy efficiency projects within the City.
4. Community Outreach Events and Workshops
Arbor Day Festival –March 8 -CPAU will table at this festival in partnership with the
City’s Urban Forestry Division of the Public Works Department and non -profit, Canopy.
Earth “Month” Events – Utilities is collaborating with other City Departments to
promote environmental education workshops, events and activities centered around
Earth Day, April 22. During the month of March, residents and business utility customers
will receive a bill insert listing a number of events available in Palo Alto on or around
Earth Day. Find full details at cityofpaloalto.org/workshops
5. Utilities Organizational Changes
Utilities is instituting organizational changes as follows:
1. Tomm Marshall and Dean Batchelor will swap jobs temporarily until the end -of-the-year
to better identify process changes to improve efficiency between the Operations and
Engineering staff.
2. Jane Ratchye has agreed to incorporate the Utilities Marketing Services team into the
Resource Management team, which manages our rebate, efficiency and green
programs, to ensure a comprehensive portfolio approach to our resource portfolio.
3. Senior Management Analyst Dave Yuan has accepted a promotion to the Utilities
Strategic Business Manager position. Mr. Yuan will have oversight over the Utilities
budget, IT Strategy efforts (including the Utility billing team), the Fiber Optics policy
development, succession planning efforts and workforce development, and
coordination of our responses to internal performance audits.
Chair Foster asked about the linkAgesTM TimeBank program. Communications Manager
Catherine Elvert described the program and explained that the program was developed by the
Palo Alto Medical Foundation (PAMF) to allow community members to trade expertise and time
with others in the community. Chair Foster suggested that broad advertisement of the
program would be helpful to ensure success.
UNFINISHED BUSINESS
None.
NEW BUSINESS
ITEM 1: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that Council Approve Changes to the Utilities Strategic Plan and Receive the Six Month Utilities
Strategic Plan Performance Update (July through December 2014)
Senior Management Analyst Dave Yuan summarized the written r eport on the updates to the
Utilities Strategic Plan. He noted that the performance measures for the July-December 2014
period focusing on the five measures that have not yet been met.
Commissioner Eglash asked Yuan to expand on the employee satisfaction scores and why they
did not meet expectations. Yuan stated that 62% of the employees reported being satisfied.
Utilities Advisory Commission Minutes Approved on: Page 4 of 11
He added that, if the responses of “neutral” were included, then the number would increase to
80%. Commissioner Eglash said that this seemed like a low number. Yuan explained that the
scores fell from last year and that it may have to do with dissatisfaction with compensation,
which is based on City policies and not totally under the control of Utilities. Commissioner
Eglash suggested using the survey results as an opportunity to follow up with HR to address
some of the employees’ concerns. Director Valerie Fong stated that the survey feedback
indicated that there was a concern about communications between the divisions which is why
the department is making some organizational changes. Another theme is employees did not
feel recognized which is an actionable item and that the department is focusing on expanding
efforts to recognize employees.
Vice Chair Waldfogel asked if the low satisfaction has been reflected in an increase in
departures for other agencies. Fong replied that there have been some departures.
Council Member Scharff noted that the lack of IT equipment was a problem and asked for an
explanation. Director Fong explained that the IT department has to provide equipment to the
entire City and it takes time for a City our size. She added that IT will also hire contractors to
speed the deployment of equipment.
Council Member Scharff noted that 50% responded to the survey and that the most satisfied or
most unsatisfied people may be more represented in respondents. He asked if we compare the
results with other agencies. Director Fong responded that she doesn't know what other
agencies have found with respect to employee satisfac tion. She added that, instead, she
focuses on the trends in our results over time.
Yuan explained the proposed changes to the strategic objectives, performance measures, and
strategic initiatives.
Commissioner Hall asked if the reason for changing the strategic initiative F3 (to evaluate the
appropriate fraction of fixed costs that should be collected by fixed charges versus volumetric
charges) is due to the plan to address these by completing cost of service analyses. Yuan
confirmed that this is the reason.
Commissioner Melton stated that he felt that strategic objective F4 (equity transfer to the
General Fund) is an important management measurement and should not be removed from the
Strategic Plan. Senior Deputy City Attorney Jessica Mullan stated that there is no discretionary
action with respect to the equity transfer and that removing it from the Strategic Plan changes
nothing as to the transfer and how it is calculated. Council Member Scharff added that there is
a legal issue and that, as a strategic initiative, it has the appearance of being discretionary, but
there's nothing discretionary and nothing strategic so he supports removing it from the
strategic plan as staff proposed.
With respect to the strategic objective associated with objective BP7 (participate in electric cost
allocation studies), Vice Chair Waldfogel asked if there are opportunities to partner with other
agencies to share cost with respect to regulatory compliance and if a strategic initiative should
Utilities Advisory Commission Minutes Approved on: Page 5 of 11
be added to find if there are any inter-agency cooperation alternatives that could be pursued.
Director Fong said that Utilities does not have the capacity to manage this as an initiative but
Utilities will partner with other agencies when opportunities arise. Utilities has inter agency
cooperation through various memberships with Northern California Power Agency (NCPA),
California Municipal Utilities Association (CMUA), and American Public Power Association
(APPA).
Commissioner Hall asked how long the City has followed the balanced scorecard method. Yuan
said since 2010 when the Strategic Plan was adopted. Co mmissioner Hall stated that he
supports the balanced scorecard method and said this in his experience, it is not always
followed through on and that in some cases, the objec tives could be more specific with respect
to dates and deliverables.
Commissioner Eglash stated that the goal for electrification is to study, not to go forward yet in
a particular direction. He noted that smart grid is another case where the direction is not yet
known and is awaiting more study. Commissioner Eglash added that the Strategic Plan really
matters and that he is glad to see Utilities taking it seriously.
Commissioner Eglash suggested that the performance measure target for PT1 (employee
satisfaction improvement from baseline level) could be changed to improve employee
satisfaction every year, not just from the fixed baseline. He suggested that this change would
give management a tool to measure itself.
ACTION:
Chair Foster made a motion to support the staff recommendation on all non-water related
items in the strategic plan with a change to the performance target for PT1 from “improvement
from baseline level” to “annual improvement”. Commissioner Eglash seconded the motion.
The motion carried unanimously (6-0 with Chair Foster, Commissioners Chang, Eglash, Hall,
Melton and Vice Chair Waldfogel voting yes, and Commissioner Cook absent).
The UAC returned to complete the water-related parts of this item after Commissioner Hall
departed from the meeting.
Yuan summarized the new strategic initiatives related to water (BP1, BP3, BP8, BP11, and BP
12).
Commissioner Melton asked about the new strategic initiative BP2. Yuan said that it was to
update the Water Integrated Resource Plan and will evaluate the advisability of expanding the
use of groundwater as a water supply source.
Commissioner Eglash asked if the Strategic Plan, especially the proposed strategic initiative
BP12 related to updating the Urban Water Management Plan (UWMP) should include long-
term initiatives due to the impact of climate change such as the impact on facilities due to rising
sea levels. Director Fong noted at the Sustainability/Climate Action Plan (S/CAP) will address
Utilities Advisory Commission Minutes Approved on: Page 6 of 11
those issues. She noted that the Chief Sustainability Officer will provide an update on the
S/CAP at the UAC’s April meeting.
ACTION:
Chair Foster made a motion to support the staff recommendation with respect to the water
related items. Commissioner Eglash seconded the motion. The motion carried unanimously (5-
0 with Chair Foster, Commissioners Chang, Eglash, Melton and Vice Chair Waldfogel voting yes,
and Commissioners Cook and Hall absent).
ITEM 2: ACTION: Selection of Potential Topics for Joint UAC/Council Study Session
Chair Foster asked if there were any specific topics that the UAC would like to discuss at the
meeting with Council on April 20. He suggested that a potential format for the meeting is for
the 9 Council members to share their thoughts and allow time for each Commissioner to s peak
as well.
Chair Foster suggested that governance of CPAU could be a topic for discussion. Vice Chair
Waldfogel said that a survey of other agencies' governance would be valuable for that
discussion, noting that the Sacramento Municipal Utilities Dist rict has a different model for
governance.
Chair Foster said that the UAC Chair and Vice Chair would meet with the Mayor and Vice Mayor
to establish the list of topics for discussion.
ACTION:
None.
ITEM 3: ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting
Chair Foster asked who would be providing a presentation on the fiber plan and FTTP. Director
Fong said that CIO Jonathan Reichental will provide that presentation.
ACTION:
None.
ITEM 4: PRESENTATION: Overview of Wastewater Treatment Plant Long Term Facilities Plan
Regional Water Quality Control Plant (RWQCP) Manager Jamie Allen provided a summary of the
RWQCP's Long-Range Facilities Plan (LRFP) that was completed in 2012 and accepted by the
City Council in July 2012. He stated that the plan was prepared because the RWQCP’s facilities
were old and past their design lifetime. He said that the facility was vital and runs around the
clock. The LRFP was done to provide a roadmap, project sequencing, and the ultimate plant
layout for new facilities. It also included some evaluation of the cost of facilities to respond to
potential future regulations related to nitrogen and phosphorus. The plant serves over 200,000
people across six communities. Allen stated that minor capital additions were approved
through the partnership agreement at about $2.8 million per year, escalating with inflation.
Utilities Advisory Commission Minutes Approved on: Page 7 of 11
Allen stated that the facilities for processing biosolids needed to be rehabilitated. The
incinerator needed to be replaced. The plan was to first build a dewatering and truck load-out
facility, an $18 million project, allowing the City to remove the incinerators and temporarily
ship biosolids to an East Bay Municipal Utility District facility for processing or the Central Valley
for composting. The second phase was to build a wet anaerobic digester to process biosolids
and make energy from the biogas, a $75 million project. That cost estimate was still
preliminary, and would become more accurate as the design phase progressed. The third phase
would be to evaluate processing food waste in the digester.
Allen stated that the total estimated capital cost of all projects in the LRFP, including the new
biosolids facility, was $222 million with a cost to the CPAU Wastewater Collection Fund of $78
million. Using a low-cost loan from the State Revolving Loan Fund, the estimated annual cost
for the CIP is $9.2 million, of which $3.3 million is allocated to CPAU. He stated that other
treatment plants in the area were beginning rehabilitation efforts similar in scale to Palo Alto’s.
Allen stated that the San Francisco Bay did not currently have a problem with nitrogen and
phosphorus discharge, but regulators were concerned with potential harm from these sources.
If regulators decided there was a potential for harm to the Bay, additional equipment might
need to be added to the treatment plant to reduce these discharges. This could cost as much as
$150 million. The City was supporting monitoring of the Bay and looking for low cost process
improvements that could reduce these discharges.
Commissioner Eglash thanked Allen for his presentation. He said that one of the issues raised
during the discussion of the Wastewater Collection Utility Financial Plan was that operational
costs at the treatment plant were increasing substantially. He asked why that was.
Senior Resource Planner Jon Abendschein clarified that Utilities staff was not aware of increases
in operations costs at the RWQCP, and that the increases in treatment costs shown in the
Wastewater Collection Financial Plan are related to projected increases in debt service costs
due to capital investment at the treatment plant. Allen confirmed that was the case.
Commissioner Eglash asked whether it was reasonable to say that the Wastewater Collection
rate increases were due to a combination of factors: an increase in treatment costs due to
capital investment at the plant, an increase in operations costs for the Wastewater Collection
Utility, and the fact that revenues were currently below costs. Abendschein confirmed that was
the case, but noted that projected operations costs increases were in line with inflation.
Commissioner Melton asked if the concentration of salts in the recycled water generated by the
treatment plant has declined as a result of improvements the City of Mountain View made to
its collection systems. Allen stated that the RWQCP coordinates with its partner agencies to
identify the sources of the salt and these efforts had improved the quality of the recycled water
produced. He noted that conservation and the drought had reduced flows to the plant and
salinity had gone back up. The long-term trend in salinity had been downward, but it was a
difficult issue to manage. Part of the process of managing salinity involved making sure partner
agencies were reducing infiltration in their sewer systems by replacing degraded pipes.
Utilities Advisory Commission Minutes Approved on: Page 8 of 11
Commissioner Melton noted that the Santa Clara Valley Water District has a recycling plant that
produces potable quality water. He added that the availability of recycled water for irrigation
should be high on the priorities list for the plant. Allen said that staff at the plant supported
expanding recycled water.
Vice Chair Waldfogel asked if the total dissolved solids (TDS) target number of 600 ppm was
acceptable for the users of recycled water. Allen stated that Stanford Lands had requested a
TDS of 650, but acceptable salinity levels depend on soil conditions, drainage conditions and
plant materials. Vice Chair Waldfogel encouraged staff to coordinate with potential users of
recycled water on acceptable TDS levels. Council Member Scharff said the City had set a goal
for TDS levels. Assistant Director Jane Ratchye said that the City had coordinated with potential
recycled water users, who had requested a TDS level of 650 and confirmed that the City’s
adopted goal was to achieve a TDS level of 600.
Commissioner Hall thanked Allen for speaking to the UAC. He asked how much of the total
treatment cost was for capital costs versus operational costs. He noted that the treatment
costs for CPAU were rising quickly. Allen said that capital investment was roughly 10% of the
total cost of operating the plant.
Commissioner Hall requested additional detail on wastewater treatment operations, debt
service, and capital investment costs in the future. He said this was important to enable the
UAC review of the Wastewater Collection rates. Allen said he would work with Utilities staff to
provide the information. Director Fong noted that while staff could provide information, the
treatment plant’s spending plan was not within the UAC’s purview.
Vice Chair Waldfogel noted that the cost estimates for the biosolids facility were preliminary,
and could increase from the projections in the Wastewater Collection Financial Plan. He also
noted that the nitrogen issue could also lead to increases in treatment costs from the
projections in the Financial Plan. The current treatment cost projections could be on the low
end of the possible range of future treatment costs.
ITEM: 5: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt: (1) a Resolution Approving the Fiscal year 2016 Wastewater
Collection Financial Plan and Amending the Wastewater Collection Utility Reserve Management
Practices, and (2) a Resolution amending State Schedules S-1 (Residential Wastewater
Collection and Disposal), S-2 (Commercial Wastewater Collection and Disposal), S-6 (Restaurant
Wastewater Collection and Disposal) and S-7 (Commercial Wastewater Collection and Disposal
– Industrial Discharger)
Resource Planner Eric Keniston summarized the WWC financial projection, noting that rate
increases of 9%/year for the next four years are required as presented in February when staff
presented the preliminary financial forecasts. Costs are increasing at 3 to 5% per year, but
revenues are currently below costs so rates must increase at a higher rate than costs.
Utilities Advisory Commission Minutes Approved on: Page 9 of 11
ACTION:
Chair Foster made a motion to recommend that the City Council Adopt: (1) a Resolution
Approving the Fiscal year 2016 Wastewater Collection Financial Plan and Amending the
Wastewater Collection Utility Reserve Management Practices, and (2) a Resolution amending
State Schedules S-1 (Residential Wastewater Collection and Disposal), S-2 (Commercial
Wastewater Collection and Disposal), S-6 (Restaurant Wastewater Collection and Disposal) and
S-7 (Commercial Wastewater Collection and Disposal – Industrial Discharger). Vice Chair
Waldfogel seconded the motion. The motion carried unanimously (6-0 with Chair Foster,
Commissioners Chang, Eglash, Hall, Melton and Vice Chair Waldfogel voting yes, Commissioner
Cook absent).
______________________________________________________________________________
At this point in the meeting, Commissioner Hall left the meeting and the UAC returned to
complete the discussion on the water-related parts of Item #1 before discussing Item #6.
ITEM 6: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt: (1) a Resolution Approving the Fiscal Year 2016 Water Utility
Financial Plan and Amending the Water Utility Reserve Management Practices; and (2) a
Resolution Amending Rate Schedules W-1 (General Residential Water Service), W-2 (Water
Service from Fire Hydrants), W-3 (Fire Service Connections), W-4 (Residential Master-Metered
and General Non-Residential Water Service), and W-7 (Non-Residential Irrigation Water
Service)
Senior Resource Planner Jon Abendschein provided an update to the preliminary rate
projections that were provided to the UAC at its February meeting. Abendschein stated that
the San Francisco Public Utilities Commission (SFPUC) had previously projected that wholesale
water rates would rise by 15%, but after the UAC's February meeting, the SFPUC advised the
City that its wholesale water rate for FY 2016 is instead projected to increase by 30.7%, which
would increase the City’s wholesale water costs by 14%. He stated that staff had changed its
rate proposal for FY 2016 to a 12% increase instead of 7%, and would use rate stabilization
reserves to spread any remaining cost increase across future years. Staff is working on a public
communications strategy. The result of the change in SFPUC’s wholesale water rates is that the
entire 12% proposed retail rate increase is due to the increased wholesale water cost.
Abendschein showed that the SFPUC's debt service is rising due to the Water System
Improvement Program (WSIP), the program to upgrade and repair the regional water system.
The project had started in 2007 and was projected to end in 2019. Each year the SFPUC issues
new debt to fund the next phase of the project. That meant that each year the annual debt
service costs assigned to wholesale customers like Palo Alto increases, with a corresponding
increase in wholesale water rates. The increases in debt service payments remain in effect until
the debt service is paid off in several decades.
Abendschein said staff incorporated feedback the UAC provided at its February meeting about
post-drought consumption and whether it would return to pre-drought levels. In previous
droughts consumption did not returned to pre-drought levels. Staff took that into account and
changed the water consumption forecast for FY 2016 through FY 2023. This assumption
primarily affected projected future rate increases rather than the proposed FY 2016 rate
Utilities Advisory Commission Minutes Approved on: Page 10 of 11
increase, and affected them by a percentage point or two. He also noted that the projections
were rate changes, not bill changes, and customers who conserved would see lower bill
increases.
Commissioner Eglash commended staff on incorporating the comments from the UAC in
February and on responding to the unexpected change in the wholesale price of water.
Commissioner Chang asked if the balance between fixed charges versus volumetric charges was
appropriate, given the drought. She asked whether more revenue should be collected from
volumetric charges if the goal was to encourage conservation.
Abendschein noted that the last cost of service analysis (COSA) resulted in an allocation of fixed
charges of about 15% of the total revenue, which was an increase from the level of fixed
revenues collected prior to that COSA. It was in line with the California Urban Water
Conservation Council’s best management practices. The time to recommend revisions to the
level of fixed charges is at the next COSA.
ACTION:
Chair Foster made a motion to recommend that the City Council adopt: (1) a Resolution
Approving the Fiscal Year 2016 Water Utility Financial Plan and Amending the Water Utility
Reserve Management Practices; and (2) a Resolution Amending Rate Schedules W-1 (General
Residential Water Service), W-2 (Water Service from Fire Hydrants), W-3 (Fire Service
Connections), W-4 (Residential Master-Metered and General Non-Residential Water Service),
and W-7 (Non-Residential Irrigation Water Service). Commissioner Eglash seconded the
motion. The motion carried unanimously (5-0 with Chair Foster, Commissioners Chang, Eglash,
Hall, Melton and Vice Chair Waldfogel voting yes, and Commissioners Cook and Hall absent).
ITEM 7: DISCUSSION: Update and discussion on Impacts of Statewide Drought on Water and
Hydroelectric Supplies
Assistant Director Jane Ratchye provided an update on the impacts of drought on the City. She
stated that the situation is still very bleak, but that the SFPUC is still requesting 10% voluntary
water use reductions.
Commissioner Melton noted that although Shasta Reservoir is down from a normal year, it is
doing better than Hetch Hetchy and that the state is getting disparate results between water
available for electric generation and drinking water supplies.
Vice Chair Waldfogel asked by hydroelectric costs go up in the drought since it has always been
represented that hydro costs are fixed. Ratchye replied that for the City’s hydroelectric
supplies from the Western Area Power Administration, when water supplies are short, the
financial obligation of project repayment is shifted from water users to power users.
