HomeMy WebLinkAboutStaff Report 5681
City of Palo Alto (ID # 5681)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 4/22/2015
City of Palo Alto Page 1
Summary Title: Electric Utility Financial Plan
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt a Resolution Approving the Fiscal Year 2016 Electric Financial Plan,
Including no Rate Changes for July 1, 2015, and Amending the Electric Utility
Reserve Management Practices
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) recommend that 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.
The UAC reviewed the FY 2016 Electric Financial Plan at its April 1, 2015 meeting and voted
unanimously to recommend adoption of the plan and changes to Reserves Management
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Practices.
Background
Every year staff presents the Council 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 structure 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. These additional costs were
included in the mid-year budget adjustments for FY 2015. 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 Section 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 $9 million from the Supply Rate Stabilization Reserve to the Supply Operations
Reserve. This transfer will enable staff to maintain Supply Operations Reserve levels
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above the guideline levels until rates are changed in FY 2017.
These proposed actions are described in more detail in the FY 2016 Electric Financial Plan
(Attachment B).
Staff is not proposing any rate changes for the Electric Utility in FY 2016, but is beginning an
electric cost of service analysis (COSA) in preparation for proposing to change rates in FY 2017.
Staff will have policy discussions with the UAC and Council to identify policy objectives for the
study prior to beginning the COSA. Table 1 shows the projected rate adjustments included in
the FY 2016 Electric Financial Plan and their impact on the median residential electric bill.
Table 1: Projected Electric Rate Adjustments, FY 2016 to FY 2020
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Forecasted Rate Changes 0% 6% 6% 1% 1%
Estimated Bill Impact ($/mo)* $0.00 $2.69 $2.80 $0.38 $0.72
* estimated impact on median residential electric bill, which is $42.76 in FY 2015.
Table 2 shows the proposed and projected rate adjustments in the context of the other
proposed and projected utility rates.
Table 2: Rate Adjustments, All Utilities, FY 2016 Proposed, FY 2017 to FY 2020 Projected
FY 2016 FY 2017 FY 2018 FY 2019 FY 2020
Electric 0% 6% 6% 1% 1%
Gas1 0% 7% 4% 4% 4%
Wastewater 9% 9% 9% 9% 6%
Water 12% 8% 8% 8% 3%
Refuse2 9% 9% 8% 2% to 3% 2% to 3%
Storm Drain3 2.7% 2% to 3% 2% to 3% 2% to 3% 2% to 3%
Total Bill
Change4
(%) 6% 8% 7% 5% 3%
($/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 as new
renewable projects come online to fulfill the City’s Council-approved environmental goals. The
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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. CIP costs are also
expected to increase at only an inflationary rate, except for costs associated with installing
smart grid technologies. The Electric Financial Plan assumes that those smart grid costs are
funded from the Electric Special Projects Reserve, though this will require action by the City
Council before such funding can occur.
Changes from Preliminary Financial Forecast
The Finance Committee reviewed preliminary financial forecasts for the Electric Utility at its
March 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 that presented in the preliminary
financial forecast.
Commission Review
The UAC reviewed the attached Financial Plan and Reserves Management Practices at its April
1, 2015 meeting and, with little comment, unanimously recommended approval. One
commissioner commented on the extended drought scenario discussed in the Financial Plan
and in staff’s presentation, noting that although reserves decreased in that scenario, it was
appropriate to use contingency reserves in case of an extended drought. Another commissioner
recommended that staff consider amending the way that it presents the Electric Special
Projects reserve in charts in the report to make it clear that it was not intended for use in
routine utility financial operation, and only for special projects.
Timeline
After receiving the Finance Committee’s recommendation, 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 for
FY 2016 associated with this Financial Plan.
Policy Implications
The attached FY 2016 Electric 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).
Environmental Review
The UAC’s review and recommendation to Council on the FY 2016 Electric 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:
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Attachment 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 (PDF)
Attachment B: Proposed Amendments to Electric Utility Reserves Management
Practices (PDF)
Attachment C: Proposed FY 2016 Electric Utility Financial Plan (PDF)
Attachment D: Excerpted UAC Minutes of April 1, 2015 (PDF)
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
150316 sdl 6053271
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 hydroelectric
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)
ATTACHMENT B
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 Benefits
Revenues remaining at the end of each fiscal year. Expenditure of these funds requires
action by the City Council.