Utilities Advisory Commission Minutes Approved on: Page 11 of 11
COMMISSIONER COMMENTS
Chair Foster recommended that the April UAC meeting start with the fiber-to-the-premises
(FTTP) item followed by the S/CAP item since those are likely to have the interest of the public,
who may wish to attend.
Chair Foster asked that the rates communication materials stress that the SFPUC’s wholesale
water costs are passed through to the City directly.
Commissioner Eglash noted that the agenda has the wrong date for the next meeting. Director
Fong stated that the actual date is April 1, 2015
Meeting adjourned at 9:18 p.m.
Respectfully submitted,
Marites Ward
City of Palo Alto Utilities
1
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 1, 2015
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt a Resolution Identifying Projects to be Funded by
the Electric Special Project Reserve
REQUEST
Staff recommends that the Utilities Advisory Commission (UAC) recommend City Council adopt
a resolution to designate the $51.8 million in the Electric Special Project (ESP) Reserve as
follows:
1. Use up to $20 million for smart grid deployment initiatives;
2. Use remaining funds of approximately $32 million for transmission upgrades; and
SUMMARY
The Calaveras Reserve was first established in 1983 to help defray costs associated with the
Calaveras Hydroelectric Project. Since its inception, Council has changed the purpose of the
reserve several times, always ensuring that the funds must be used for the benefit of the City of
Palo Alto Utilities (CPAU) electric ratepayers.
In November 2011 Council changed the name of the Calaveras Reserve to the ESP Reserve and
adopted ESP Reserve Guidelines to ensure the reserve funds were spent to benefit electric
ratepayers. Staff’s recommendation is consistent with the ESP Reserve Guidelines and provides
a clear funding alternative for two substantial initiatives: smart grid deployment and
transmission upgrades to improve reliability. Both initiatives are in the evaluation and planning
stages and, if deemed worthwhile, will be brought to the UAC and Council for approval when
staff’s assessment is complete. The combined cost of the two projects is expected to exceed
the funds available in the ESP Reserve.
Approval of staff’s recommendation is necessary to ensure that the ESP Reserve funds are
available for smart grid deployment and transmission upgrades. Should the projects not
materialize, then the funds will automatically be transferred to the Electric Supply Operations
Reserve at the end of FY 2020.
2
BACKGROUND
The Calaveras Reserve was first established in 1983 to offset costs associated with the
Calaveras Hydroelectric Project1. Council changed the purpose of the Calaveras Reserve in 1996
(CMR:214:96), and authorized collecting funds from electric ratepayers to cover the amount
that certain electric assets’ costs were projected to be above their value, or “stranded”, in
anticipation of electric deregulation in 1998 and the possibility of “direct access” (i.e., electric
customers could receive commodity services from another energy supplier). Additionally,
Council approved a new Calaveras Reserve policy linking the reserve balance to an amount
sufficient to cover potential stranded costs.
When the Calaveras Reserve balance reached $71 million in 1999, stranded costs were deemed
fully collected and Council ceased the collection of funds for these stranded costs and
established the Calaveras Reserve Guidelines (CMR 222:99). The guidelines included a schedule
to draw down the funds through the end of FY 2033 so that each year’s stranded costs were
transferred into the electric fund’s operating budget.
On June 15, 2009, Council approved new guidelines to manage the Calaveras Reserve
(CMR:275:09) which included setting the minimum transfer to the electric utility’s operating
budget based on an annual calculation of short-term stranded costs. In addition, the updated
guidelines stated that any funds in excess of long-term stranded costs should be used for
projects that benefit electric ratepayers.
In 2011, the potential that Palo Alto would have stranded costs as a result of direct access was
over and Council expressed concerns about the rate at which the funds were being depleted,
given the prospect of several capital intensive projects facing electric ratepayers—including the
possibility of spending $20 million to fund smart grid initiatives and $30 million or more in
transmission investments to improve the reliability of electric supply for Palo Alto. In
November 2011, Council adopted Resolution 9206 which:
1. Changed the purpose of the Calaveras Reserve from partially funding above market
electric costs and partially funding projects that benefit electric ratepayers , to entirely
funding projects that benefit electric ratepayers;
2. Renamed the Calaveras Reserve as the Electric Special Project (ESP) Reserve; and
3. Set the following ESP Reserve guidelines:
a. The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers;
b. ESP Reserve funds are to be used for projects of significant impact;
c. Projects proposed for funding must demonstrate a need and/or value to electric
ratepayers. The projects must have verifiable value and not be speculative, or risky
in nature;
d. Projects proposed for funding must be substantial in size, requiring funding of at
least $1 million;
1 The Calaveras Hydroelectric Project is a 250 megawatt facility owned by the Northern California Power Agency
(NCPA) on the North Fork of the Stanislaus River. The City of Palo Alto has rights to 22.92% of the output from the
project (and pays that fraction of its costs, including debt service).
3
e. Set a goal to commit funds by end of FY 2015; and
f. Any uncommitted funds remaining at the end of FY 2020 will be transferred to the
Electric Supply Operation Reserve2 and the ESP Reserve will be closed.
When the ESP Reserve Guidelines were adopted, the ESP Reserve balance was approximately
$50 million. This included a $2 million transfer made in 2009 to fund a four-year pilot program
for zero-interest energy efficiency loans for commercial customers. Demand for the pilot
program was low and after four years was terminated. Approximately $1.5 million has since
been returned to the ESP Reserve.
DISCUSSION
Staff continues to evaluate the merits of smart grid deployment and transmission line upgrades.
Both of these initiatives are complicated and require long lead times to develop. The exact
costs and benefits are not currently known; however, the two projects combined are expected
to cost more than $50 million. At the opportune time in the coming years, staff will provide an
assessment and recommendation outlining the costs, benefits and requirements for each
project. An update on the current status of the two projects follows.
Implementation of Smart Grid Systems
A consultant study, The Assessment of Smart Grid Applications Relevant to Palo Alto, was
undertaken to look at smart grid applications specific to Palo Alto . Key findings from the study
presented in February 2012 (Staff Report 2443) include:
1. Advanced meter-based sensors can provide granular and timely energy and water
consumption information to customers to more optimally use utility services, and
enables CPAU to offer varied retail rates to customers based on individual needs.
2. Voltages sensed by the advanced meters enable the electric utility to manage the
distribution system voltage at a more optimal level and enables CPAU to detect and
respond to electricity outages faster.
3. Deployment of sensor technology in the electric distribution system enables better
utilization of distribution system assets to optimally facilitate a greater adoption of
electrification technologies such as electric vehicle and distributed generation
technologies, including photovoltaics.
The 2012 assessment also found the benefit stream associated with such a large capital
investment was not compelling enough, and the technology not mature enough, to warrant a
full scale deployment at that time. Based on the consultant’s recommendation, staff has
instead undertaken a number of pilot scale projects to better assess the costs, benefits and
hurdles associated with smart grid deployment and to provide advanced meters to CPAU’s
“early adopter” type customers.
2 In July 2014, Council adopted new financial reserve guidelines thus eliminating the Electric Supply Rate
Stabilization Reserve. Funds were disbursed into several reserves including the new Electric Supply Operation
Reserve, which is now used for rate stabilization purposes.
4
Early results from the pilot projects and technology advancements in the past 3 years now
suggest full implementation of smart grid systems will be economical for Palo Alto. As a first
step in this regard, CPAU along with the City’s Information Technology Department is
considering a new Utilities Customer Information System (CIS) to store and process the
increased amount of data associated with the advanced meter sensors. This initiative is being
undertaken in conjunction with the City’s effort to migrate to a new Enterprise Resource
Planning (ERP) system. Expectations are that a new ERP/CIS system will be implemented in the
2018-2020 timeline with full implementation of a smart grid system, if found to be cost-
effective, to begin immediately thereafter.
The assessment estimated the cost of implementing smart grid systems at $20 -$25 million. The
portion of the cost attributed to the gas and water utilities is approximately $5 million with the
remaining $20 million attributed to the electric utility. Therefore, staff recommends reserving
$20 million from the ESP Reserve for this project at this time.
Transmission Upgrades
Staff continues its efforts to diversify the transmission routes to the City to improve the
reliability of electric power delivery to the City. Currently the City’s power is delivered over
Pacific Gas and Electric’s (PG&E) transmission system at its Colorado substation near Highway
101. PG&E uses three 115 kilovolt (kV) transmission lines to serve CPAU, but all three lines run
in a common corridor on the bay side of the City. These lines are susceptible to single events
that can affect all three lines, as happened in February of 2010 when a small aircraft hit the
power lines resulting in a city-wide power outage. Since 2010, the City has been actively
involved in the regional transmission planning efforts conducted by the California Independent
System Operator (CAISO). This has resulted in two alternatives to diversify the transmission
routes to the City that are currently under consideration.
One alternative is an electric transmission interconnection between the City and the SLAC
National Accelerator Laboratory (SLAC). The project would construct a new transmission line
from SLAC’s substation to one of the City’s distribution substations. This project would increase
reliability of service for SLAC and the City by providing redundant transmission; it would also
reduce the City’s cost of transmission service by avoiding low voltage transmission charges,
since the new connection to the transmission grid would be at 230kV. Preliminary project cost
estimates are around $45 million. Staff has been involved in discussions and negotiations with
the key stakeholders, including SLAC, Stanford, the Department of Energy (DOE), and the CAISO
for the past few years. Currently Stanford and the City are waiting for the results of further
studies, which are anticipated to be completed this spring.
The second alternative for diversifying the transmission routes to the City is for PG&E to build a
new transmission access point extending from the City’s receiving station to a PG&E site at
NASA Ames within the same bay side electric transmission system as the City’s existing access
point. Under this plan the City’s share of the cost has yet to be determined, but should be
limited to the incremental costs of upgrades on the City’s side of the connection. While this
alternative would improve reliability for the City at a lower initial cost, it will not provide long-
5
term transmission cost relief to the City and is a less diverse electric source from the corridor on
the western side of the Peninsula.
The preferred alternative will be contingent upon feasibility, cost, reliability, diversity, and
agreement between stakeholders. Staff anticipates that a final decision will occur by the end of
2015. Should the City move forward on the SLAC project, construction may take from 3-5 years
after a decision is made. A project of this size will require environmental review followed by
engineering design, manufacture of specialized equipment and , finally, construction.
Alternatives
Alternatives to staff’s recommendation to designate ESP Reserve to fund the two major
initiatives outlined above include the following:
1. Do not designate the funds for specific projects now. Instead leave the funds
uncommitted in the ESP Reserve, and if a project consistent with the ESP Reserve
Guidelines materializes before FY 2020, seek Council approval to use the funds;
2. Close the ESP Reserve effective immediately, and transfer the current balance of the ESP
Reserve to the Electric Supply Operation Reserve, with Council approval ; and
3. Change the guidelines by extending the dates as follows, with Council approval:
a. Change the date when commitment of funds must be determined to the end of
FY 2017 (instead of the end of FY 2015); and
b. Change the date when any uncommitted funds remaining will be transferred to
the Electric Supply Operation Reserve and the ESP Reserve to the end of FY 2022
(instead of the end of FY 2020);.
The first alternative simply makes the funds available for projects other than specifically smart
grid or transmission upgrades. To be consistent with the ESP Reserve guidelines, the projects
would need to cost at least $1 million and provide value to electric ratepayers. Such projects
may include:
New billing and/or customer information systems;
Development of local solar projects;
Electrification initiatives;
Distribution system monitoring and optimization projects; and
Electric distribution system undergrounding projects.
Committing ESP Reserve funds to smart grid initiatives and transmission related upgrades will
not preclude staff from pursuing the projects mentioned above and possibly seeking funds from
the ESP Reserve, if there are compelling reasons to do so and if the re are ESP Reserve funds
available.
The second alternative, transfer the ESP Reserve funds to the operating reserve now, would
defer electric rate increases planned for the next two to three years, thus providing immediate
benefit to electric ratepayers in the form of rate relief. Should the smart grid and transmission
upgrade projects materialize, staff would need to seek rate increases and/or bond financing to
pay for the projects at that time. Staff recommends against using reserves to defer addressing
long-term structural financia l issues. Reserves are generally ineffective at deferring structural
deficits more than ·a few years, and the deferred rate increases are typically higher.
The third alternative changes the ESP guidelines to defer the date by which a commitment of
funds must be made to specific projects. This will allow more time to better·develop the cost
estimates and benefit analyses for likely projects such as smart grid initiatives and transmission
upgrades. This is a reasonable alternative to the proposal, however is not recommended as it
simp ly defers the discussion of how the funds may be used . Staffs prefere nce is to earmark the
funds for the two p r ojects identified sooner in order to allow for clear funding alternatives as it
evaluates the merits of the smart grid initi atives and transmission upgrades.
RESOURCE I M PACT
Supporting staff's recommendation to desi gnate the ESP Reserve funds will not impact
resources. Requests for future expenditures for projects from the proposed new ESP Reserve
require Council approval and their resource impact will be identified at that time.
POLICY IMPLICATIONS
The City's electric ratepayers have been the source of the funds since Council established the
Reserve in 1983. In 1996, California's e lectric industry deregulation law, AB 1890, authorized
both investor-owned and municipal utilities to collect a Competition Transition Charge (CTC), on
electric customer bills. The City opted to collect the CTC from electric ratepayers and further
fund the Calaveras Reserve. The City Attorney's Office has advised that Calaveras funds
continue to be spent to benefit those who contributed -the City's electri c ratepayers.
Staffs recommendat ion to desi gnate funds for smart grid deployment and transmission line
upgrades is consistent with the Council adopted ESP Reserve Guidelines and meets the
intended use of the ori ginal Calaveras Reserve, to benefit Palo Alto's electric ratepayers.
ENVIRO NMENTAL REV I EW
Designation of the Electric Special Project Reserve Funds does not meet the definition of a
project pursuant to Public Resources Code Section 21065, thus no California Environmental
Quality Act review is required.
ATTACH M ENT
A. Resolution to Designate Electric Special Project Reserve Funds for Smart Grid Initiatives and
Transmission Line Upgrades
PREPARED BY: M O NI CA PADILLA, Senior Resou rce Planner ~
REVIEWED BY: ~N E RATCHYE, Assist ant Director, Resource Management
APPROVED BY: {~NJ -VA~LE-~~l +--0-.+.-+-G~~~~~-
Director of Utilities
6
*****NOT YET APPROVED*****
150317 sdl 6053281
1
Resolution No.____
Resolution of the Council of the City of Palo Alto
Identifying Projects to be Funded by the
Electric Special Project Reserve
RECITALS
A. In 1983 the City of Palo Alto (“City”) first established the Calaveras Reserve to help
defray cost associated with the Calaveras Hydroelectric Project.
B. In 1997 Council authorized the collection of a competitive transition surcharge
from the City’s electric customers to cover stranded costs in the event customers elected to
receive electric supply services from other providers.
C. In 1999 Council stopped the collection of the competitive transition surcharge
as the Calaveras Reserve was fully funded at $71 million, and established the Calaveras
Reserve Target and Guidelines with a schedule to draw down funds.
D. In 2009 Council approved new Calaveras Reserve guidelines which required the
annual calculation of short-term stranded costs to determine the minimum transfer to the
electric utility’s operating budget based o n t h e annual calculation of the electric utility’s long-
term stranded costs, and the identification of funds available for special projects to the benefit of
electric ratepayers.
E. In 2011 (Reso 9206) Council changed the name of the Calaveras Reserve to the
Electric Special Project (ESP) Reserve and the purpose from partially funding above market
electric costs and partially funding projects that benefit electric ratepayers, to entirely funding
projects that benefit electric ratepayers. New ESP Reserves Guidelines were also approved,
including a provision to commit the funds for preferred projects by end of FY 2015.
F. At the end of FY 2015, the ESP Reserve balance is expected to be approximately
$52 million with no commitments yet identified for the use of funds.
G. The City is exploring two major capital projects for the benefit of its electric
ratepayers: smart grid deployment and transmission-related reliability upgrades. Both projects
meet the criterion set forth in the ESP Reserve Guidelines.
//
//
ATTACHMENT A
*****NOT YET APPROVED*****
150317 sdl 6053281
2
H. Consistent with the ESP Reserve Guidelines goal to commit the funds by the end
of FY 2015, staff recommends designating the uncommitted ESP Reserve funds to smart grid
deployment efforts and transmission-related reliability upgrades to the benefit of electric
ratepayers.
I. At the April 1, 2015 Utilities Advisory Commission (UAC) meeting, the UAC
reviewed staff’s recommendation and ______________
J. At the May X, 2015, Finance Committee meeting th e Finance Committee
___________
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. In accordance with the Electric Special Project Reserve Guidelines
adopted by Council on November 1, 2011 (Resolution 9206), the Council approves of the use of
ESP Funds to be committed for the following projects, for the benefit of the City’s electric
ratepayers:
a) Smart grid deployment initiatives, funded with up to $20 million of ESP
Reserves funds;
b) Transmission-related reliability upgrades to the City’s electric
infrastructure, funded via any and all ESP Reserve funds remaining.
SECTION 2: While Council has designated, via adoption of this resolution, the
use of ESP Reserve Funds for the projects identified above in Sections 1(a) and (b), Staff will seek
Council approval for specific projects only after staff’s complete assessment and
recommendation on the costs, benefits and requirements for each project.
/ /
/ /
/ /
/ /
/ /
/ /
/ /
*****NOT YET APPROVED*****
150317 sdl 6053281
3
SECTION 3: The Council finds that the adoption of this resolution identifying
projects to be funded by the ESP Reserve does not meet the California Environmental Quality
Act’s definition of a “project” under Public Resources Code Section 21065, thus no
environmental review is required.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST: APPROVED:
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM:
___________________________ ____________________________
Senior Deputy City Attorney Director of Utilities
____________________________
Director of Administrative Services
1
4
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 1, 2015
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt a Resolution Approving the Fiscal Year 2016 Gas
Financial Plan, Including no Recommended Rate Changes for July 1, 2015, and
Amending the Gas Utility Reserve Management Practices
RECCOMENDATION
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council adopt
a resolution (Attachment A) approving the fiscal year (FY) 2016 Gas Financial Plan (Attachment
C) and amending the Gas Utility Reserve Management Practices (Attachment B).
EXECUTIVE SUMMARY
The FY 2016 Gas Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2022. Costs are projected to rise moderately for the next several years due
primarily to Capital Improvement Program (CIP) increases and costs related to transporting gas
on PG&E’s pipelines. As reserves are currently adequate, staff proposes that no increase will be
needed for FY 2016, but the Financial Plan includes a 7% projected rate increase for FY 2017
and 3% to 4% annual increases after FY 2017, to adequately recover the costs of providing gas
service.
Staff also recommends changes to the Gas Utility Reserves Management Practices to
accommodate a change in City budgeting practices for CIP projects.
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.
2
Each Financial Plan also contains a set of Reserves Management Practices describing the
reserves for each utility and the management practices for those reserves. Staff may propose
amendments to these reserves as part of the Financial Plans.
The UAC reviewed preliminary long-term financial forecasts at its February 4, 2015 meeting.
DISCUSSION
Proposed Actions for FY 2016
This year’s Gas Utility Financial Plan proposes the following actions for FY 2016:
1. Transfer $3.4 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3C of Attachment C for more details; and
2. Amend the CIP Reserve to accommodate a change in City capital budgeting practices.
These amendments are summarized below, but for a more in-depth description of the
reasons for these changes, see Section 3B of the Financial Plan:
a. Amend the Reserves Management Practices to modify the purpose of the CIP
Reserve to enable it to act as a cash flow and contingency reserve for capital
investment projects; and
b. Transfer the funds that are projected to be released from the Re-appropriations
Reserve at the end of FY 2015 to the CIP Reserve.
This proposal is described in more detail in the FY 2016 Gas Financial Plan (Attachment C).
Projected Rate Adjustments over the Financial Planning Period
Table 1 shows the projected rate adjustments included in the Gas Utility Financial Plan and their
impact on the median residential gas bill.
Table 1: Projected Gas Rate Adjustments and Residential Bill Impact, FY 2016 to FY 2022
FY
2016
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
Gas Utility 0% 7% 4% 4% 4% 4% 3%
Estimated Bill Impact for
Residential Customers ($/mo)* - $2.60 $1.77 $1.89 $2.01 $1.30 $1.24
* Bill impacts are presented holding commodity prices static, as these are a pass -through cost and change monthly
based on market conditions. Median bills based on 18 therms in summer (April-October) and 54 therms winter
(November-March).
Table 2 shows the proposed and projected rate adjustments in the context of the other
proposed and projected utility rates.
3
Table 2: Rate Adjustments, All Utilities, FY 2016 Proposed, FY 2017 to FY 2020 Projected
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Electric 0% 6% 6% 1% 1%
Gas1 0% 7% 4% 4% 4%
Wastewater 9% 9% 9% 9% 6%
Water 12% 8% 8% 8% 3%
Refuse2 9% 9% 8% 2% to 3% 2% to 3%
Storm Drain3 2.7% 2% to 3% 2% to 3% 2% to 3% 2% to 3%
Total Bill
Change4
(%) 6% 8% 7% 5% 3%
($/mo) $14.73 $18.91 $18.53 $14.39 $9.55
(1) Gas rate changes are shown with commodity rates held constant. Actual gas commodity rates will vary monthly
with wholesale market fluctuations
(2) No forecast available past FY 2018, inflationary increases assumed.
(3) Storm Drain Rates increase annually by CPI; existing rates sunset in June 2017 unless reauthorized by a majority
vote of property owners.
(4) Change in estimated median residential bill, $230.76 as of June 30, 2014
Staff’s annual assessment of the financial position of the City’s utilities 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 projecting rates that are adequate to recover these costs. The current rates are also based
on the methodology from the April 2012 Gas Utility Cost of Service Study completed by Utility
Financial Solutions (Staff Report 2812). Staff reviews this study annually and plans to update
the cost of service analysis over the next two to three years.
The main drivers for the increase in the Gas Utility’s costs (and therefore rates) over the next
several years include:
The cost for transmission on the PG&E system, which is projected to nearly double in FY
2016 and increase by roughly 3% thereafter; and
Operating and CIP costs, which are projected to rise by roughly 2% to 4% annually.
There is uncertainty related to capital costs for the Gas Utility in coming years. Gas main
replacement costs have risen substantially in recent years, and it is possible higher CIP
expenditures will be required in the future. The Financial Plan includes rate projections for a
“High CIP Cost” scenario. Staff plans to complete an updated gas system master plan later in
2015 and expects better information about future main replacement costs whe n that plan to
update the assessment of the system’s condition is completed.
NEXT STEPS
After receiving the UAC’s recommendation, the Finance Committee will review staff’s
recommendations in April. The proposed Financial Plans will be considered for adoption by the
City Council with the FY 2016 budget in June.
RESOURCE IMPACT
No impacts on FY 2016 sales revenues are projected for the Gas Utility since no rate increase is
proposed for FY 2016. See the attached FY 2016 Gas Utility Financial Plan for a more
comprehensive overview of projected cost and revenue changes for FY 2016 through FY 2022.
POLICY IMPLICATIONS
The proposed FY 2016 Gas Utility Financial Plan includes amended Reserve Management
Practices that will modify Council policy with respect to the structure of the Gas Utility financial
reserves. These Re serve Management Practices replace the current Reserve Management
Practices, which were approved by Council in June 2014 {Resolution 9423).
ENVIRONMENTAL REVIEW
The UAC's review and recommendation to Council on the proposed Gas Financial Plan do not
meet the definition of a project, pursuant to Section 21065 of the California Environmental
Quality Act, thus no environmental review is required.
ATTACHMENTS
A. Resolution of the Council of the City of Palo Alto Approving the FY 2016 Gas Utility
Financial Plan and Amending the Gas Utility Reserves Management Practices
B. Amended Gas Utility Reserves Management Practices {in redline/strikeout text)
C. Proposed FY 2016 Gas Utility Financial Plan
PREPARED BY: JONATHAN ABENDSCHEIN, Senior Resource Planner cfo;
ERIC KENISTON, Resource Planner cc·;-~£-
~)'LANE RATCHYE, Assistant Director, Resource Management
VA ~G
REVIEWED BY:
APPROVED BY:
Director of Utilities
4
Attachment A
* NOT YET APPROVED *
150319 sdl 6053275
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2016 Gas Utility Financial Plan and Amending the Gas Utility
Reserves Management Practices
R E C I T A L S
A. Each year the City of Palo Alto (“City”) assesses the financial position of its
utilities with the goal of ensuring adequate revenue to fund operations. This includes making
long-term projections of market conditions, the physical condition of the system, and other
factors that could affect utility costs, and setting rates adequate to recover these costs. It does
this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made a
part of the Financial Plans.
C. The City intends to make changes to its Gas Utility Reserves Management
Practices to amend the purpose and management practices of the Gas Utility’s Capital
Improvement Program (CIP) Reserve.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2016 Gas Utility Financial Plan,
including the amended Gas Utility Reserves Management Practices. These Reserves
Management Practices replace the Reserves Management Practices previously approved for
the Gas Utility as part of the FY 2015 Gas Utility Financial Plan (Resolution 9423).
SECTION 2. The Council hereby approves the transfer of $3.4 million in FY 2015 from
the Rate Stabilization Reserve to the Operations Reserve, and the transfer of all funds released
in FY 2015 from the Reappropriations Reserve to the CIP Reserve, as described in the FY 2016
Gas Utility Financial Plan approved via this resolution.
/ /
//
Attachment A
* NOT YET APPROVED *
150319 sdl 6053275
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s 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
Proposed Amendments to Gas Utility Reserves Management Practices
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 future year expenditure on the Gas Utility’s 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.
ATTACHMENT B
Proposed Amendments to Gas Utility Reserves Management Practices
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
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
Funds may be added to or withdrawn from the CIP Reserve by action of the City Council
and held for future year expenditure on the Gas Utility’s CIP Program. Withdrawal of
funds from the CIP Reserve requires Council action. If there are funds in the CIP 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.
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 [BA1]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.
a)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 re turn
them to ratepayers in the next Financial Plan . Staff may also seek City Council approval
Proposed Amendments to Gas Utility Reserves Management Practices
to approve holding funds in this reserve in excess of the maximum level, if they are held
for a specific future purpose related to the CIP.
Section 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 .
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. I n
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.
Proposed Amendments to Gas Utility Reserves Management Practices
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 purp ose 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.
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
FY 2016 TO FY 2022
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 3
Section 2: Executive Summary and Recommendations ........................................................... 4
Section 2A: Executive Summary ................................................................................................... 4
Section 2B: Summary of Proposed Actions .................................................................................. 5
Section 3: Rate and Reserve Proposals ................................................................................... 5
Section 3A: Current and Proposed Rates ..................................................................................... 5
Section 3B. Reserves Management Practices, Proposed Change ................................................ 6
Section 3C. Proposed Reserve Transfers ...................................................................................... 7
Section 4: Current State of the Utility..................................................................................... 7
Section 4A. Utility Overview ........................................................................................................ 7
Section 4B. Current Rates and Competitiveness .......................................................................... 8
Section 4C. Current Utility Financial Status ................................................................................. 9
Section 4D. Status of Reserves ................................................................................................... 10
Section 4E. Debt Service ............................................................................................................. 11
Section 5. Looking Back ....................................................................................................... 11
Section 5A. Background ............................................................................................................. 11
Section 5B. Historical Gas Commodity Prices ........................................................................... 13
Section 5C. Historical Expenses and Revenues ......................................................................... 13
Section 6. Looking Forward .................................................................................................. 14
Section 6A. Seven Year Financial Forecast ................................................................................ 14
1.Overview ...................................................................................................................... 14
2.Commodity Supply Costs.............................................................................................. 15
3.Operations .................................................................................................................... 16
ATTACHMENT C
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4. Capital Improvement Program (CIP) ............................................................................ 17
5. Equity Transfer ............................................................................................................. 18
Section 6B. Revenue Requirement and Sources ........................................................................ 18
Section 6C. Risk Assessment and Reserve Adequacy ................................................................ 20
Section 6D. Alternate Scenarios ................................................................................................ 21
Section 6E. Historical and Projected Consumption ................................................................... 22
Section 6F. Long Term Outlook ................................................................................................. 23
Section 6G. Communications Plan ............................................................................................ 24
Appendices ......................................................................................................................... 26
Appendix A: Gas Utility Financial Forecast Detail ..................................................................... 27
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 28
Appendix C: Gas Utility Reserves Management Practices ......................................................... 30
Appendix D: Gas Utility Debt Service Details ............................................................................. 31
Appendix E: Description of Gas Utility Cost Categories ............................................................. 33
Appendix F: Gas Utility Communications Samples .................................................................... 34
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SECTION 1: DEFINITIONS AND ABBR EVIATIONS
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.
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E City Gate, or City Gate: 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 City Gate.
PVC: Polyvinyl chloride, a plastic gas main material
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.
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SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS
SECTION 2 A : EXECUTIVE SUMMARY
This document presents a financial plan for the City of Palo Alto’s (CPAU’s) Gas Utility for the
next seven years. The 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.
Over the next seven fiscal years staff projects that the Gas Utility will see non-commodity costs
rising at roughly 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 allowance purchase costs. In addition,
capital improvement program (CIP) costs have increased as the economy has improved, and
CPAU is also planning for new gas main replacement projects after completing a large multi-
year gas main replacement project. The Gas Utility expenses over the period of this financial
plan are shown in Table 1 below.
Table 1: Gas Utility Expenses for FY 2014 to FY 2022
Expenses
($000)
FY 2014
(actual)
FY 2015
(est.)
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Commodity costs 14,325 12,438 13,429 14,962 16,294 16,999 17,364 17,680 18,127
Operations 17,869 19,479 21,581 22,486 23,297 23,285 24,386 25,359 26,313
Capital Projects 240 2341 5673 5214 5402 5550 5728 5728 5728
TOTAL 32,435 34,258 40,683 42,661 45,093 45,933 47,477 48,767 50,168
To ensure that revenues cover these rising costs, the financial plan includes the rate trajectory
shown in Table 2. There is no planned rate increase for FY 2016, a result that is made possible
due to accumulated rate stabilization reserves, which resulted when new gas main replacement
projects were not added in FY 2014 and FY 2015 in order to complete a multi-year project to
replace the last of the ABS plastic mains in Palo Alto. A 7% increase is projected for FY 2017,
followed by 3% and 4% increases for FY 2018 through FY 2022. A 7% increase in FY 2017 would
be equivalent to $2.60 per month for the median residential customer’s monthly gas bill, based
on commodity prices as of February 2015.
Table 2: Projected Gas Rate Trajectory for FY 2015 to FY 2022
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
0% 7% 4% 4% 4% 3% 3%
This financial plan includes an updated to the Gas Utility Reserves Management Practices,
amending the purpose of the CIP Reserve, as described below.
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SECTION 2 B : SUMMARY OF PROPOSE D ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2016:
1. Amend the Reserves Management Practices to modify the purpose of the CIP Reserve,
enabling it to act as a cash flow contingency reserve for capital investment projects as
outlined in Section 3B.
2. Transfer all funds released from the Reappropriations Reserve at the end of FY 2015 to
the CIP Reserve, as outlined in Section 3B.
3. Transfer $3.4 million from the Rate Stabilization Reserve to the Operations Reserve. See
Section 3C for more details.
SECTION 3: RATE AND RESERVE PROPOSALS
SECTION 3 A : 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 prices1. In addition, monthly service charges were increased to
recover the cost providing gas service to customers. In January 2015 the PaloAltoGreen Gas
program was launched, which allowed customers to reduce or eliminate the greenhouse gas
(GHG) emissions associated with their gas usage for an additional charge. The voluntary
program is backed by high quality environmental offsets that CPAU will purchase on behalf of
participants.2
Also 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 program3.
This component will change depending on the cost of allowances and gas demand. In addition,
two bill components (Local transportation and Administration) were collapsed into the
Distribution rate to streamline bill presentation. Table 3, below, summarizes the current rates
for all customer classes.
1 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 4596, 4/21/2014: https://www.cityofpaloalto.org/civicax/filebank/documents/39983
3 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
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Table 3: Current Gas Rates
Rate Component Units
G-1
(Residential)
G-2 (Small
Commercial)
G-3 (Large
Commercial)
G-10
(CNG)
Last
Changed
Service Charge $/month 9.88 74.86 361.18 50.65 7/1/2012
Distribution (Tier 1) $/therm 0.4392 0.6147 0.6071 0.0509 2/1/2015
Distribution (Tier 2) $/therm 0.9546 N/A N/A N/A 2/1/2015
PaloAltoGreen Gas
(optional)
$/therm
additional
$0.12 $0.12 $0.12 $0.12 7/1/2014
(new rate)
Commodity $/therm 0.3281
(Feb. 2015)
0.3281
(Feb. 2015)
0.3281
(Feb. 2015)
0.3281
(Feb. 2015)
(varies
monthly)4
Tier 1 amount (for G-1, residential customers):
Winter Therms/day 2 N/A N/A N/A 7/1/2012
Summer Therms/day 0.667 N/A N/A N/A 7/1/2012
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 Solutions.5 Staff tentatively plans to review
this cost of service study in two to three years unless any major changes occur to the utility’s
operations or customer base that would necessitate an earlier study. Before any such update,
staff will review current rates and the scope of the study with the UAC and Council to
determine UAC and Council policy priorities.
SECTION 3 B . RESERVES MANAGEMEN T PRACTICES, PROPOSED CHANGE
Staff proposes one change to the Gas Utility Reserves Management Practices (Appendix C) in
this Financial Plan. Staff recommends changing the CIP Reserve definition and management
practices so that it becomes a cash flow and contingency reserve for CIP projects. Currently
these purposes are served by a combination of the Operations and Reappropriations Reserves,
while the CIP Reserve acts as a sinking fund to accumulate funds for large one -time future CIP
expenditures (which are rare). The City is changing its budgeting practices starting with FY 201 6,
and will no longer reappropriate CIP budgets each year. Instead, CIP budgets for long -term or
ongoing projects will be renewed each year through the annual budget process. This means
that the funds in the Reappropriations Reserve ($1.5 million as of June 30, 2014) will be
released after June 30, 2015. These funds acted as a cash flow reserve for CIP projects, and
some or all of it should be retained for that purpose. Staff proposes to retain these funds in the
CIP reserve, and the proposed changes to the Reserves Management Practices will enable CPAU
to do that.
Staff proposes to initially set a minimum and maximum guideline for the CIP reserve that will
enable it to hold similar amounts to what has typically been held within the Reappropriations
Reserve. Staff intends to review the capital management practices at other agencies and revisit
these guideline levels, but initially, staff proposes a minimum guideline level of 12 to 24 months
of CIP expenditure. CIP-related funds in the Commitments Reserve would be allowed to count
toward that guideline. The CIP-related funds in the Commitments Reserve are equal to the total
4 For historic commodity rates, see: http://www.cityofpaloalto.org/civicax/filebank/documents/30399
5 Staff Report ID#2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
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remaining balance of all CIP contracts currently in progress, and these funds should be taken
into account when determining whether CIP cash flow and contingency reserves are adequate.
The initial maximum guideline level would be 24 months of CIP expenditures, but the maximum
guideline could be exceeded with Council approval.
Figure 1 shows the Reappropriations Reserve level as of June 30, 2014, as well as the CIP
portion of the Reserve for Commitments.
Figure 1: Gas Utility Capital Reserve
SECTION 3 C . PROPOSED RESERVE TRANSFERS
For FY 2016, staff proposes a $3.4 million transfer from the Rate Stabilization Reserve. This
transfer is included in the financial projections in this Financial Plan. It will enable CPAU to
maintain adequate Operations Reserve levels while moderating the pace of increase in Gas
rates. In addition, staff proposes transfers from the Reappropriations Reserve to the CIP
Reserve as described in the previous section. The impact of these transfers on reserves levels
can be seen in Appendix A.
SECTION 4: CURRENT S TATE OF THE UTILITY
SECTION 4 A . UTILITY OVERVIEW
The CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,500 customers are connected to the natural gas system,
approximately 21,800 (93%) of which are residential and 1,700 (7%) of which are non-
residential. Residential customers consume about 11 to 12 million therms of gas per year,
roughly 45% of the gas sold, while non-residential customers consume 55% (about 15 million
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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 spas6. Non-residential customers use gas for space and water
heating (73% of gas consumed), cooking (20%), and industrial processes (6%).7
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 a 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. The cost of
purchased gas and PG&E local transportation service accounts for roughly one third of the
utility’s expenditures.
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 2 3,500 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 accounts for around 15 to 20% of the utility’s expenditures. Costs
for main replacements have been going up, however, and those uncertainties are discussed in
Section 6A(4) below.
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.
SECTION 4 B . CURRENT RATES AND COMPETITIVENESS
Table 4 presents winter and summer residential bills for Palo Alto and PG&E for several usage
levels for rates in effect as of and July 2014 (to illustrate a summer month bill) and January 2015
(to illustrate a winter month bill). The annual gas bill for the median residential customer for
calendar year 2014 was $489.94, about 1% lower than the annual bill for a PG&E customer with
6 http://energyalmanac.ca.gov/naturalgas/overview.html
7 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are
for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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the same consumption. In January 2015, PG&E’s distribution rates for gas increased
substantially to collect for needed system improvements for pipeline safety and maintenance,
and their rates are expected to continue to increase in the future.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 4: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(Jan 2015)
30 33.82 40.29 -16%
(Median) 54 52.97 72.52 -27%
80 84.03 116.15 -28%
150 175.97 2412 -27%
Summer
(Jul 2014)
10 19.55 12.36 58%
(Median) 18 27.28 22.34 22%
30 44.04 41.01 7%
45 66.28 64.35 3%
Table 5 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of January 1, 2015. Bills for CPAU customers at the usage levels shown are 5 to 6%
lower for smaller commercial customers and 8 to 21% higher for larger 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 27-44% 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 5: Commercial Monthly Average Gas Bill Comparison (for Rates in Effect Jan. 1, 2015)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 562 600 -6%
5,000 4,942 5,205 -5%
10,000 10,020 9,284 8%
50,000 48,656 40,242 21%
SECTION 4 C . CURRENT UTILITY FI NANCIAL STATUS
In FY 2014, gas purchases represented 44% of Gas Utility’s costs, with CIP and Operations
together representing another 22%. The remaining costs were for administration, overhead,
and other costs (34%) as shown in Figure 3. The percentages for FY 2014 are skewed by the
fact that CIP, which is normally about 20% of expenses, was reduced in FY 2014 to allow for a
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backlog of projects to be completed. The utility’s revenue in FY 2014 came almost entirely from
gas sales (95%), with the remainder coming from capacity and connection fees (2%), and other
sources (3%), as shown in Figure 2.
As shown in Table 6, for FY 2015, net
revenues are expected to be $334,000, or $3.4 million lower than the $3.8 million in the
adopted budget. Net sales are projected to be $4.8 million lower than the adopted budget,
mainly due to an accounting error.
Table 6: Projected Gas Utility Net Revenue, FY 2015
Gas - Operating Activity All figures in thousands $ (000’s)
Adopted
Budget
FY 2015
Projected
FY 2015
Activity
Variance to
Budget
Net Sales * 37,343 32,586 (4,757)
Other revenues 1,849 2,005 156
Purchase costs (13,732) (12,438) (1,294)
Other expenses ** (21,686) (21,820) 124
Total 3,764 334 (3,430)
* Includes misc. sales, adjustments, discounts, and bad debt
** Includes reserve transfers, salaries, allocated charges, other misc. expenses and
encumbrances
SECTION 4 D . STATUS OF RESERVES
Table 7 shows the projected balance of each of the Gas Utility reserves for the period covered
by this Financial Plan. The projected balances are also provided in Appendix A . Total reserves
at the end of FY 2015 (6/30/2015) are projected to be $28.6 million, with $8.9 million remaining
in the Rate Stabilization Reserve for future years and $8.4 million in the Operations Reserve,
which is at the Reserve Target level. As detailed in Appendix C (Gas Utility Reserves
Figure 3: FY 2014 Costs by Activity
Gas
Purchases,
44%
CIP, 1%
Operations,
21%
Admin/
Overhead,
34%
Figure 2: FY 2014 Revenue Structure
Sales of
Gas, 95%
Capacity/
Connection
, 2%
Other, 3%
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Management Practices) and in Section 3B, this plan includes a change to the structure of the
utility’s CIP Reserve to make it a cash flow and contingency reserve for CIP projects.