Section 10. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following
practices:
a) The following guideline levels are set forth for the CIP Reserve. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 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 action. 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 level set forth
above, staff shall present a plan to the City Council to replenish the reserve. The plan
shall be delivered within six months of the end of the fiscal year, and shall, at a
minimum, result in the reserve reaching its minimum level by the end of the following
fiscal year. For example, if the Operations Reserve is below its minimum level at the end
of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its
minimum level by June 30, 2015. In addition, staff may present an alternative plan that
takes longer than one year to replenish the reserve.
d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or
lower than the target level, any Financial Plan created for the Electric Utility shall be
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 and Electric Supply Fund Reserves are
permitted if consistent with the purposes of the two reserves involved in the transfer. Such
transfers require action by the City Council.
ELECTRIC UTILITY
FINANCIAL PLAN
FY 2016 TO FY 2023
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
ATTACHMENT C
ELECTRIC UTILITY FINANCIAL PLAN
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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
ELECTRIC UTILITY FINANCIAL PLAN
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SECTION 1: DEFINITIONS AND ABBREVIATIONS
CAISO: California Independent System Operator
CARB: California Air Resources Board
CIP: Capital Improvement Program
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
CVP: Central Valley Project
GWh: a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for discussing
total monthly or annual electric load for the entire city, or the monthly or annual output of an
electric generator.
kWh: a kilowatt-hour, the standard unit of measurement for electricity sales to customers.
kW: a kilowatt, a unit of measurement used in reference a customer’s peak demand (the
highest 15 minute average consumption level in a month), which is used for billing large and
mid-size commercial customers.
kV: a kilovolt, one thousand volts, a unit of measurement of the voltage at which a section of
the distribution system operates. The transmission system operates at 115-500 kV, and this is
lowered to 60 kV in the subtransmission section of the Electric Utility’s distribution section,
then 12 kV or 4 kV in the rest of the distribution system, and finally 120, 240, or 480 volts at the
electric outlet.
MWh: a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale
electricity purchases.
MW: a megawatt, equal to 1,000 kW. Commonly used when discussing maximum electricity
demand for all customers in aggregate.
PG&E: Pacific Gas and Electric
REC: Renewable Energy Certificate
RPS: Renewable Portfolio Standard
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.
ELECTRIC UTILITY FINANCIAL PLAN
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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 3A: OVERVIEW OF FINANCIAL 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 3B: 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 RATE AND RESERVES PROPOSALS
SECTION 4A: 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 4B: 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 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 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 Council
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 4C: PROPOSED RESERVE TRANSFERS
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 intended as general
background information to help readers better understand the forecasts in Sections 6 and 7.
SECTION 5A: 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 replacement
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 project and its
contract with WAPA for CVP hydropower.
In 2001 CPAU began planning for the impacts associated with the new terms of its contract with
WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power
supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental
power to balance the monthly and annual variability of CVP generation. The new contract
would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in
CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would
increase and CPAU needed to more actively 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 commencing 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 5B: 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 5C: DISTRIBUTION SYSTEM
The Electric Utility receives electricity at a single connection point with PG&E’s transmission
system. From there the electricity is delivered to customers through nearly 470 miles of
distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are
underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line
transformers, 1,075 underground and substation transformers, and the associated electric
services (which connect the distribution lines to the customers’ homes and businesses). These
lines, substations, transformers, and services, along with their associated poles, meters, and
other associated electric equipment, represent the vast majority of the infrastructure used to
deliver electricity in Palo Alto.
SECTION 5D: COST STRUCTURE AND REVENUE 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 5E: 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 5F: 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 compressed 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 6A: 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 6B: FY 2009 TO FY 2014 COST AND REVENUE TRENDS
The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in
Figure 7 and the tables in Appendix A (Electric Utility Financial Forecast Detail). These decreases
were partly related to declines in electricity market prices due to the impact of shale gas and
partly due to above average output from hydroelectric resources. These factors are discussed in
more detail in Section 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 6C: 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 6D: 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 regardless 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 6E: 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 6F: RISK ASSESSMENT AND RESERVES ADEQUACY
The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and
the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the
reserve minimum 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 6G: 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 average 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 6H: 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 expiration,
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 portfolio at prices under $65 per
megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those
contracts expire. Although recent prices have been in that range, 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 that project (and nearly 7% of the
utility’s total costs), so when the debt is retired, the project could be a low-cost asset for the
utility, providing carbon-free energy equal to 13% of the Electric Utility’s supply needs in an
average year.