Table 7: Projected End of Fiscal Year Gas Utility Reserve Balances for FY 2015 to FY 2022
Ending Reserve
Balance ($000) FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
Reappropriations
and Commitments 9,817 9,817 9,817 9,817 9,817 9,817 9,817 9,817
Capital 1,488 1,488 1,488 1,488 1,488 1,488 1,488 1,488
Rate Stabilization 8,884 3,913 545 0 0 0 0 0
Operations 8,429 8,711 9,279 7,721 7,529 8,159 9,216 10,807
Unassigned 0 0 0 0 0 0 0 0
TOTAL 28,619 23,929 21,129 19,026 18,834 19,464 20,521 22,112
SECTION 4 E . DEBT SERVICE
The Gas Utility’s annual debt service is roughly $800,000 per year. This is related to one bond
issuance that will require payments through 2026. This issuance, the 2011 Series A Utility
Revenue Refunding Bonds, was a joint issuance between the Gas and Water Utilities refinancing
the 2002 Utility Revenue Bonds, Series A, which was issued to finance various capital
improvements for both systems. The City is in compliance with all covenants on the bond.
Additional detail is provided in Appendix D.
SECTION 5. LOOKING B ACK
SECTION 5 A . BACKGROUND
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
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 w ere 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.
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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 over 45 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 2014 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
protection is 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
footage of annual PVC replacement for future CIP projects is currently being conducted. This
was an example of how local control of its Gas Utility has provided Palo Alto resident s 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 recent 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.
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.
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
GAS UTILITY FINANCIAL PLAN
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SECTION 5B. HISTORICAL GAS COMMODITY PRICES
Gas commodity prices have suffered periods of very high volatility. As shown in Figure 4, gas
commodity prices spiked up—and then plunged down—dramatically in the 2000/2001
California energy crisis. Prices also rose quickly from late 2007 to a peak in July 2008, followed
by a steep fall as the gas extraction process of hydraulic fracturing (“fracking”) resulted in
increased supplies. Gas prices, though still subject to volatility, have been moderate since
2009.
Figure 4: Gas Market Prices at PG&E Citygate
SECTI ON 5 C . HISTORICAL EXPENSES AND REVENUES
Table 8 shows the Gas Utility’s expenses and revenues for the past five years. Total costs for
this utility have decreased 20% since 2010, primarily since commodity costs decreased 36%
with reduced gas market prices. Distribution operations costs11 were 5% higher in 2014 than
they were in 2010. Sales revenues decreased in FY 2013 as the utility began to pass through
the monthly gas commodity prices to customers. FY 2013 sales volumes were also lower than
normal due to warmer than average weather. Budgeted CIP expenses were notably low in FY
2014 because no new main replacement project was budgeted. This was to allow work to be
11 Administration, Demand Side Management, Engineering, O&M, and Resource Management categories.
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GAS UTILITY FINANCIAL PLAN
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completed on a large multi-year main replacement project that commenced in a prior year.
Budgeting for ongoing gas main replacements resumed in FY 2015.
Table 8: Gas Utility Historical Expenses
SECTION 6. LOOKING F ORWARD
SECTION 6 A . SEVEN YEAR FINANCIAL FOREC AST
1. OVERVIEW
Staff has prepared a forecast of costs and revenues through FY 2022. As shown in Table 9 (and
Appendix A), total costs for the Gas Utility are projected to rise steadily through FY 2022.
Operations costs are projected to increase at 3% per year, though costs are projected to be
temporarily higher in FY 2016 through FY 2018 while the cross-bore program is being
completed (see Section 6A(3) below for more discussion). In addition, future ongoing CIP
spending is assumed to increase with inflation. Some uncertainty exists in the projection for CIP
costs due to high main replacement costs, as discussed in Section 6 A(4).
Although costs are increasing, lower CIP budgets in FY 2014 and FY 2015 have resulted in
healthy reserves and only moderate non-commodity rate increases are needed in upcoming
years.
2010 2011 2012 2013 2014
1
2 Utilities Retail Sales 43,244 42,855 41,034 33,759 34,843
3 Service Connection & Capacity Fees 451 516 592 731 654
4 Other Revenues & Transfers In 1,713 203 103 830 313
5 Interest plus Gain or Loss on Investment 1,342 821 1,119 (239)706
6 Total Sources of Funds 46,750 44,396 42,847 35,081 36,517
7
8 Purchases of Utilities:
9 Supply Commodity 21,846 20,732 15,356 12,461 12,992
10 Supply Transportation 620 706 879 994 1,333
11 Total Purchases 22,466 21,438 16,235 13,455 14,325
12
13 Administration (CIP + Operating)2,494 2,895 3,473 4,273 3,988
14 Customer Service 1,134 1,230 1,270 1,358 1,338
15 Demand Side Management 428 563 614 630 438
16 Engineering (Operating)266 280 333 340 352
17 Operations and Maintenance 3,942 3,297 5,032 4,940 4,119
18 Resource Management 696 1,039 729 506 516
19 Debt Service Payments 505 488 406 296 282
20 Rent 320 230 230 219 419
21 Transfers to General Fund 5,300 5,304 6,006 5,971 5,811
22 Other Transfers Out 407 614 170 207 606
23 Capital Improvement Programs 2,389 8,325 7,821 7,620 240
24 Total Uses of Funds 40,348 45,704 42,320 39,814 32,435
25
26 Into/ (Out of) Reserves 6,402 (1,308)528 (4,733)4,082
Fiscal Year
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Table 9: Seven Year Gas Financial Forecast Summary
*The rate change line shows the combined effect of commodity and non-commodity rate changes for FY 2013. For current and
future years, only non-commodity rate changes are shown. Commodity rates will vary monthly with market prices.
2. COMMODITY SUPPLY COS T S
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.
Commodity costs are expected to stay steady or decline slightly over the next several years.
Figure 5 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 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,12 but in December 2014 PG&E applied to the CPUC
to more than double local transportation costs. Staff is tracking PG&E’s application, and based
on discussions to date, expects that nearly all of the proposed increase in local transportation
costs will be approved. Staff projects these costs to escalate at 3% per year in subsequent
years. As these charges are dictated by PG&E and are outside of Palo Alto’s control, staff may
propose making these costs a pass-through charge, similar to the commodity charge, in FY 2016
or FY 2017.
12 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.
Actual Adopted Proj.Proj.Proj.Proj.Proj.Proj.Proj.Proj.
2014 2015 2015 2016 2017 2018 2019 2020 2021 2022
1 RATE CHANGE (%)*0%0%0%0%7%4%4%4%3%3%
2 SALES IN THOUSAND THERMS 28,117 28,881 27,895 28,939 28,995 29,060 29,110 29,160 29,200 29,243
3
4 Utilities Retail Sales 34,843 37,343 32,586 33,327 36,957 39,789 42,197 44,168 45,499 47,036
5 Service Connection & Capacity Fees 654 580 602 640 662 686 707 728 728 728
6 Other Revenues & Transfers In 313 554 1,022 1,620 1,919 2,255 2,623 2,999 3,355 3,689
7 Interest plus Gain or Loss on Investment 706 715 381 407 323 260 213 213 242 306
8 Total Sources of Funds 36,517 39,192 34,592 35,993 39,861 42,990 45,740 48,108 49,824 51,759
9
10 Purchases of Utilities:
11 Supply Commodity 12,992 12,484 10,385 10,723 11,980 13,108 13,778 14,139 14,436 14,848
12 Supply Transportation 1,333 1,248 2,053 2,706 2,982 3,186 3,221 3,225 3,245 3,279
13 Total Purchases 14,325 13,732 12,438 13,429 14,962 16,294 16,999 17,364 17,680 18,127
14
15 Administration (CIP + Operating)3,988 3,331 4,238 4,350 4,473 4,600 4,731 4,865 4,994 5,120
16 Customer Service 1,338 1,629 1,486 1,532 1,590 1,650 1,712 1,777 1,831 1,879
17 Demand Side Management 438 1,284 625 641 657 674 691 709 727 745
18 Engineering (Operating)352 450 367 378 392 406 421 436 449 461
19 Operations and Maintenance 4,119 4,250 4,366 5,497 5,686 5,884 5,086 5,272 5,430 5,571
20 Resource Management 516 976 947 1,276 1,464 1,678 1,914 2,146 2,369 2,586
21 Debt Service Payments 282 802 802 803 803 802 800 800 802 803
22 Rent 419 431 431 443 457 470 485 499 514 530
23 Transfers to General Fund 5,811 5,730 5,730 6,162 6,454 6,709 7,008 7,332 7,679 8,040
24 Other Transfers Out 606 472 486 499 511 524 537 550 564 578
25 Capital Improvement Programs 240 2,341 2,341 5,673 5,214 5,402 5,550 5,728 5,728 5,728
26 Total Uses of Funds 32,435 35,428 34,258 40,683 42,661 45,093 45,933 47,477 48,767 50,168
27
28 Into/ (Out of) Reserves 4,082 3,764 334 (4,690)(2,800)(2,102)(193)630 1,057 1,591
Fiscal Year
GAS UTILITY FINANCIAL PLAN
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Figure 5: Wholesale Gas Price Projections
3. OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance, Engineering, Resource Management, and Administration categories in Table 9,
above. Debt service, rent, and transfers are also included in Operations costs (excluding the
General Fund equity transfer). Appendix E includes detailed descriptions of the activities
associated with these cost categories. Operations costs are projected to increase by 3 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 2016 to FY 2018 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
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included $3 million in additional funding over the forecast period for this program, but the
program will likely require additional funding in future years to complete.
4. 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.
Table 10 shows the current status of these project categories and future projected spending.
Table 10: 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 5a (Background)
for more detail). CPAU has temporarily slowed down its new CIP appropriations in this category
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 plans to complete a Gas System Master Plan in 2015 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.
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
One Time Projects 192 (30) 162 - - - - - -
Gas Main Replacement 8,892 (3,099) 5,793 5,532 4,161 3,650 3,785 3,878 4,000
Tools And Equipment 407 (18) 389 64 100 100 100 100 100
Ongoing Projects 1,594 (205) 1,389 223 763 786 809 834 858
Customer Connections 752 (415) 337 3 950 979 1,008 1,038 1,069
TOTAL 11,837 (3,767) 8,070 5,822 5,974 5,514 5,702 5,850 6,028
*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).
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The current budget for gas main replacement assumes the current pace of main replacement,
but does not take into account the recent rise in costs for main replacement, which have
increased from the levels seen during the recent r ecession. 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.
Ongoing Projects, Tools and Equipment, and Customer Connections are projected to cost
approximately $1.8 million in FY 2016 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 2016 to FY 2020 is funded by utility rates. The details of the plan are shown in Appendix B:
Gas Utility Capital Improvement Program (CIP) Detail.
5. EQUITY TRANSFER
The City calculates the equity transfer from its Gas Utility based on a rate of return on the net
book value of the utility’s capital assets[1]. The Council adopted this methodology in 2009 and it
has remained unchanged since. Each year it is calculated according to the 2009 Council-
adopted methodology, and does not require additional Council action.
SECTION 6 B . REVENUE REQUIREMENT AND SOURCES
The Gas Fund’s costs and revenues from FY 2010 through FY 2022 are shown in Figure 6 below.
Rate changes in future years assume that the gas commodity prices remain at 2015 levels. This
is done to better highlight those rate component changes which the utility controls rather than
gas commodity costs, which are subject to market price variation and passed through directly
to customers monthly based on market prices. Revenues are projected to be lower than
expenses through FY 2018, with the utility drawing down the Rate Stabilization Reserve during
that time. In general, rates will need to increase 3% to 4% per year to match revenues to costs
and bring the Operations Reserve to Target levels by the end of the forecast period .
[1] 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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Reserves are adequate to avoid increasing gas rates until FY 2017, when a 7% increase is
projected. A 7% increase is equivalent to an additional $1.75 to $3.88 per month (summer and
winter) for the median residential customer’s monthly gas bill, based on commodity prices as of
February 2015. Future increases would be roughly half of these levels.
Figure 6: Gas Utility Revenue and Cost Projections
The proposed rate trajectory draws the Rate Stabilization Reserve down to zero by FY 2018, as
shown in Figure 7.
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Figure 7: Gas Utility Revenue and Cost Projections
SECTION 6 C . R ISK ASSESSMENT AND R ESERVE ADEQUACY
Staff performs an annual assessment of financial risks for the Gas Utility. For this evaluation,
staff estimates using the following criteria:
1. The maximum observed one-year distribution revenue variance over the past five years;
and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Commodity price risk is not included in the risk assessment because these costs are passed
directly to customers each month. Table 11 summarizes the risk assessment calculation for the
Gas Utility. The Operations Reserve is projected to be adequate to manage these levels of risk
over the entire forecast period.
Table 11: Gas Utility Risk Assessment ($000)
FY
2016
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
Total Revenue 21,314 22,253 23,564 24,991 23,373 26,340 28,010
Max. Historical Revenue Variance 5% 5% 5% 5% 5% 5% 5%
Budget-to-Actual Risk 1,079 1,127 1,193 1,107 1,266 1,334 1,418
System Rehabilitation CIP Budget 4,723 4,235 4,394 4,822 4,511 4,658 4,65
CIP Contingency @10% 472 424 439 482 451 466 466
Total Risk Assessment Value 1,552 1,550 1,633 1,589 1,717 1,800 1,884
Projected Operations Reserve Level 8,711 9,279 7,721 7,529 8,159 9,216 10,807
GAS UTILITY FINANCIAL PLAN
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The Gas Utility currently has one contingency reserve (the Operations Reserve), and this
Financial Plan maintains reserves within their approved guideline levels throughout the forecast
period, as shown in Figure 8 below. Reserve levels also exceed the short-term risk assessment
value for the utility.
Figure 8: Operations Reserve Adequacy
SECTION 6 D . ALTERNATE SCENARIOS
The forecast described in the previous sections assumes that gas main replacement costs are
about the same as they were in previous years. There is substantial uncertainty about this
assumption. Staff has created a separate CIP scenario in which main replacement budgets are
50% higher than the base forecast. As described in Section 6A (Seven Year Financial Forecast)
prices for the most recent main replacement projects have been nearly 50% higher than
previous projects. The current forecast assumes that these prices have been temporary spikes
due to the economy picking up, but that may not be the case. The “High CIP Cost” scenario
assumes that CPAU continues its current pace of main replacement and prices remain at these
higher levels.
Figure 9 shows the rate increases under the High CIP Cost scenario and the base case
(inflationary increases in CIP budgets). If this scenario becomes reality, it may be possible to
phase in the increase in CIP budgets over several years to defer the rate impact into later years.
CPAU will be developing a Gas System Master Plan, planned for later in 2015 or 2016. It will
give CPAU the information it needs to determine the feasibility of these types of strategies.
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Figure 9: Rate Increases for High CIP Scenario
SECTION 6 E . HISTORICAL AND PROJECTED CONSUMPTIO N
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions. As
shown in Figure 10, 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. Since 2011 usage has decreased by
almost 3% annually, with generally increasing gas rates encouraging conservation and spurring
energy efficiency investment. Gas usage was 28.8 million therms in FY 2014.
Gas consumption is projected to recover somewhat and stay stable over the forecast period,
with growth being offset by gas efficiency savings. Figure 10 presents the historical gas
consumption levels (with and without the gas energy efficiency (EE) programs) from FY 1971
through FY 2014 and projections for FY 2015 through FY 2023.
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Figure 10: Historic and Projected Gas Consumption
SECTION 6 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 t he 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.
As discussed in Section 6A (Seven Year Financial Forecasts), the future CIP investment needs for
the Gas Utility may be lower than in the past, although costs per foot for main replacement
may increase substantially. The Gas Utility has replaced 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 performing a study in
2015 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
27
29
31
33
35
37
39
41
43
45
47
Th
e
r
m
s
(
M
i
l
l
i
o
n
s
)
Purchases
Purchases without EE
Actual Forecast
GAS UTILITY FINANCIAL PLAN
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(GHG) emissions to 1990 levels by 2020 and then maintaining those reductions. 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. If stricter goals are
enacted at the state or local level, however, it could lead to “electrification”, or consumer
switching from gas-using appliances to electric-using appliances for heating, cooking and
processes. 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. One example of a stricter standard has been stated by the Governor—reducing GHG
emissions to 80 percent below 1990 levels by 2050.13 This goal, or less ambitious interim state
goals, would require legislation to implement. But 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.”14 Staff anticipates legislation this year to address the
Governor’s 2030 climate goals of 50% renewable generation, 50% reduction in transportation
fuels, and a doubling of energy efficiency. A few bills have already been introduced on post -
2020 GHG emission reduction goals and the GHG cap-and-trade market. As stewards of the Gas
Utility, the City should continue to stay aware of developments in state climate planning,
participate as a stakeholder, and consider these types of impacts and ways to mitigate them
when developing its own sustainability goals.
SECTION 6 G . COMMUNICATIONS PLAN
The FY 2016 communications strategy covers four primary areas: operations, infrastructure,
safety, efficiency, renewables and rates. CPAU has moved to market pricing for commodity
rates. Changes to the commodity rates are posted monthly on the City’s website. This year, in
light of the water and wastewater utility rate increases, CPAU is deferring any formal “rate
change” to the gas utility at this time, but website and community education about rates is
ongoing. 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 new campaigns and programs in FY 2016 to pro mote 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 Pa lo Alto compete for a $5 million
prize at the end of a two-year campaign. Since adoption of a carbon neutral electric supply
portfolio and retirement of the PaloAltoGreen program, CPAU launched a new voluntary
13 Executive Orders S-3-05 and B-16-2012.
14 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment , California Air
Resources Board, October 2013, pg 88.
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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 crossbores, 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
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 customer s 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.
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APPENDICES
Appendix A: Gas Utility Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Gas Utility Debt Service Details
Appendix E: Description of Gas Utility Cost Categories
Appendix F: Gas Utility Communications Samples
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APPENDIX A : GAS UTILITY FINANCIAL FORECAST D ETAIL
Actual Adopted Proj.Proj.Proj.Proj.Proj.Proj.Proj.Proj.
2014 2015 2015 2016 2017 2018 2019 2020 2021 2022
1 RATE CHANGE (%)*0%0%0%0%7%4%4%4%3%3%
2 SALES IN THOUSAND THERMS 28,117 28,881 27,895 28,939 28,995 29,060 29,110 29,160 29,200 29,243
3
4 Utilities Retail Sales 34,843 37,343 32,586 33,327 36,957 39,789 42,197 44,168 45,499 47,036
5 Service Connection & Capacity Fees 654 580 602 640 662 686 707 728 728 728
6 Other Revenues & Transfers In 313 554 1,022 1,620 1,919 2,255 2,623 2,999 3,355 3,689
7 Interest plus Gain or Loss on Investment 706 715 381 407 323 260 213 213 242 306
8 Total Sources of Funds 36,517 39,192 34,592 35,993 39,861 42,990 45,740 48,108 49,824 51,759
9
10 Purchases of Utilities:
11 Supply Commodity 12,992 12,484 10,385 10,723 11,980 13,108 13,778 14,139 14,436 14,848
12 Supply Transportation 1,333 1,248 2,053 2,706 2,982 3,186 3,221 3,225 3,245 3,279
13 Total Purchases 14,325 13,732 12,438 13,429 14,962 16,294 16,999 17,364 17,680 18,127
14
15 Administration (CIP + Operating)3,988 3,331 4,238 4,350 4,473 4,600 4,731 4,865 4,994 5,120
16 Customer Service 1,338 1,629 1,486 1,532 1,590 1,650 1,712 1,777 1,831 1,879
17 Demand Side Management 438 1,284 625 641 657 674 691 709 727 745
18 Engineering (Operating)352 450 367 378 392 406 421 436 449 461
19 Operations and Maintenance 4,119 4,250 4,366 5,497 5,686 5,884 5,086 5,272 5,430 5,571
20 Resource Management 516 976 947 1,276 1,464 1,678 1,914 2,146 2,369 2,586
21 Debt Service Payments 282 802 802 803 803 802 800 800 802 803
22 Rent 419 431 431 443 457 470 485 499 514 530
23 Transfers to General Fund 5,811 5,730 5,730 6,162 6,454 6,709 7,008 7,332 7,679 8,040
24 Other Transfers Out 606 472 486 499 511 524 537 550 564 578
25 Capital Improvement Programs 240 2,341 2,341 5,673 5,214 5,402 5,550 5,728 5,728 5,728
26 Total Uses of Funds 32,435 35,428 34,258 40,683 42,661 45,093 45,933 47,477 48,767 50,168
27
28 Into/ (Out of) Reserves 4,082 3,764 334 (4,690)(2,800)(2,102)(193)630 1,057 1,591
29
30 Reappropriations + Commitments 11,194 11,305 9,817 9,817 9,817 9,817 9,817 9,817 9,817 9,817
31 Plant Replacement 0 0 0 0 0 0 0 0 0 0
32 CIP Reserve 0 0 1,488 1,488 1,488 1,488 1,488 1,488 1,488 1,488
33 Rate Stabilization 8,598 8,598 8,884 3,913 545 0 0 0 0 0
34 Operations Reserve 8,382 8,382 8,429 8,711 9,279 7,721 7,529 8,159 9,216 10,807
35 Unassigned 0 0 0 0 0 0 0 0 0 0
36 Total Reserves 28,174 28,285 28,619 23,929 21,129 19,026 18,834 19,464 20,521 22,112
37 (3,507)445 (4,690)(2,800)(2,102)(193)630 1,057 1,591
38 Short Term Risk Assessment Value 1,226 1,552 1,550 1,633 1,717 1,800 1,836 1,884
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M)5,588 5,620 5,620 5,807 6,186 6,529 6,613 6,810 6,994 7,196
42 Target (60 Days Commodity + O&M)8,382 8,429 8,429 8,711 9,279 9,793 9,920 10,214 10,490 10,794
43 Max (60 Days Commodity + O&M)11,176 11,239 11,239 11,614 12,372 13,057 13,227 13,619 13,987 14,392
44
Fiscal Year
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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 2016 FY 2017 FY 2018 FY 2019 FY 2020
ONE TIME PROJECTS
GS-09000 Gas Station 1 Rebuild 6,630 - - - 6,630 - - - - - -
GS-08000 Gas Station 2 Rebuild 10,023 - - - 10,023 - - - - - -
GS-10000 Gas Station 3 Rebuild 8,489 - - (30,125) (21,636) - - - - - -
GS-11001 Gas Station 4 Rebuild 16,898 - - - 16,898 - - - - - -
GS-13003 COBUG emissions equipment - - - - - - - - - - -
GS-15001 Security at Receiving Stations - 150,000 - - 150,000 - - - - - -
Subtotal, One-time Projects 42,040 150,000 - (30,125) 161,915 - - - - - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-08011 GMR - Project 18 10,531 - - - 10,531 - - - - - -
GS-09002 GMR - Project 19 1,683,181 - - (1,072,730) 610,451 1,135,565 - - - - -
GS-10001 GMR - Project 20 4,280,658 - - (1,570,222) 2,710,436 2,956,030 - - - - -
GS-11000 GMR - Project 21 2,314,845 - - (452,823) 1,862,022 1,396,378 - - - - -
GS-12001 GMR - Project 22 - 603,000 - (3,579) 599,421 43,854 3,540,000 - - - -
GS-13001 GMR - Project 23 - - - - - - 621,000 3,010,000 - - -
GS-14003 GMR - Project 24 - - - - - - - 640,000 3,100,000 - -
GS-15000 GMR - Project 25 - - - - - - - - 685,000 3,200,000 -
GS-16000 GMR - Project 26 - - - - - - - - 678,000 3,300,000
GS-20000 GMR - Project 27 - - - - - - - - - 700,000
Subtotal, Gas Main Replacement Program 8,289,216 603,000 - (3,099,354) 5,792,862 5,531,827 4,161,000 3,650,000 3,785,000 3,878,000 4,000,000
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools 48,062 100,000 - (13,957) 134,105 - 100,000 100,000 100,000 100,000 100,000
GS-01019 Global Positioning System 80,306 - - (3,887) 76,419 2,810 - - - - -
GS-02013 Directional Boring Machine 413 - - - 413 - - - - - -
GS-03007 Directional Boring Equipment 408 - - - 408 - - - - - -
GS-03008 Polyethylene Fusion Equip.29,168 - - - 29,168 - - - - - -
GS-14004 Gas Distribution System Model 148,608 - - - 148,608 60,918 - - - - -
Subtotal, Tools and Equipment 306,965 100,000 - (17,844) 389,121 63,728 100,000 100,000 100,000 100,000 100,000
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Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
ONGOING PROJECTS
GS-11002 Gas System Improvements 266,770 219,000 - (186,693) 299,077 222,990 225,000 232,000 239,000 246,000 253,417
GS-03009 System Ext. - Unreimbursed 150,595 183,500 - (17,971) 316,124 - 192,675 198,500 204,455 211,000 216,908
GS-80019 Gas Meters and Regulators 438,837 335,000 - - 773,837 - 345,000 355,000 366,000 377,000 387,952
Subtotal, Ongoing Projects 856,202 737,500 - (204,664) 1,389,038 222,990 762,675 785,500 809,455 834,000 858,277
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions (127) 752,000 - (415,114) 336,759 3,000 950,000 978,500 1,007,855 1,038,091 1,069,234
Subtotal, Customer Connections (127) 752,000 - (415,114) 336,759 3,000 950,000 978,500 1,007,855 1,038,091 1,069,234
GRAND TOTAL 9,494,296 2,342,500 - (3,767,101) 8,069,695 5,821,545 5,973,675 5,514,000 5,702,310 5,850,091 6,027,511
Funding Sources
Connection Fees 602,000 - 639,600 662,000 686,360 861,000 728,159
Utility Rates 893,200 - 5,334,075 5,334,075 5,334,075 5,334,075 5,334,075
CIP-RELATED RESERVES DETAIL
6/30/2014
(Actual)12/31/2014
Reappropriations 1,488,296 2,248,150
Commitments 8,006,000 5,821,545
GAS UTILITY FINANCIAL PLAN
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APPENDIX C : GAS UTILITY RESERVES MANAGEMENT PRACTICES
(Amendments to this section are proposed. See the proposed resolution adopting this Financial
Plan. This section will be added to the Financial Plan following adoption of any amendments to
this section.)
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APPENDIX D : GAS UTILITY DEBT SERVICE DETAILS
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
2015
FY
2016
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
2011 Utility
Revenue Refunding
Bonds, Series A
802 803 803 802 800 800 802 803
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
2015
FY
2016
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
Revenues 34,592 35,993 39,861 42,990 45,740 48,108 49,824 51,759
Expenses
(Excluding CIP
and Debt Service)
(31,114) (34,207) (36,645) (38,889) (39,584) (40,950) (42,237) (43,637)
Net Revenues 3,478 1,786 3,216 4,101 6,156 7,158 7,587 8,122
Debt Service 802 803 803 802 800 800 802 803
Coverage Ratio 434% 222% 400% 511% 770% 895% 946% 1011%
Table 14: Debt Service Minimum Reserves ($000)
FY 2015 FY
2016
FY
2017
FY
2018
FY
2019
FY
2020
FY
2021
FY
2022
Gas Utilitya 18,802 14,112 11,312 9,209 9,017 9,647 10,704 12,295
Debt Serviceb 803 804 803 802 801 801 802 803
Reserves Ratioc 23x 18x 14x 11x 11x 12x 13x 15x
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.
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
GAS UTILITY FINANCIAL PLAN
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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
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APPENDIX E : 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 F : GAS UTILITY COMMUNIC ATIONS SAMPLES
Page 1 of 4
5
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: April 1, 2015
SUBJECT: Staff Recommendation that the Utilities Advisory Commission Recommend
that the City Council Adopt a Resolution Approving the Fiscal Year 2016 Electric
Financial Plan, Including no Recommended Rate Changes for July 1, 2015, and
Amending the Electric Utility Reserve Management Practices
REQUEST
Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council adopt
a resolution (Attachment A) amending the Electric Utility Reserve Management Practices
(Attachment B) and approving the fiscal year (FY) 2016 Electric Financial Plan (Attachment C).
EXECUTIVE SUMMARY
The FY 2016 Electric Utility Financial Plan includes projections of the utility’s costs and revenues
through FY 2023. Costs are projected to rise substantially for the next several years due
primarily to increasing costs for electric supply purchases as a result of new renewable energy
projects coming online. Increases in transmission costs are also projected. No rate increases
are proposed for FY 2016, but a 6% rate increase is projected for FY 2017 and another 6%
increase for FY 2018. Staff is also proposing two reserves transfers to the Supply Operations
Reserve: $11 million from the Hydro Stabilization Reserve in FY 2015, and $9 million from the
Supply Rate Stabilization Reserve in FY 2016. The Hydro Stabilization Reserve is intended to be
used during periods of low hydroelectric generation such as FY 2015, and the Supply Rate
Stabilization Reserve is being drawn down to allow the City to complete a cost of service study
before its next rate change. Even after the recommended transfers from reserves, reserve
levels are, and will remain, adequate to manage contingencies.
Staff also recommends a change to the Electric Utility Reserves Management Practices for the
Capital Improvement Project (CIP) Reserve to accommodate a change in City budgeting
practices for CIP projects.
Page 2 of 4
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. Staff may propose
amendments to these reserves as part of the Financial Plans.
DISCUSSION
Proposed Actions for FY 2015
When Council adopted the FY 2015 Electric Utility Financial Plan, it approved several transfers
between reserves. Funds were transferred out of the Emergency Plant Replacement and Rate
Stabilization Reserve into the newly-created CIP and Operations Reserves. These transfers were
mainly related to setting up the new reserves structu re approved as part of that Financial Plan.
Now, staff recommends an additional transfer for FY 2015, a transfer of $11 million from the
Hydro Stabilization Reserve to the Operations Reserve, leaving it with $17 million remaining at
the end of FY 2015 (an adequate level for insuring against contingencies). This is to fund
additional commodity supply costs resulting from the drought. Generation from hydroelectric
resources was low due to the drought forcing CPAU to buy additional power in the electricity
markets to make up for the reduced hydroelectric generation. These purchases of additional
power are projected to result in roughly $11 million in additional costs in FY 2015.
Proposed Actions for FY 2016
This year’s Electric Utility Financial Plan includes the following proposed actions for FY 2016:
1. Amend the CIP Reserve to accommodate a change in the City’s capital budgeting
practices. These amendments are summarized below, but for a more in-depth
description of the reasons for these amendments, see Sectio n 4C of the Financial Plan:
a. Modify the purpose of the CIP Reserve to enable it to act as a cash flow and
contingency reserve for capital investment projects by amending the Reserves
Management Practices.
b. At the end of FY 2015, transfer funds projected to be released from the
Reappropriations Reserve (due to a change in City capital budgeting practices) to
the CIP Reserve .
2. Transfer $9 million from the Supply Rate Stabilization Reserve to the Supply Operations
Reserve. This transfer will enable staff to maintain Supply Operations Reserve levels
above the guideline levels until rates are changed in FY 2017.
These proposed actions are described in more detail in the FY 2016 Water Financial Plan
(Attachment B).
Page 3 of 4
Staff is not proposing any rate changes for the Electric Utility in FY 2016, but is beginning an
electric cost of service study as preparation to proposing to change rates in FY 2017. Staff will
have policy discussions with the UAC and Council to identify policy objectives for the study.
Table 1 shows the projected rate adjustments included in the FY 2016 Electric Utility Financial
Plans and their impact on the median residential electric bill.
Table 1: Projected Electric Rate Adjustments, FY 2016 to FY 2020
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Forecasted Rate Changes 0% 6% 6% 1% 1%
Estimated Bill Impact ($/mo)* $0.00 $2.69 $2.80 $0.38 $0.72
* estimated impact on median residential electric bill, which is currently $42.76.
Table 2 shows the proposed and projected rate adjustments in the context of the other
proposed and projected utility rates.
Table 2: Rate Adjustments, All Utilities, FY 2016 Proposed, FY 2017 to FY 2020 Projected
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Electric 0% 6% 6% 1% 1%
Gas1 0% 7% 4% 4% 4%
Wastewater 9% 9% 9% 9% 6%
Water 12% 8% 8% 8% 3%
Refuse2 9% 9% 8% 2% to 3% 2% to 3%
Storm Drain3 2.7% 2% to 3% 2% to 3% 2% to 3% 2% to 3%
Total Bill
Change4
(%) 6% 8% 7% 5% 3%
($/mo) $14.73 $18.91 $18.53 $14.39 $9.55
(1) Gas rate changes are shown with commodity rates held constant. Actual gas commodity rates will vary monthly
with wholesale market fluctuations
(2) No forecast available past FY 2018, inflationary increases assumed.
(3) Storm Drain Rates increase annually by CPI; existing rates sunset in June 2017 unless reauthorized by a majority
vote of property owners.
(4) Change in estimated median residential bill, $230.76 as of June 30, 2014
The main driver for the increase in the electric utility’s costs (and therefore rates) over the next
several years is the cost of new renewable projects coming online. Electricity purchase costs
began increasing starting in FY 2013 and will continue to increase through FY 2018 a s new
renewable projects come online to fulfill the City’s Council-approved environmental goals. The
remaining costs for the electric utility are not projected to increase as quickly. Operations costs
are expected to increase at or below inflation through the forecast period. Capital investment
costs are also expected to increase at only an inflationary rate, except for costs associated with
installing smart grid technologies. This forecast assumes that those smart grid costs are funded
from the Electric Special Projects Reserves, though this will require action by the City Council
before such funding can occur.
Changes from Preliminary Financial Forecast
The UAC reviewed preliminary financial forecasts for the Electric Utility at its February 4, 2015
meeting. Staff made minor adjustments to the pattern of electric rate increases for FY 2017
through FY 2020 based on revised assessments of reserve levels, but the cumulative increase to
rates over that period is nearly identical to the preliminary financial forecast.
NEXT STEPS
After rece i ving the UAC's recommendation, the Finance Committee will review the FY 2016
Electric Financial Plan on April 21, 2015. The City Council will consider its adoption with the FY
2016 budget.
RESOURCE IMPACT
Because no rate changes are proposed for FY 2016, there are no projected resource impacts
associated with this Financial Plan.
POLICY IMPLICATIONS
The attached Financial Plan includes amended Reserve Management Practices that will modify
Council policy with respect to the structure of the financial reserves of the Electric Utility.
These Reserve Management Practices replace the current Reserve Management Practices,
which were last adopted by Council in June 2014 (Resolution 9423).
ENVIRON M ENTAL REVIEW
The UAC's review and recommendation to Council on this Financial Plan 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 2016 Electric Utility
Financial Plan and Amending the Electric Utility Reserves Management Practices
B. Amended Electri c Utility Reserves Management Practices
C. Proposed FY 2016 Electric Utility Financial Plan
PREPARED BY:
REVIEWED BY:
APPROVED BY:
JONATHAN ABENDSCHEIN, Senior Resource Planner/7
ERIC KEN ISTON, Resource Planner
~ANE RATCHYE, Assistant Director, Resource Management VA-G
Director of Utilities
Page 4of4
Attachment A
* NOT YET APPROVED *
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2016 Electric Utility Financial Plan and Amending the Electric
Utility Reserves Management Practices
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.
C. The City intends to make changes to its Electric Utility Reserves Management
Practices to amend the purpose and management practices of the Electric Utility’s Capital
Improvement Program (CIP) Reserve.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the FY 2016 Electric Utility Financial Plan,
including the amended Electric Utility Reserves Management Practices. These Reserves
Management Practices replace the Reserves Management Practices previously approved for
the Electric Utility as part of the FY 2015 Electric Utility Financial Plan (Resolution 9423).
SECTION 2. The Council hereby approves the transfer of $11 million in FY 2015 from
the Hydro Stabilization Reserve to the Operations Reserve, the transfer of all funds released in
FY 2015 from the Reappropriations Reserve to the CIP Reserve, and the transfer of $9.0 million
in FY 2016 from the Rate Stabilization Reserve to the Operations Reserve, as described in the FY
2016 Electric Utility Financial Plan approved via this resolution.
/ /
/ /
/ /
150316 sdl 6053271
Attachment A
* NOT YET APPROVED *
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
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DRAFT Proposed Amendments to Electric Utility Reserves Management Practices
APPENDIX C : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
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 and capital 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 hydroe lectric
resources, as described in Section 7 (Hydro Stabilization Reserve)
e)For rate stabilization, as described in Section 11 (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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DRAFT Proposed Amendments to Electric Utility Reserves Management Practices
e) For cash flow management and contingencies related to the future year expenditure on
the Electric Utility’s Capital Improvement Program (CIP), as described in Section 10 (CIP
Reserve)
f) For rate stabilization, as described in Section 11 (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 below 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. Hydro Stabilization Reserve
DRAFT Proposed Amendments to Electric Utility Reserves Management Practices
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 Hydro
Stabilization Reserve by action of the City Council and held to offset higher commodity
supply costs during years of lower than average generation. Withdrawal of funds from the
Hydro 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 Benefit s
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 6 months of budgeted CIP expense
Maximum Level 12 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.
DRAFT Proposed Amendments to Electric Utility Reserves Management Practices
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds
may be added to this reserve. If there are funds in this reserve in excess of the
maximum level staff must propose to transfer these funds to another reserve or return
them to ratepayers in the next Financial Plan. Staff may also seek City Council to
approve holding funds in this reserve in excess of the maximum level if they are held for
a specific future purpose related to the CIP.
Funds may be added to the Electric Distribution Fund CIP Reserve by action of the City
Council and held for future year expenditure on the Electric Utility’s CIP Program.