Another factor that may affect the utility’s supply costs in the long run is carbon allowance
revenue. Currently the Electric Utility receives $3 to 5 million per year in revenue from
allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to
pay for energy efficiency and to purchase renewable energy to support the utility’s Carbon
Neutral Plan. That revenue source is expected to continue through 2020, but 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 numbers 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 continue 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 ASSUMPTIONS
SECTION 7A: ELECTRICITY PURCHASES
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 accommodate 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 7B: 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 7C: 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 undergrounding), 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 7D: 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 7E: 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 7F: WHOLESALE REVENUES AND 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 7G: 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 education
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
J u n e 1 6 , 2 0 1 4 40 | P a g e
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
J u n e 1 6 , 2 0 1 4 41 | P a g e
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
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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.)
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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.
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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
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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 Administration.
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their electric services.
Resource Management: This category includes supply portfolio management, energy
procurement, rate setting, and tracking of legislation and regulation related to the electric
industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
monitoring the substations and performing routine maintenance;
performing preventative maintenance on the system;
monitoring the system’s status from the UCC using SCADA;
maintaining the SCADA system;
investigating outages and other customer complaints and performing emergency
repairs;
clearing vegetation near overhead power lines; and
testing and replacing meters to ensure accurate sales metering.
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services, Utilities Department
administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering energy efficiency programs and
the direct cost of rebates paid. Includes solar rebates.
Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX G: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS
EXCERPTED DRAFT MINUTES OF THE APRIL 1, 2015
UTILITIES ADVISORY COMMISSION MEETING
ITEM: 5: ACTION: 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
Senior Resource Planner Jon Abendschein summarized the Electric Financial Plan. No rate
increase was proposed for July 1, 2016. He noted that staff was working on an Electric Cost of
Service Analysis (COSA) prior to a rate change effective in July 1, 2016. Abendschein noted that
the forecast assumed that the drought would end in the winter of 2016/2017. He then
presented a three year drought scenario in which the drought continued until the winter of
2017/2018. He showed that electricity costs increased due to an increase in market power
purchase costs as staff purchased more electricity as a result of the low hydroelectric
generation. These increased costs could be covered with larger than expected rate increases, or
with a rate adjustment mechanism that would be put in place to cover the increased costs due
to the droughts. Costs (and rates) would have to be 10% to 12% higher during an extended
drought. Reserves would be drawn down significantly, but not enough to present a danger to
the utility’s financial position.
Commissioner Eglash noted that it was appropriate to draw down reserves in the event of a
major contingency like an extended drought. He asked if the cost of maintaining a carbon
neutral supply portfolio would increase in a drought.
Abendschein stated that the increased cost of buying Renewable Energy Credits to match
increased market purchases was small and much lower than the limit of 0.15 cents/kWh.
Assistant Director Jane Ratchye added that the City’s future cost of Renewable Energy Credits
purchased to achieve carbon neutrality would be lower than it is currently due to new solar
contracts coming online. Even in this drought, the cost was much lower than the carbon
neutral spending limit.
Commissioner Hall recommended that the chart showing the Supply Fund reserves not show
the Electric Special Projects reserve. He said it makes it look like that reserve was available for
operational spending.
ATTACHMENT D
Abendschein said he would take that comment under consideration, but explained that the
presentation was intended to show all available unrestricted reserves to present a complete
picture of the utility’s financial position.
ACTION:
Commissioner Cook made a motion to approve staff’s recommendation that the UAC
recommend that the City Council adopt a resolution approving the FY 2016 Electric Financial
Plan, including no rate changes for July 1, 2015, and amending the Electric Utility Reserve
Management Practices. Commissioner Eglash seconded the motion. The motion carried
unanimously (6-0 with Commissioners Cook, Eglash, Hall, Melton, Foster, and Waldfogel voting
yes and Commissioner Chang absent).