Withdrawal of funds from the CIP Reserve requires City Council ac tion. If there are funds in
the CIP 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 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 Section 11 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
DRAFT Proposed Amendments to Electric Utility Reserves Management Practices
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 and commodity expense commodity
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 le vel 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 pre sent 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 shal l be
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
DRAFT Proposed Amendments to Electric Utility Reserves Management Practices
Transfers between Electric Distribution Fund Reserves an d 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
FY 2016 TO FY 20 23
CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 3
Section 2: Introduction .......................................................................................................... 4
Section 3: Executive Summary and Recommendations ........................................................... 4
Section 3A: Overview of Financial Position .................................................................................. 4
Section 3B: Summary of Proposed Actions .................................................................................. 5
Section 4: Detail of FY 2016 Rate and Reserves Proposals ....................................................... 5
Section 4A: Current Rates ............................................................................................................ 5
Section 4B: Reserves Management Practices, Proposed Change ................................................ 6
Section 4C: Proposed Reserve Transfers ...................................................................................... 7
Section 5: Utility Overview .................................................................................................... 8
Section 5A: Electric Utility History ............................................................................................... 8
Section 5B: Customer Base ........................................................................................................ 10
Section 5C: Distribution System ................................................................................................. 10
Section 5D: Cost Structure and Revenue Sources ...................................................................... 10
Section 5E: Reserves Structure ................................................................................................... 11
Section 5F: Competitiveness ...................................................................................................... 13
Section 6: Utility Financial Projections ................................................................................. 14
Section 6A: Load Forecast .......................................................................................................... 14
Section 6B: FY 2009 to FY 2014 Cost and Revenue Trends ........................................................ 16
Section 6C: FY 2014 Results ....................................................................................................... 16
Section 6D: FY 2015 Projections ................................................................................................ 17
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Section 6E: FY 2016 – FY 2023 Projections ................................................................................ 18
Section 6F: Risk Assessment and Reserves Adequacy ............................................................... 20
Section 6G: Alternate Scenario .................................................................................................. 23
Section 6H: Long-Term Outlook ................................................................................................. 26
Section 7: Details and Assumptions ..................................................................................... 27
Section 7A: Electricity Purchases ............................................................................................... 27
Section 7B: Operations .............................................................................................................. 29
Section 7C: Capital Improvement Program (CIP) ....................................................................... 30
Section 7D: Debt Service ............................................................................................................ 31
Section 7E: Equity Transfer ........................................................................................................ 32
Section 7F: Wholesale Revenues and Other Revenues .............................................................. 32
Section 7G: Sales Revenues ....................................................................................................... 33
Section 8: Communications Plan .......................................................................................... 33
Appendices ......................................................................................................................... 34
Appendix A: Electric Utility Financial Forecast Detail ................................................................ 36
Appendix B: Electric Utility Capital Improvement Program (CIP) Detail ................................... 40
Appendix C: Electric Utility Reserves Management Practices ................................................... 36
Appendix D: Rate Design ........................................................................................................... 43
Appendix E: Electric Utility Debt Service Details ........................................................................ 44
Appendix F: Description of Electric Utility Operational Activities .............................................. 45
Appendix G: Samples of Recent Electric Utility Outreach Communications .............................. 46
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SECTION 1 : DEFINITIONS AND ABBR EVIATIONS
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
Subtransmission 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.
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SECTION 2 : INTRODUCTION
This document presents a Financial Plan for the City’s Electric Utility for the next eight 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 3 : EXECUTIVE SUMMARY AND RECOMMENDATIONS
SECTION 3 A : OVERVIEW OF FINANC IAL POSITION
The Electric Utility’s costs will increase moderately 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 2014 to FY 2023
Expenses
($000)
FY 2014
(actual)
FY 2015
(est.) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Elec. Supply
Purchases 68,089 80,012 71,971 71,799 73,296 73,033 72,800 74,513 75,850 76,078
Operations 44,761 45,818 46,549 47,187 48,043 48,773 49,690 50,491 51,298 52,955
Capital
Projects 13,016 12,711 11,442 13,584 14,771 15,675 16,129 16,596 17,076 17,570
TOTAL 125,867 138,541 129,962 132,570 136,110 137,482 138,619 141,600 144,225 146,603
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. No increases are proposed for
Fiscal Year (FY) 2016.
Table 2: Projected Electric Rate Trajectory for FY 2016 to FY 2023
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
0% 6% 6% 1% 1% 0% 0% 2%
This Financial Plan projects that the Rate Stabilization Reserves will be exhausted by the end of
FY 2016. Table 3 shows the projected reserve transfers over the forecast period. 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. 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.
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Table 3: Reserves Transfers for FY 2016 to FY 2023 ($000)
Reserve FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Electric Special
Projects - (333) (333) (1,000) (1,000) (1,000) (1,000) (1,000)
Supply Rate
Stabilization (9,000) - - - - - - -
Supply
Operations (9,000) 333 333 1,000 1,000 1,000 1,000 1,000
SECTION 3 B : SUMMARY OF PROPOSED ACTIONS
Staff proposes the following action for the Electric Utility in FY 2015:
1. Transfer $11 million from the Hydro Stabilization Reserve to the Supply Operations
Reserve in FY 2015 to offset costs associated with low hydroelectric generation. See
Section 4C (Proposed Reserve Transfers) for more details.
Staff proposes the following actions for the Electric Utility in FY 2016:
1. Transfer $9.0 million from the Supply Rate Stabilization Reserve to the Supply
Operations Reserve in FY 2016. See Section 4C (Proposed Reserve Transfers) for more
details.
2. Take the following measures with respect to the CIP Reserve (see Section 4B (Reserves
Management Practices, Proposed Change) for more details):
a. Amend the Reserves Management Practices to modify the purpose of the CIP
Reserve to enable it to act as a cash flow and contingency reserve for capital
investment projects.
b. Transfer all funds released from the Reappropriations Reserve at the beginning
of FY 2016 to the CIP Reserve.
SECTION 4 : DETAIL OF FY 2016 RA TE AND RESERVES PROP OSALS
SECTION 4 A : CURRENT RATES
The current rates were adopted on July 1, 2009, when CPAU increased electric rates by 10%.
Table 4, below, summarizes the current 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.
Another specialty rate is the E-18 municipal electric rate. No changes are proposed to any of the
electric rates for FY 2016.
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Table 4: Current Electric Rates (Adopted July 1, 2009)
Rate Component Units
E-1
(Residential)
E-2 (Small
Commercial)
E-4 (Med.
Commercial)
E-7 (Large
Commercial)
Demand (Summer) $/kW N/A N/A 20.54 18.97
Demand (Winter) $/kW N/A N/A 13.84 11.54
Energy (Summer)
Tier 1 $/kWh 0.09524 0.14045 0.08171 0.07808
Tier 2 $/kWh 0.13020 N/A N/A N/A
Tier 3 $/kWh 0.17399 N/A N/A N/A
Energy (Winter)
Tier 1 $/kWh Same as
summer
energy
0.12661 0.07318 0.07209
Tier 2 $/kWh N/A N/A N/A
Tier 3 $/kWh N/A N/A N/A
Tier amounts:
Tier 1 kWh/day 0-10 N/A N/A N/A
Tier 2 kWh/day 10-20 N/A N/A N/A
Tier 3 kWh/day >20 N/A N/A N/A
SECTION 4 B : RESERVES MANAGEMENT PRACTICES, PROPOSED CHANGE
Staff is proposing one change to the Electric Utility Reserves Management Practices
(Appendix C) in this Financial Plan. Staff recommends changing the CIP Reserve definition and
management practices so that it becomes a cash flow and conti ngency reserve for CIP projects.
Currently these purposes are served by a combination of the Operations and Reappropriations
Reserves, while the CIP Reserve acts as a sinking fund to accumulate funds for large one -time
future CIP expenditures (which are rare). The City is changing its budgeting practices starting
with FY 2016, and will no longer reappropriate CIP budgets each year. Instead, CIP budgets for
long-term or ongoing projects will be renewed each year through the annual budget process.
This means that the funds in the Reappropriations Reserve ($8.7 million as of June 30, 2014)
will be released after June 30, 2015. These funds acted as a cash flow reserve for CIP projects,
and some or all of it should be retained for that purpose. Staff proposes to retain these funds in
the CIP reserve, and the proposed changes to the Reserves Management Practices will enable
CPAU to do that.
Staff proposes to initially set a minimum and maximum guideline for the CIP reserve that will
enable it to hold similar amounts to what has typically been held in the Reappropriations
Reserve. Staff then intends to review capital reserve management practices at other agencies
and revisit these guideline levels. Initially, staff proposes a minimum guideline level of
six months of CIP expenditures. CIP-related funds in the Commitments Reserve would be
allowed to count toward that guideline. The CIP-related funds in the Commitments Reserve are
equal to the total remaining balance of all CIP contracts currently in progress, and these funds
should be taken into account when determining whether CIP cash flow and contingency
reserves are adequate. The initial maximum guideline level would be twelve months of CIP
expenditures, but the maximum guideline could be temporarily exceeded with Co uncil
approval.
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Figure 1 shows the Reappropriations Reserve level as of June 30, 2014, as well as the CIP
portion of the Reserve for Commitments. The proposed minimum and maximum guidelines
over the forecast period are also shown.
Figure 1: Capital Reserve
SECTION 4 C : PROPOSED RESERVE TRA NSFERS
In the FY 2015 Electric Financial Plan several transfers between reserves were approved . Funds
were transferred out of the Emergency Plant Replacement, Supply Rate Stabilization,
Distribution Rate Stabilization Reserve, and Central Valley Project Reserves into the newly-
created Hydro Stabilization Reserve and Supply and Distribution Operations Reserves. These
transfers were mainly related to setting up the new reserves structure that was approved by
Council in June 2014. Now, in addition to these previously approved transfers, staff
recommends one additional transfer for FY 2015, a transfer of $11 million from the Hydro
Stabilization Reserve, leaving it with $17 million remaining at the end of FY 2015. This is to fund
additional commodity supply costs resulting from the drought. See Section 6D (FY 2015
Projections) for more information.
For FY 2016, staff proposes a $9 million transfer from the Supply Rate Stabilization Reserve to
the Supply Operations Reserve. This transfer will enable staff to maintain Supply Operations
Reserve levels within guideline levels while completing a cost of service study in anticipation of
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a 2016 rate increase. This will leave the Supply Rate Stabilization Reserve nearly empty. As
mentioned in Section 5E (Reserves Structure), this reserve is intended to be empty unless it
contains funds to be used in future years to spread large single-year rate increases across
multiple years.
In addition, staff is proposing transfers from the Reappropriations Reserve to the CIP Reserve as
described in the previous section. 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), as well as
in Appendix A (Electric Utility Financial Forecast Detail).
SECTION 5 : UTILITY OVERVIEW
This section provides an overview of the utility and its operations. It is inte nded as general
background information to help readers better understand the forecasts in Sections 6 and 7.
SECTION 5 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.
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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 replace ment
program for its underground system in the early 1990s.
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
Utility1 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 pr oject 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 managing 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 co mmencing deliveries in 2005. In 2011 the
renewable energy goal was increased to 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
hydroelectric supplies, purchases of long-term renewable energy supplies, and short-term
renewable energy purchases (RECs) to meet the balance of its needs.
1 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997
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Figure 2: Cost Structure (FY 2014)
SECTION 5 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 29,300 customers connected to the
electric system, 26,400 (90%) of which are residential and 2900 (10%) of which are non-
residential. Residential customers consumed 182 gigawatt-hours (GWh) in FY 2014,
approximately 19% of the electricity sold, while non-residential customers consumed 81% or
768 GWh. Residential customers use electricity primarily for lighting, refrigeration, electronics,
and air conditioning.2 Non-residential customers use the majority of their electricity for cooling,
ventilation, lighting, office equipment (offices), cooking (restaurants), and refrigeration (grocery
stores).3
Large customer loads represent a larger proportion of sales for the Electric Utility they do for
the City’s other utilities. The largest customers (the 66 customers on the E -7 rate schedule)
account for over 40% of CPAU’s sales. The next largest customer group (the 740 customers on
the E-4 rate schedule) represents another 32% of sales. In total, that means that less than 3% of
customers account for nearly three quarters of the electric load.
SECTION 5 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 asso ciated poles, meters, and
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto.
SECTION 5 D : COST STRUCTURE AND R EVENUE SOURCES
As shown in Figure 2, electric commodity
purchases accounted for roughly 52% of
the Electric Utility’s costs in FY 2014.
Operational costs represented roughly
34%, and capital investment was
responsible for the remaining 10%. CPAU’s
non-hydro long-term commodity supply is
heavily dependent on long term contracts
which have little variability in price. On
2 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010
3 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006.
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Figure 4: Revenue Structure (FY 2014)
Figure 3: Hydro Variability (FY 2016)
0%
20%
40%
60%
80%
100%
120%
140%
Low
Hydro
Average High
Hydro
Surplus
Hydro (sales)
Market
Power/RECs
Hydro
Renewables
Load
average, 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 47% of total costs in FY 2023.
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, average, and low
hydroelectric generation scenarios. The
most recent risk assessment estimates
the additional cost associated with a very
low generation scenario to be as much as
$11 million (see Section 6F (Risk
Assessment and Reserves Adequacy).
The Electric Utility receives 85% 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 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 93% 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 5B (Customer
Base), nearly three quarters of the utility’s
electricity sales are to the 800 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 25% of the
utility’s revenue comes from peak demand
charges on large commercial 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 5 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
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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 C (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 4B (Reserves Management Practices, Proposed Change).
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
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.
Hydro 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. 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 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 Financial Plan
proposes adding an additional purpose, making it a cash flow and contingency reserve
for the CIP. This would change the way the reserve is managed, as described in Section
4B (Reserves Management Practices, Proposed Change). 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
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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.
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 2015 to FY 2023
Ending Reserve
Balance
($000) FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
Reappropriations 0 0 0 0 0 0 0 0 0
Commitments 3,164 3,164 3,164 3,164 3,164 3,164 3,164 3,164 3,164
Underground Loan 734 734 734 734 734 734 734 734 734
Public Benefits 1,771 1,384 942 401 30 0 0 0 0
Special Projects 51,838 51,838 51,505 51,171 50,171 49,171 48,171 47,171 46,171
Hydro Stabilization 17,000 17,000 17,000 17,000 17,000 17,000 17,000 17,000 17,000
Capital 0 8,715 8,715 8,715 8,715 8,715 8,715 8,715 8,715
Rate Stabilization 9,000 0 0 0 0 0 0 0 0
Operations 29,098 28,148 24,392 24,819 28,324 32,764 34,749 35,087 36,043
Unassigned 0 0 0 0 0 0 0 0 0
TOTAL 112,605 110,982 106,452 106,005 108,139 111,548 112,533 111,872 111,827
SECTION 5 F : COMPETITIVENESS
For the median consumption level the annual residential electric bill for calendar year 2014 was
$513.17 under current CPAU rates, 26% lower than the annual bill for a PG&E customer with
the same consumption and 3% lower than 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
below were in effect as of January 1, 2015. Over the next several years low usage customers in
PG&E territory are expected 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
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more favorable compared to most PG&E customers. Even with the com pressed tiers, bills for
high usage Palo Alto consumers are likely to remain substantially lower than the bills for high
usage PG&E customers.
Table 6: Residential Monthly Electric Bill Comparison (Effective 1/1/15, $/mo)
Season Usage (kwh) Palo Alto PG&E Santa Clara
Winter
(December)
300 28.57 48.51 33.49
(Median) 453 48.49 78.64 51.19
650 76.33 132.46 73.99
1200 172.03 315.49 137.63
Summer
(July)
300 28.57 48.51 33.49
(Median) 365 37.04 60.46 41.01
650 76.33 138.42 73.99
1200 172.03 321.69 137.63
Table 7 shows the average monthly electric bill for commercial customers for various usage
levels. Bills for small commercial customers in Palo Alto are 34% below what they would be in
PG&E territory and 21% below what they would be in Santa Clara (Silicon Valley Power). For
large commercial customers, rates are about 30% below PG&E’s and are 5% to 10% lower than
Santa Clara’s.
Table 7: Commercial Monthly Electric Bill Comparison (1/1/15, $/mo)
Usage (kwh/mo) Palo Alto PG&E Santa Clara
1,000 134 203 168
160,000 18,364 26,722 19,488
500,000 43,319 64,772 48,565
2,000,000 216,594 304,320 236,295
SECTION 6 : UTILITY FINANCIAL PROJECTIONS
SECTION 6 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 stayed flat as a result of a continuing focus on energy efficiency, as
well as the adoption of more stringent appliance efficiency standards and energy standards in
building codes.
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Figure 5: Historical Electricity Consumption
Figure 6 shows the forecast of electricity consumption through FY 2023, as well as what
electricity consumption would have been without energy efficiency rebates, appliance
efficiency standards, stricter building codes, and rooftop photovoltaic (PV) generation. The
forecast assumes that current trends continue and sales through the forecast period decline
slightly. As of the end of December 2014, net metered PV installations in Palo Alto provided
less than 1% of the total electricity consumed in the City. The Council -adopted Local Solar
Plan’s goal is to increase the penetration of local PV generation to 4% of the City’s needs by
2023.
Figure 6: Forecasted Electricity Consumption
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SECTION 6 B : FY 2009 TO FY 2014 COST AND REVENU E 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 7A (Electricity Purchases). Since FY 2012, total expenses for the utility
have been increasing as renewable resources come online, though some of the increase is
associated with 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 or below inflation over that
time.
Figure 7: Electric Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2014 and Projections through FY 2023
SECTION 6 C : FY 2014 RESULTS
In spring of 2013, staff forecasted a $2.2 million deficit for FY 2014. Results were better than
forecasted, a $230,000 deficit, but there were several offsetting variances from the forecast .
Low generation from the utility’s hydroelectric resources led to higher market purchase costs,
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but these were partially offset by savings in renewable energy costs. This was due to the
cancelation of two higher cost renewable contracts and a delay in the online date for a third .
Sales revenue was $6.5 million lower than projected, but projections had been high due to
overestimated load growth due to planned customer expansions. Actual sales volumes for FY
2014 ended up being similar to FY 2013. The unrealized sales revenue would have resulted in a
deficit for the year, but it was offset by savings in a variety of areas. These included savings in
transmission charges, savings in capital project budgets, and savings in operating budgets. Table
8 summarizes the variances from forecast.
Table 8: FY 2014, Actual Results vs. 2013 Forecast
Net Cost/(Benefit) Type of change
Lower renewable energy costs due to project
cancelations and delays
(6,093,000) Cost savings
Higher market purchase costs due to renewable
project cancelations and low hydro
9,669,000 Cost increase
Lower than projected transmission charges and
higher transmission-related revenues
(5,197,000) Cost savings
Other commodity purchase cost savings (1,401,000) Cost savings
Savings in capital investment budgets due to
canceled projects
(3,897,000) Cost savings
Savings in operating budgets (2,042,000) Cost savings
Sales revenue lower than projected 6,483,000 Revenue decrease
Other variances, net 448,000 Various
Net Cost / (Benefit) of Variances (2,030,000)
SECTION 6 D : FY 2015 PROJECTIONS
In spring of 2014, staff forecasted a $5.8 million deficit for FY 2015. This was to be funded from
reserves. Staff’s current forecast is for a deficit of $16.6 million. Most of the $10.8 million
difference is associated with lower hydroelectric generation due the drought . The cost for the
utility’s hydroelectric resources is mostly fixed, meaning they do not change much regardle ss of
how much energy those resources generate. When they generate less electricity than average,
CPAU must purchase additional electricity from marketers to make up the difference. When
they generate more electricity than average, CPAU is able to save on its market electricity
purchase costs. In FY 2015, the drought has caused much lower hydroelectric generation than
average, leading to additional costs as CPAU makes more purchases in the electricity markets .
In addition, CPAU and other CVP wholesale electric customers can incur additional costs during
a drought under the terms of their contracts with the Federal government. When CVP
revenues from water sales decrease, the difference may be collected from electric customers as
happened in FY 2015. Table 9 summarizes the changes from last year’s forecast.
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Table 9: FY 2015 Change in Projected Results, 2014 Forecast vs 2015 Forecast
Net Cost/(Benefit) Type of change
Drought-related cost increases associated with CVP
(Western) hydropower contract
2,765,000 Cost increase
Drought-related increase in market purchase costs 8,499,000 Cost increase
Decrease in projected sales 1,672,000 Revenue decrease
Other revenue higher than projected (403,000) Revenue increase
Renewables – one-time payment delayed from FY 2014 795,000 Cost increase
Transmission cost savings (2,391,000) Cost savings
Other variances, net ($137,000) Various
Net Cost / (Benefit) of Variances 106,000
SECTION 6 E : FY 2016 – FY 2023 PROJECTIONS
As shown in Figure 7 above, costs for the Electric Utility are projected to increase through FY
2018, then level off in subsequent years. This is primarily related to electricity purchase costs,
which have been increasing starting in FY 2013 and will continue to increase through FY 2018 as
new renewable projects come online to fulfill the City’s environmental goals . Operations costs
are expected to increase at or below the inflation rate through the forecast period. Capital
investment costs are also expected to increase at only an inflationary rate, except for costs
associated with installing smart grid technologies. This forecast assumes that smart grid costs
are funded from the Electric Special Projects Reserves.
Revenues will have to increase 6% in FY 2017 and another 6% in FY 2018 to keep up with these
cost increases. Customers who reduce consumption over the forecast period will see their bills
increase at a slower rate, and as more customers are added to the utility’s customer base,
those customers will share in paying for the utility’s fixed costs. The combination of these
factors means that the average residential bill is projected to increase at a slightly slower pace
than the rates, assuming some growth in the customer base and decreases in the average
amount of electricity each customer uses. Of course, results will differ for each individual
customer depending on their energy use patterns.
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 Distribution Rate
Stabilization Reserve will be empty as of the end of FY 2015. The Supply Rate Stabilization
Reserve is projected to be empty by the end of FY 2016. Assuming the projected increases in
revenue, the utility’s reserves will remain adequate through the forecast period. Both the
Supply and Distribution Operations Reserve, the utility’s main contingency reserves, will remain
comfortably above minimum levels and adequate to meet all identified risks, as discussed in
Section 6F (Risk Assessment and Reserves Adequacy).
With respect to the Hydro Stabilization Reserve, these projections assume average rainfall next
winter, although hydro generation is still predicted to be below average since much of next
year’s precipitation is expected to refill reservoirs that are low due to the current drought . Staff
has also included a forecast in Section 6G (Alternate Scenario) that assumes adverse conditions
for hydroelectric generation.
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Figure 8: Electric Utility Reserves (Supply Fund):
Actual Reserve Levels through FY 2014 and Projections through FY 2023
Figure 9: Electric Utility Reserves (Distribution Fund):
Actual Reserve Levels through FY 2014 and Projections through FY 2023
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SECTION 6 F : RISK ASSESSMENT AND RESERVES ADEQUAC Y
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 throughout the forecast period. Reserve levels also exceed the short term
risk assessment for the utility.
There are a variety of risks associated with the Supply Fund. These risks are shown below in
Table 10. 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 10 is very low.
Table 10: Electric Supply Fund Risk Assessment
Categories of Electric Supply
Cost Uncertainties
Estimates of Adverse
Outcomes (M$)
Notes FY 2015 FY 2016
1. Load Net Revenue 0.7 0.5
Revenue loss from load decreases (net of
reduction in energy purchases)
2. Production from Hydroelectric
Resources: Western & Calaveras 9.1 11.6 Lower than forecasted hydro
3. Renewable Production: Landfill
& Wind 0.7 0.4
Additional cost of renewable output that is
higher than forecasted
4. Carbon Neutral Cost 0.3 0.3 Higher than forecasted market prices for RECs
5. Market Price (Energy) 0.8 0.6
Higher than forecasted market prices for
energy
6. Local Capacity 0.4 0.4
Higher than forecasted market prices for local
capacity
7. Transmission/CAISO 3.7 4.6 High-end transmission forecast scenario
8. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage
9. Western Cost 2.7 3.0 Risk of rate adjustments from Western
10. Regulatory and Legal - -
Risk of adverse financial impacts from
regulatory changes or legal action
11. Supplier Default
- -
Consequences of project failure and supplier
default for below market renewables currently
in operation
Electric Supply Fund Risks $19.4
million
$22.4
million
Projected Supply Operations +
Hydro Stabilization Reserve
Levels
$35.4
million
$32.9
million
Of the risks faced by the Electric Utility’s Supply Fund in FY 2016, the risk of a dry year with very
low hydroelectric output is 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. Risks associated with hydroelectric output account for $9.1 million (43%) of FY 2015
contingencies.
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Of the remaining risks for FY 2016, $3.7 million (19%) is related to the projected costs if
transmission cost increases are higher than staff’s current forecast. Another $2.7 million (13%)
is related to the possibility of drought-related changes to Western rates for CVP hydropower,
and $1.5 million (7%) is related to fluctuations in market prices for capacity, energy, and RECs.
As shown in Figure 10, the Supply Operations Reserve will stay within the reserve guidelines
over the course of the forecast period. In addition, as shown in Figure 11, the combined hydro
stabilization and supply operations reserves stay above the risk assessment level.
Figure 10: Electric Supply Operations Reserve Adequacy
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Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined
Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve
through FY 2020. 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.
Table 11: Electric Distribution Fund Risk Assessment ($000)
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Total non-commodity revenue $41,776 $41,689 $42,397 $45,153 $46,508
Max. revenue variance, previous ten years 8% 8% 8% 8% 8%
Risk of revenue loss $3,297 $3,290 $3,346 $3,564 $3,671
CIP Budget $12,711 $11,442 $13,584 $14,771 $15,675
CIP Contingency @10% $1,271 $1,144 $1,358 $1,477 $1,567
Total Risk Assessment value $4,568 $4,434 $4,705 $5,041 $5,238
This Financial Plan includes a proposal to make the CIP Reserve a contingency reserve as well.
See Section 4B (Reserves Management Practices, Proposed Change) for more details.
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Figure 12: Electric Distribution Operations Reserve Adequacy
SECTION 6 G : ALTERNATE SCENARIO
Extended drought is the most significant factor that can affect the Electric Utility’s financial
position due to the large fraction of hydroelectric generation in its supply portfolio. This section
describes the impact of a three-year drought on reserves and rates. Costs are projected to
increase by $8 to $12 million per year in a three-year drought, which would result in the need
for rate increases throughout the drought followed by a rate decrease at the end of the
drought. The Hydro Stabilization Reserve would help, but would not be sufficient in such a
scenario. Instead of adjusting the base rates, the City could put a “hydro rate adjuster” into
place, which would adjust rates up or down in dry or wet years, respectively. Staff is working to
develop such a rate adjuster and plans to discuss such a mechanism with the UAC and Council
in FY 2016 with the goal of having a hydro rate adjuster in place by FY 2017. The following
discussion assumes that a hydro rate adjuster with a maximum level of 1.3 cents/kWh would be
in effect starting in FY 2017 and that FY 2016 through FY 2018 are drought years.
As shown in Figure 13, below, the addition of a 0.65 to 1.3 cent per kWh hydro rate adjuster
would, when combined with the Hydro Stabilization Reserve, recover adequate revenue to
cover costs in a three-year drought. Once the hydro adder reached its maximum level (1.3
cent/kWh), the utility’s revenues would match its costs, a situation which could be sustained
through a drought lasting even longer than three years. The hydro adder would likely still be
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required in subsequent years to replenish the Hydro Stabilization Reserve, as shown in Figure
14, but a year with high precipitation and higher than a verage hydro generation, as has
occurred after prior droughts, could replenish the reserves more quickly. Figure 15 illustrates
that the Hydro Stabilization and Operations Reserves could temporarily drop below the risk
assessment level in this scenario. But the City also has the ability to implement a mid-year rate
change, if necessary to protect the financial health of the utility.
Figure 13: Electric Rate Trajectory in a Three Year Drought
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Figure 14: Electric Supply Reserve Changes in a Three Year Drought
Figure 15: Electric Supply Reserve Adequacy during a Three Year Drought
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SECTION 6 H : LONG -TERM OUTLOOK
This forecast covers the period from FY 2016 through FY 2023, 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 expirat ion,
especially because this resource represents nearly 40% of the electric portfolio, and represents
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
provide 17% to 18% of the energy for the utility’s supply portf olio 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, 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. Staff is already working
on a replacement renewable resource for the contract expiring in 2021.
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 t hat 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 there is no
provision for the continuation of these allocations past 2020 . 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. 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.
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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 will also start monitoring 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 number s of rooftop solar
installations. The utility has already started to take some of these factors into account in its
long term planning processes, but will need to con tinue to incorporate them into its planning
methodologies.
Looking out toward 2050 and beyond, if the State were to adopt climate goals consistent with
Executive Orders S-3-05 and B-16-2012 (with a goal of reducing GHG emissions to 80 percent
below 1990 levels by 2050), or if similar local goals were adopted, 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
overinvestment.
SECTION 7 : DETAILS AND ASSUMPTI ONS
SECTION 7 A : ELECTRICITY PURCHASE S
As shown in Figure 16 the utility gets roughly 50% of its energy from hydroelectric projects in a
normal year (FY 2014 has been dry). Contracts with renewable sources made up just over 20%
of the portfolio in FY 2014, and are projected to rise to roughly 50% by 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.
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Figure 16: Electricity Supply by Source
Figure 17 shows the historical and projected costs for the electric supply portfolio,4 as well as
average and actual hydroelectric generation.5 Electric supply costs decreased in FY 2010 and FY
2011 due to decreases in market prices related to shale gas. In addition, FY 2009 was a dry year
with low hydroelectric production, so FY 2010 and FY 2011 looked better by comparison. Costs
increased in FY 2013, FY 2014, and FY 2015 due to the drought, which reduced the amount of
generation the utility received from its hydroelectric resources. Costs are projected to decrease
slightly in FY 2016 if hydroelectric generation returns to normal, but will increase in subsequent
years 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 accom modate new
renewable projects. In total, electric supply costs are projected to increase $7.5 million from FY
2014 levels by FY 2018, at which point all currently contracted renewable projects will be
online. Costs are only projected to increase slightly in subsequent years.
4 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).
5 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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Figure 17: Electric Supply Portfolio Costs, Historical and Projected
SECTION 7 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 7D (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 F (Description of Electric Utility Operational Activities) includes detailed descriptions
of the work associated with each of these activities.
From FY 2009 to FY 2014, Operations costs increased by $2.7 million, or roughly 1% per year on
average. Excluding debt service and transfers, which stay relatively stable over time, costs
increased roughly 3% per year over that time. In FY 2015 costs continued that trend, and these
trends are projected to continue over the forecast period.
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Figure 18: Historical and Projected Electric Utility Operational Costs
SECTION 7 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
The Electric Utility’s CIP is shown in Table 12, and consists of the following programs and
budgets:
System Capacity and Reliability: CPAU monitors the distribution system and identifies
sections that need upgrades to increase reliability or to provide additional capacity to
deliver power. This category includes activities such as upgrading and replacing
transformers, replacing distribution lines to increase capacity, improving system
protection schemes (fuses, switches, etc.), and upgrading substation equipment.
Smart Grid and Advanced Metering: This project includes the cost of future upgrades
to the distribution system and metering infrastructure to take advantage of advances in
automation, sensing, and metering technologies. CPAU is currently operating pilot
programs to determine the scope of the upgrades.
4/12 kilovolt (kV) Conversion: The distribution system currently has some sections that
operate at 4 kV and some at 12 kV. CPAU is converting the 4 kV sections of the system
to enable them to connect to the rest of the system more effectively, providing greater
reliability. Operating the system at 12 kV also lowers energy losses.
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Undergrounding: This category includes projects to move sections of the overhead
system underground. These projects are generally funded in part by phone and cable
companies, whose systems are undergrounded at the same time.
Underground System Rebuilding: Underground sections of the distribution system
require periodic replacement due to the wear on the system associated with exposure
to soil and water.
Software and Equipment: This category includes the costs of upgrades to the software,
communications, and remote monitoring equipment used to monitor the system and
plan upgrades. It includes the cost of upgrades to the SCADA system.
Customer Connections: This represents the cost of installing new services or upgrades
to existing services at a customer’s request in response to development or
redevelopment. Because the Electric Utility charges a fee to these customers to cover
the cost, these are considered to be “customer-funded” projects.
One-time Projects: This category represents occasional large projects that do not fall
into any other category.
Excluding smart grid projects, CIP spending is expected to increase by 3% to 4% per year
through the forecast period. Smart grid upgrades, particularly in later years, are projected to
cost substantial amounts of money, but CPAU does not have precise cost estimates yet. 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 smart grid updates, the CIP plan for FY 2016 to FY 2020 is
primarily funded by utility rates, but other sources of funds include connection fees (for
Customer Connections), phone and cable companies (primarily for undergro unding), and other
funds (for smart grid). The details of the plan are shown in Appendix B (Electric Utility Capital
Improvement Program (CIP) Detail).
Table 12: Budgeted Electric Utility CIP Spending
SECTION 7 D : DEBT SERVICE
The Electric Utility’s annual debt service is $100,000 per year. This is related to the 2007
Electric Utility Clean Renewable Energy Tax Credit Bonds, Series A, which will require payments
through 2021. This $1.5 million 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 total capacity of these projects was 250 kilowatt (kW).
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget Committed FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
One-Time Projects 1,409 (314) 1,096 383 125 1,275 1,000 3,100 3,750
System Expansion 67 - 67 - - - - - -
Reliability 1,143 (9) 1,134 180 25 1,250 750 - -
Undergrounding 2,716 (57) 2,659 1,403 500 50 2,150 2,250 500
4/12 Kv Conversion 943 (353) 590 40 - 120 450 400 -
Underground Rebuilding 4,242 (941) 3,301 542 1,050 1,100 800 400 850
Ongoing Projects 6,885 (1,625) 5,260 1,556 3,620 3,480 3,120 2,825 2,840
Customer Connections
(Fee Funded)3,622 (730) 2,891 817 3,000 3,108 3,220 3,336 3,456
TOTAL 21,028 (4,029) 16,999 4,920 8,320 10,383 11,490 12,311 11,396
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year.
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The City is in compliance with all covenants on the bond. Additional detail is provided in
Appendix E (Electric Utility Debt Service Details).
SECTION 7 E : EQUITY TRANSFER
The City calculates the equity transfer from its Electric Utility based on a rate of return on the
net book value of the utility’s capital assets6. The Council adopted this methodology in 2009
and it has remained unchanged since. Each year it is calculated according to the 2009 Council-
adopted methodology, and does not require additional Council action.
SECTION 7 F : WHOLESALE REVENUES A ND OTHER REVENUES
The Electric Utility receives most of its revenues from sales of electricity, but about 15% comes
from other sources. Of these other sources, roughly 30% represent wholesale “revenues” that
are included solely for accounting purposes. These revenues have offsetting electric supply
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 2014 these sources represented roughly 40% of revenue from sources other
than electricity sales. The remaining FY 2014 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, but plans to review these fees as part of the electric cost of service study to see if they
are recovering the appropriate amount of revenue.
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.
6 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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SECTION 7 G : SALES REVENUES
Sales revenue projections are based on the load forecast in Section 6A (Load Forecast) and the
projected rate changes shown in Figure 7. As discussed in Section 6A, sales revenues for this
utility stay relatively stable due to the mild climate in Palo Alto . In addition, Palo Alto is a built
out City, with incremental growth in population and relatively stable commercial customer
loads.
SECTION 8 : COMMUNICATIONS PLAN
The FY 2016 Electric Utility communications strategy covers four primary areas: efficiency,
renewables, operations, infrastructure, safety and rates. CPAU has not had an electric rate
increase since 2009 and does not expect one in the upcoming year, so there is no need for
formal “rate change” communications at this time, but website and community edu cation
about rates is ongoing. CPAU has been and will continue to communicate about the March
2013 decision to only purchase carbon-neutral electric supplies, which includes apprising the
public of major renewable energy purchase agreements. Electric use efficiency incentives are
promoted year-round. 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 will engage in several new campaigns and programs in FY 2016 to promote electric utility
efficiency and renewables generation. The Georgetown University Energy Prize competition is a
friendly, national campaign to encourage communities to reduce energy use. Energy savings
from reduced electric and gas consumption qualify to help Palo Alto compete for a $5 million
prize at the end of a two-year campaign. The Local Solar Plan includes three components for
community solar options. Other new programs include home efficiency services and online
tools to help customers manage their energy use.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate
adjustment messages through a variety of marketing and media channels. Staff talks with
business customers at special facilities meetings, attends neighborhood safety and emergency
preparedness fairs and offers presentations to school and community groups. A team of Electric
Operations Technicians is available to provide educational demonstrations on electric utility
safety to school groups, which the CPAU Communications team will support. 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.
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APPENDICES
Appendix A: Electric Utility Financial Forecast Detail
Appendix B: Electric Utility Capital Improvement Program (CIP) Detail
Appendix C: Electric Utility Reserves Management Practices
Appendix D: Rate Design
Appendix E: Electric Utility Debt Service Details
Appendix F: Description of Electric Utility Operational Activities
Appendix G: 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 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2
3 ELECTRIC LOAD
4 Purchases (MWh)1,040,851 1,019,788 978,833 969,519 976,319 980,894 979,005 977,292 993,844 997,125 998,260 997,531 997,596 999,464 986,864
5 Sales (MWh)995,811 965,048 946,518 942,562 946,841 950,784 948,656 946,996 963,035 966,215 967,314 966,608 966,670 968,481 956,271
6
7 BILL AND RATE CHANGES
8 System Average Rate ($/kWh)0.1048$ 0.1155$ 0.1168$ 0.1156$ 0.1154$ 0.1164$ 0.1158$ 0.1158$ 0.1231$ 0.1307$ 0.1317$ 0.1336$ 0.1336$ 0.1336$ 0.1381$
9 Change in System Average Rate 10%1%-1%0%1%0%0%6%6%1%1%0%0%3%
10 Change in Average Residential Bill 11%-5%-1%-4%-1%4%-1%4%6%1%1%0%0%2%
11
12 STARTING RESERVES
13 Reappropriations (Non-CIP)- - 2,760,000 343,000 1,886,000 305,000 - - - - - - - - -
14 Commitments (Non-CIP)2,241,000 1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000
15 Restricted for Debt Service - - - - - - - - - - - - - - -
16 Emergency Plant Replacement 3,057,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - -
17 Central Valley Project Reserve 22,000 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - -
18 Underground Loan Reserve 709,000 717,000 731,000 736,000 742,000 738,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000
19 Public Benefits Reserves 2,109,000 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 1,770,570 1,383,579 942,269 401,037 30,329 - - -
20 Electric Special Projects Reserve 70,397,000 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 51,504,667 51,171,333 50,171,333 49,171,333 48,171,333 47,171,333
21 Hydro Stabilization Reserve - - - - - - - 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000
22 Capital Reserves - - - - - - - - 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000
23 Rate Stabilization Reserves 55,418,000 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 9,000,000 - - - - - - -
24 Operations Reserves - - - - - - - 29,098,101 28,147,709 24,392,071 24,819,428 28,324,454 32,764,040 34,748,754 35,087,237
25 Unassigned - - - - - - - - - (0) (0) - - - -
26 TOTAL STARTING RESERVES 133,953,000 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,604,671 110,982,289 106,452,006 106,004,797 108,139,116 111,548,373 112,533,087 111,871,570
27
28 REVENUES
29 Net Sales 105,312,712 113,129,269 111,948,267 109,309,318 109,974,337 110,301,711 109,858,447 109,644,507 118,519,206 126,244,211 127,381,868 129,182,750 129,191,140 129,433,106 132,015,572
30 Wholesale Revenues 10,618,388 7,903,940 8,443,016 7,189,218 6,635,790 6,010,409 8,361,193 9,762,754 16,127,681 17,899,396 18,193,077 18,520,428 18,457,947 17,183,269 17,608,371
31 Other Revenues and Transfers In 11,744,330 8,458,392 6,374,799 7,027,230 9,624,213 13,669,185 10,826,729 9,842,016 10,552,506 10,520,182 12,135,863 12,522,226 12,868,793 13,211,063 13,569,255
32 TOTAL REVENUES 127,675,429 129,491,602 126,766,082 123,525,766 126,234,340 129,981,305 129,046,369 129,249,277 145,199,394 154,663,790 157,710,808 160,225,405 160,517,880 159,827,438 163,193,198
33
34 EXPENSES
35 Electric Supply Purchases 82,348,075 68,714,475 61,247,248 58,724,136 61,313,637 68,785,977 81,704,930 76,259,040 84,697,114 87,985,432 87,652,519 87,403,918 88,750,130 88,323,133 88,823,060
36 Operating Expenses
37 Administration
38 Allocated Charges 3,585,068 2,667,704 2,807,991 3,416,423 4,399,674 4,139,837 3,809,450 3,904,868 4,002,906 4,103,416 4,206,436 4,312,048 4,420,046 4,530,589 4,643,908
39 Rent 3,428,294 3,963,377 3,721,542 3,839,201 3,875,836 4,051,044 4,225,064 4,351,816 4,482,370 4,616,842 4,755,347 4,898,007 5,044,947 5,196,296 5,352,185
40 Debt Service 8,185,819 7,919,136 7,343,352 8,902,751 9,265,736 9,020,651 9,128,150 9,139,768 8,953,886 8,955,164 8,808,619 8,818,349 8,783,507 8,792,388 9,624,493
41 Transfers and Other Adjustments 13,282,668 10,860,269 13,056,927 11,603,695 16,797,054 11,385,421 11,534,855 11,537,926 11,541,075 11,544,301 11,547,609 11,550,999 11,554,474 11,558,036 11,561,687
42 Subtotal, Administration 28,481,848 25,410,486 26,929,812 27,762,069 34,338,299 28,596,953 28,697,519 28,934,378 28,980,237 29,219,723 29,318,011 29,579,403 29,802,974 30,077,308 31,182,273
43 Resource Management 2,062,511 3,033,428 2,380,313 2,654,024 3,024,268 3,541,524 2,518,045 2,592,974 2,685,421 2,781,884 2,880,881 2,983,786 3,071,974 3,151,655 3,234,248
44 Demand Side Management 3,336,356 4,048,114 3,490,676 4,541,531 3,529,529 3,187,875 5,385,750 5,336,417 4,261,592 4,311,342 3,475,786 3,593,030 3,696,217 3,791,455 3,889,977
45 Operations and Mtc 8,975,462 8,892,002 9,339,340 9,288,490 9,601,481 9,488,627 11,307,989 11,631,635 12,016,747 12,417,061 12,827,544 13,252,906 13,630,189 13,980,676 14,343,027
46 Engineering (Operating)879,303 1,094,766 1,070,441 1,057,783 1,114,945 1,102,008 1,341,265 1,375,940 1,412,963 1,451,051 1,490,079 1,530,192 1,569,695 1,609,201 1,649,779
47 Customer Service 1,650,731 1,896,956 1,881,881 1,908,493 2,007,322 2,032,231 2,266,899 2,336,447 2,424,578 2,516,809 2,611,542 2,710,258 2,792,758 2,865,705 2,941,475
48 Allowance for Unspent Budget - - - - - - (313,702) (322,541) (332,900) (343,661) (354,701) (366,136) (376,419) (386,069) (396,037)
49 Subtotal, Operating Expenses 45,386,213 44,375,751 45,092,464 47,212,389 53,615,844 47,949,218 51,203,766 51,885,250 51,448,638 52,354,209 52,249,141 53,283,439 54,187,389 55,089,932 56,844,741
50 Capital Program Contribution 13,510,141 12,571,376 15,635,370 13,837,241 15,113,859 13,016,111 12,711,002 11,442,369 13,583,924 14,771,357 15,674,828 16,128,791 16,595,646 17,075,890 17,570,114
51 TOTAL EXPENSES 141,244,429 125,661,602 121,975,082 119,773,766 130,043,340 129,751,305 145,619,698 139,586,659 149,729,676 155,110,998 155,576,489 156,816,148 159,533,166 160,488,955 163,237,914
52
53 ENDING RESERVES
54 Reappropriations (Non-CIP)- 2,760,000 343,000 1,886,000 305,000 - - - - - - - - - -
55 Commitments (Non-CIP)1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000 3,164,000
56 Restricted for Debt Service - - - - - - - - - - - - - - -
57 Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - -
58 Central Valley Project Reserve 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - - -
59 Underground Loan Reserve 717,000 731,000 736,000 742,000 738,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000 734,000
60 Public Benefits Reserves 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 1,770,570 1,383,579 942,269 401,037 30,329 - - - -
61 Electric Special Projects Reserve 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,838,000 51,504,667 51,171,333 50,171,333 49,171,333 48,171,333 47,171,333 46,171,333
62 Hydro Stabilization Reserve - - - - - - 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000 17,000,000
58 Capital Reserve - - - - - - - 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000 8,715,000
59 Rate Stabilization Reserve 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 9,000,000 - - - - - - - -
60 Operations Reserve - - - - - - 29,098,101 28,147,709 24,392,071 24,819,428 28,324,454 32,764,040 34,748,754 35,087,237 36,042,521
61 Unassigned - - - - - - - - (0) (0) - - - - -
62 TOTAL ENDING RESERVES 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,604,671 110,982,289 106,452,006 106,004,797 108,139,116 111,548,373 112,533,087 111,871,570 111,826,854
J u n e 1 6 , 2 0 1 4 39 | P a g e
1 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
2
3 REVENUES
4 Net Sales 82%87%88%88%87%85%85%85%82%82%81%81%80%81%81%
5 Other Revenues and Transfers In 18%13%12%12%13%15%15%15%18%18%19%19%20%19%19%
6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%
7
8 EXPENSES
9 Commodity Purchases 56%54%46%46%46%52%55%52%48%47%47%46%47%47%47%
10 Operating Expenses
11 Administration
12 Allocated Charges 3%2%2%3%3%3%3%3%3%3%3%3%3%3%3%
13 Rent 2%3%3%3%3%3%3%3%3%3%3%3%3%3%3%
14 Debt Service 6%6%6%7%7%7%6%7%6%6%6%6%6%5%6%
15 Transfers and Other Adjustments 9%9%11%10%13%9%8%8%8%7%7%7%7%7%7%
16 Subtotal, Administration 20%20%22%23%26%22%20%21%19%19%19%19%19%19%19%
17 Resource Management 1%2%2%2%2%3%2%2%2%2%2%2%2%2%2%
18 Operations and Mtc 6%7%8%8%7%7%8%8%8%8%8%8%9%9%9%
19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1%1%1%1%
20 Customer Service 1%2%2%2%2%2%2%2%2%2%2%2%2%2%2%
21 Allowance for Unspent Budget 0%0%0%0%0%0%0%0%0%0%0%0%0%0%0%
22 Subtotal, Operating Expenses 30%32%34%36%39%34%31%33%32%31%31%32%32%32%32%
23 Capital Program Contribution 10%10%13%12%12%10%9%8%9%10%10%10%10%11%11%
24 TOTAL EXPENSES 95%96%93%94%96%97%95%93%89%88%88%88%89%90%90%
25
26 RISK ASSESSMENT DETAIL (SUPPLY FUND)
27 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
28 1. Load Net Revenue 77,428 652,853 481,940
29 2. Hydro Production: Western & Calaveras 9,314,822 9,050,313 11,647,628
30 3. Renewable Production: Landfill & Wind & Solar 375,755 743,945 384,259
31 4. Carbon Neutral Cost 331,630 303,022 333,730
32 5. Market Price 909,196 775,584 574,924
33 6. Local Capacity 475,962 408,388 392,159
34 7. Transmission/CAISO 4,555,915 3,741,647 4,554,812
35 8. Plant Outage 1,000,000 1,000,000 1,000,000
36 9. Western Cost 3,130,000 2,704,738 3,011,315
37 10. Regulatory & Legal - - -
38 11. Supplier Default - - -
39 TOTAL 20,170,708 19,380,490 22,380,767
40
Supply Operations + Hydro Stabilization
Reserves, % of Risk Assessment 229%233%185%
41
42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND)
43 FISCAL YEAR FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023
44 Distribution Revenue Variance 3,297,180 3,290,258 3,346,192 3,580,425 3,669,936 3,816,734 3,816,981 3,824,131 3,938,855
45 10% CIP Program Contingency 1,271,100 1,144,237 1,358,392 1,477,136 1,567,483 1,612,879 1,659,565 1,707,589 1,757,011
46 Total Risk Asssessment Value 4,568,280 4,434,494 4,704,584 5,057,561 5,237,419 5,429,613 5,476,546 5,531,720 5,695,866
47 Projected Operations Reserve 29,098,101 28,147,709 24,392,071 24,819,428 28,324,454 32,764,040 34,748,754 35,087,237 36,042,521
48 Operations Reserve, % of Risk Value 637%635%518%491%541%603%635%634%633%
49
44 SUPPLY OPERATIONS RESERVE
45 Min (60 days of non-capital expenses)- - - - - - 7,496,015 7,665,425 7,682,906 7,891,487 7,959,709 8,190,870 8,411,799 8,628,401 8,834,955
46 Target (90 days of non-capital expenses)- - - - - - 9,721,021 9,936,953 9,923,896 10,196,495 10,257,551 10,561,974 10,850,141 11,130,830 11,395,334
47 Max (120 days of non-capital expenses)- - - - - - 11,946,027 12,208,481 12,164,887 12,501,504 12,555,393 12,933,077 13,288,484 13,633,260 13,955,714
48
49 DISTRIBUTION OPERATIONS RESERVE
50 Min (60 days of non-capital expenses)- - - - - - 22,997,867 22,290,538 23,683,885 24,453,306 24,463,321 24,676,558 25,132,327 25,298,341 25,759,036
51 Target (90 days of non-capital expenses)- - - - - - 32,973,799 31,874,623 33,925,365 35,039,224 35,012,969 35,290,505 35,930,934 36,135,741 36,781,456
52 Max (120 days of non-capital expenses)- - - - - - 42,949,731 41,458,708 44,166,846 45,625,143 45,562,617 45,904,452 46,729,540 46,973,140 47,803,877
53 Risk Assessment Value 4,568,280 4,434,494 4,704,584 5,057,561 5,237,419 5,429,613 5,476,546 5,531,720 5,695,866
54
55 DEBT SERVICE COVERAGE RATIO
56 Net Revenues (125% of Debt Service)1460%1328%1348%1090%1140%1194%1356%1302%1421%1467%1488%1495%1527%1531%1414%
57 Available Reserves (5x Debt Service)*14.5 15.2 17.3 14.4 13.5 14.0 12.0 11.8 11.5 11.5 11.9 12.3 12.5 12.4 11.3
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.
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX B : ELECTRIC 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 Reserves Commitments FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
ONE-TIME PROJECTS
EL-06001 230 kV Electric Intertie 63,515 50,000 - (40,986) 72,529 56,233 - - - - -
EL-06003 Utility Control Center Upgrades - 75,000 - - 75,000 - - - - - -
EL-10009 Street Light Sys Conversion Project 296,270 - - (219,544) 76,726 237,378 - - - - -
EL-11014 Smart Grid Technology Installation 719,676 - - (45,325) 674,351 84,493 - 1,000,000 1,000,000 3,000,000 3,000,000
EL-10008 Advanced Metering Infrastructure 56,188 - - (7,887) 48,301 4,500 - - - - -
EL-11016 Elec. Vehicle Charging Infrastructure - - - - - - - - - - -
EL-13002 Quarry/Hopkins Substation 60kV Line - - - - - - - - - 100,000 750,000
EL-13008 Upgrade Electric Estimating System 148,650 - - - 148,650 - - - - - -
EL-xxxxx Substation Security - - - - - - 50,000 - - - -
EL-xxxxx Capacitor Bank Installation - - - - - - 75,000 275,000 - - -
Subtotal, One-time Projects 1,284,299 125,000 - (313,742) 1,095,557 382,604 125,000 1,275,000 1,000,000 3,100,000 3,750,000
SYSTEM EXPANSION
EL-11015 Reconductor 60kV Overhead Sys 67,090 - - - 67,090 - - - - - -
EL-13005 Colorado 20/21-Xfrmr Replacement - - - - - - - - - - -
Subtotal, System Expansion 67,090 - - - 67,090 - - - - - -
RELIABILITY
EL-12002 Hanover 22 - Xfrmr Replacement 6,680 - - - 6,680 - - - - - -
EL-13004 Hansen Way/Hanover 12kV Ties - - - - - - - - - - -
EL-13006 Sand Hill / Quarry 12 kV Tie 236,276 - - (3,084) 233,192 - - - - - -
EL-14005 Reconfigure Quarry Feeders 49,951 400,000 - (5,429) 444,522 - - 500,000 - - -
EL-15000 Colorado/Hopkins Sys. Improvement - 50,000 - - 50,000 - 25,000 750,000 750,000 - -
EL-15001 Substation Battery Replacement - 400,000 - - 400,000 180,000 - - - - -
Subtotal, Reliability 292,907 850,000 - (8,513) 1,134,394 180,000 25,000 1,250,000 750,000 - -
UNDERGROUNDING
EL-06002 UG District 45 134,271 - - - 134,271 - - - - -
EL-08001 UG District 42 - - - - - - - 50,000 2,000,000 250,000 -
EL-11009 UG District 43 - - - - - - - - 150,000 2,000,000 500,000
EL-11010 UG District 47 1,693,807 400,000 - (54,995) 2,038,812 1,402,500 300,000 - - - -
EL-12001 UG District 46 88,346 400,000 - (2,459) 485,887 - 200,000 - - - -
Subtotal, Undergrounding 1,916,424 800,000 - (57,454) 2,658,970 1,402,500 500,000 50,000 2,150,000 2,250,000 500,000
4/12 KV CONVERSION
EL-08000 E. Charleston 4/12kV 413,586 - - (311,226) 102,360 40,216 - - - - -
EL-09002 Middlefield/Colorado 4/12 kV - - - - - - - - - - -
EL-09004 W. Charleston/Wilkie Way 4/12 kV 85,483 - - (701) 84,782 - - - - - -
EL-12003 Hopkins Substation Rebuild - - - - - - - - - - -
EL-13000 Edgewood/Wildwood 4/12 kV Tie - - - - - - - - 50,000 400,000 -
EL-14000 Coleridge/Cowper/Tennyson 4/12 kV - - - - - - - 120,000 400,000 - -
EL-14004 Maybell 1&2 4/12 kV Conversion 444,127 - - (41,082) 403,045 - - - - - -
Subtotal, 4/12 kV Conversion 943,196 - - (353,009) 590,187 40,216 - 120,000 450,000 400,000 -
ELECTRIC UTILITY FINANCIAL PLAN
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Appendix B: Electric 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 Reserves Commitments FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
UNDERGROUND REBUILDING
EL-04010 Foothills System Rebuild 82,129 - - - 82,129 - - - - - -
EL-05000 El Camino Underground Rebuild 257,179 - - (57,389) 199,790 - - - - - -
EL-09000 Middlefield Underground Rebuild 157,928 250,000 - - 407,928 - - - - - -
EL-09003 Rebuild UG Dist 17 (Downtown)82,585 - - - 82,585 - - - - - -
EL-10006 Rebuild UG Dist 24 741,587 850,000 - (194,771) 1,396,816 26,374 - - - - -
EL-11001 Torreva Court Rebuild 7,195 - - - 7,195 - - - - - -
EL-11003 Rebuild UG Dist 15 456,427 - - (1,487) 454,940 - - - - - -
EL-11004 Hewlett Subdivision Rebuild 60,634 - - - 60,634 - - - - - -
EL-11006 Rebuild UG Dist 18 442,955 75,000 - - 517,955 475,000 - - - - -
EL-11007 Rebuild Greenhouse Condo Area 333,590 - - (267,236) 66,354 23,522 - - - - -
EL-11008 Rebuild UG Dist 19 101,473 - - (2,602) 98,871 - - - - - -
EL-12000 Rebuild UG Dist 12 343,219 - - (417,063) (73,844) 17,546 - - - - -
EL-13003 Rebuild UG Dist 16 - - - - - - - 300,000 - - -
EL-14002 Rebuild UG Dist 20 - - - - - - - 500,000 500,000 - -
EL-16000 Rebuild UG Dist 26 - - - - - - 750,000 - - - -
EL-xxxxx Revuild UG Dist 25 - - - - - - - - - 50,000 500,000
EL-xxxxx Underground System Rebuilding - - - - - - 300,000 300,000 300,000 350,000 350,000
Subtotal, Underground Rebuilding 3,066,901 1,175,000 - (940,548) 3,301,353 542,442 1,050,000 1,100,000 800,000 400,000 850,000
ONGOING PROJECTS
EL-04012 Utility Site Security 55,274 250,000 - (27,428) 277,846 12,661 250,000 - - - -
EL-13007 Underground Dist. System Security 299,172 - - (7,853) 291,319 - - 300,000 300,000 - -
EL-02011 Electric Utility GIS 193,565 165,000 - (32,895) 325,670 52,168 165,000 165,000 165,000 165,000 165,000
EL-02010 SCADA System Upgrade 101,529 60,000 - (64,201) 97,328 10,965 65,000 270,000 60,000 65,000 65,000
EL-89031 Communications System 76,136 100,000 - (5,261) 170,875 - 100,000 100,000 100,000 100,000 100,000
EL-89038 Substation Protection Improvements 121,869 280,000 - (93,755) 308,114 230,060 450,000 450,000 300,000 300,000 310,000
EL-89044 Substation Facility Improvements 86,641 185,000 - (121,720) 149,921 20,000 190,000 195,000 195,000 195,000 200,000
EL-98003 Electric System Improvements 2,461,142 2,450,000 - (1,272,245) 3,638,897 1,229,852 2,400,000 2,000,000 2,000,000 2,000,000 2,000,000
Subtotal, Ongoing 3,395,329 3,490,000 - (1,625,358) 5,259,971 1,555,706 3,620,000 3,480,000 3,120,000 2,825,000 2,840,000
CUSTOMER CONNECTIONS (FEE FUNDED)
EL-89028 Electric Customer Connections 321,745 3,300,000 - (730,274) 2,891,471 816,824 3,000,000 3,108,000 3,219,888 3,335,804 3,455,893
Subtotal, Customer Connections 321,745 3,300,000 - (730,274) 2,891,471 816,824 3,000,000 3,108,000 3,219,888 3,335,804 3,455,893
GRAND TOTAL 11,287,891 9,740,000 - (4,028,898) 16,998,993 4,920,292 8,320,000 10,383,000 11,489,888 12,310,804 11,395,893
Funding Sources
Connection Fees 1,500,000 - 1,550,000 1,600,000 1,650,000 1,700,000 -
Other Companies (Phone/CATV Co.)370,000 - 230,000 190,000 900,000 960,000 -
Other Utility Funds (Smart Grid)- - - 666,667 666,667 2,000,000 2,000,000
Utility Rates 7,870,000 - 6,540,000 7,926,333 8,273,221 7,650,804 9,395,893
CIP-RELATED RESERVES DETAIL
6/30/2014
(Actual)12/31/2014
Reappropriations 8,714,891 12,078,701
Commitments 2,573,000 4,920,292
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX C : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES
(Amendments to this section are proposed. See the proposed adopting resolution for this
Financial Plan. This section will be added to the Financial Plan following adoption of any
amendments to this section.)
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX D : RATE DESIGN
The Electric Utility’s current rate structure and methodology are consistent with the cost of
service analysis (COSA) update in 2007 by Boris Metrics. Staff plans to review and update this
cost of service study in 2015. Before conducting this new cost of service study, staff will review
current rates and the scope of the study with the UAC and Council to determine UAC and
Council policy priorities. There are a variety of rate-related topics currently being discussed by
investor- and publicly-owned utilities across California, including the pros and cons of tiered
rate structures, the impact of customer-owned generation (like net-metered solar) on rates and
revenues, and rate design for electric vehicles. With the Electric Utility’s carbon neutral electric
supply, some customers may be interested in gas-to-electric fuel switching, and the impact of
rate design on this decision also bears some discussion .
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX E : ELECTRIC UTILITY DEBT SERVICE DETAILS
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:
Table 13: Electric Utility Debt Service ($000)
FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022
2007 Clean
Renewable Energy
Bonds
100 100 100 100 100 100 100 -
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 A (Electric Utility Financial
Forecast Detail).
The Electric Utility’s reserves and net revenue are also pledged as security for the bond
issuances listed in Table 14, 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 14: 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
ELECTRIC UTILITY FINANCIAL PLAN
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APPENDIX F : 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 Admini stration.
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 G : SAMPLES OF RECENT EL ECTRIC UTILITY OUTRE ACH COMMUNICATIONS