HomeMy WebLinkAboutStaff Report 3604
City of Palo Alto (ID # 3604)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 4/16/2013
City of Palo Alto Page 1
Summary Title: Electric 5 -Year Financial Forecasts
Title: Utilities Advisory Commission Recommendation that the Finance
Committee Review the 5 -year Financial Forecast for the Electric Fund to
Determine Whether to Recommend that Council Approve an Adjustmen t to
Electric Rates Effective July 1, 2013
From: City Manager
Lead Department: Utilities
Recommendation
Staff and the Utilities Advisory Commission (UAC) recommend that the Finance Committee:
1. Review the 5-year Financial Forecasts for the Electric Fund; and
2. Recommend that the Council should not consider adjusting Electric Rates, effective July
1, 2013.
Draft Motion
Motion to:
1. Accept the Electric Fund five-year financial forecast and forward it to the full Council for
review and input.
2. Recommend that Council should not adjust Electric Rates effective July 1, 2013.
Executive Summary
Staff assessed major cost drivers and expected costs as well as the short -term risks and
determined the revenue requirements for the Electric Fund for the next five years. The
financial forecast shows that no rate adjustment is required for the Electric Fund for Fiscal Year
(FY) 2014 and FY 2015. Staff is projecting a need to adjust rates upward by 6% and 8% for FY
2016 and FY 2017, respectively. The projected revenue adjustmen ts achieve the goals of
ensuring that the balances of the Rate Stabilization Reserves are adequate and fall within the
Council-approved reserve guideline levels for the current five-year forecast horizon.
At its March 6, 2013 meeting, the UAC reviewed the 5-year financial forecasts for the Electric
Fund and recommended no change to current Electric Utility Rates.
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Background
The City of Palo Alto Utilities (CPAU) serves 29,500 electric customers over an area of
approximately 26 square miles. The City’s maximum demand for electricity in FY 2012 was
170.2 megawatts (MW) with a total consumption of electricity of 972 million kilowatt -hours
(kWh). The Electric Fund is responsible for operations and maintenance of the system and
purchases almost all of its electricity from outside of the City of Palo Alto, with the exception of
a 4.8 MW back-up generating facility and some local photovoltaic installations.
In order to maintain the financial viability of the Electric Fund, staff annually reviews the major
cost drivers, evaluates the risks and financial reserve adequacy, and determines the revenue
requirements for the Electric Fund for the next five years. The revenue requirements and
resulting revenue adjustment targets depend on a number of components includ ing sales
revenue projections, electric supply costs, distribution system operating and Capital
Improvement Program (CIP) expenses, prudent funding of the Electric Rate Stabilization
Reserves (RSRs), and debt service payments. Any change in one or more of these components
can trigger a change, up or down, to the revenue requirement. During the budget development
process, staff forecasts customer load, revenues and utility expenses to quantify the annual
revenue requirement.
Discussion
Financial Projections
Table 1 below shows the summary of financial projections for the Electric Fund for FY 2013
through FY 2018. Details of the Electric Fund’s financial projections are provided in Attachment
A. For FY 2012, the realized actual costs and revenues are base d on the City’s Comprehensive
Annual Financial Report (CAFR). For FY 2013 both budgeted and projected financial
expectations are shown. The projected column for FY 2013 reflects known variations from
budget as of January 2013. The projections for FY 201 4 through FY 2018 are based on
estimates prepared for the FY 2014 budget in December 2012. The final operating and CIP
budget requests will be presented to the Finance Committee in May.
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Table 1: Five-Year Financial Projections
($'000)
Actual Adopted Projected
2012 2013 2013 2014 2015 2016 2017 2018
1 % CHANGE IN TOTAL SYSTEM RETAIL RATE 0%0%0%0%0%6%8%2%
2 TOTAL AVERAGE RATE ($/KWH)0.115$ 0.119$ 0.119$ 0.119$ 0.119$ 0.126$ 0.136$ 0.139$
3 COMMODITY COST ($/KWH)0.048$ 0.061$ 0.053$ 0.062$ 0.069$ 0.070$ 0.070$ 0.069$
4 SALES IN GWH 943 991 951 981 979 977 975 973
5 CHANGE IN RETAIL SALES REVENUE ($'000)(31) 111 (5) - - 6,981 9,887 2,633
6
7 Utilities Retail Sales 107,415 116,827 111,984 115,633 115,400 121,807 131,380 134,020
8 Surplus Energy Sales 2,323 1,627 2,289 2,316 3,473 4,001 5,321 5,497
9 Carbon Allowance Revenue - 2,597 2,162 4,296 4,148 4,117 4,340 4,536
10 Service Connection Charges 1,468 900 900 1,160 1,595 1,405 2,015 2,150
11 CVP O&M Loan Credit 4,856 7,000 6,808 6,000 6,000 6,000 6,000 6,000
12 Other Revenues plus Transfers In 1,142 2,673 2,673 2,651 2,381 4,115 4,186 4,260
13 Interest plus Gain or Loss on Investment 4,099 3,635 3,635 3,226 2,765 2,485 2,256 2,206
14 Total Sources of Funds 121,303 135,259 130,451 135,281 135,762 143,930 155,497 158,670
15
16 Purchases to Serve Load 50,527 63,442 55,638 65,233 72,468 73,264 72,905 72,519
17 Surplus Energy Cost 3,198 1,577 2,828 2,304 3,446 3,683 4,804 4,882
18 Joint Venture Debt Service 8,803 9,383 9,268 9,024 9,028 9,040 8,854 8,855
19 CVP O&M Loan Advance 4,866 7,000 6,808 6,000 6,000 6,000 6,000 6,000
20 Supply Operations 3,415 6,634 6,634 7,256 8,183 8,700 9,149 9,577
21 Distribution Operations 20,292 24,733 24,621 24,631 25,416 26,415 27,531 28,488
22 Rent 3,598 3,704 3,704 3,815 3,929 4,047 4,168 4,293
23 General Fund Transfers 11,587 11,768 11,768 11,110 11,112 11,129 11,233 11,439
24 Other Transfers Out 299 322 322 322 322 322 322 322
25 Capital Improvement Programs 9,510 10,910 9,113 7,830 8,585 11,735 12,780 11,520
26 Total Uses of Funds 116,095 139,472 130,702 137,525 148,489 154,333 157,747 157,896
27
28 Into/ (Out of) Reserves 5,209 (4,213) (250) (2,244) (12,726) (10,404) (2,250) 774
City of Palo Alto
Electric Utility
Fiscal Year
FY 2012 Expenses and Revenues
Total expenses (Row 26 in Table 1) totaled $116.1 million in FY 2012, or $15.9 million lower
than budgeted. Total revenues (Row 14 in Table 1) were $121.3 million in FY 2012, or $3.9
million lower than budgeted. The biggest variation in expenses in FY 2012 was $11.5 million
due to lower-than-expected purchase costs to serve load. Lower electric consumption
accounted for a portion of the cost savings; consumption was 1.5% below the budget estimate.
However, the lower costs were achieved primarily due to a fortuitous increase in the quantity
of hydroelectric generation relative to what was budgeted, as well as attributed to market
prices that were much lower than projected (approximately 27%). Decreased costs for
renewable power due to the postponement of interconnection payments for the Crazy Horse
and San Joaquin projects until FY 2013, and a later-than-anticipated start date for the Johnson
Canyon project also contributed to lower overall costs. Transmission costs were also lower
than expected. Other supply related expenses include surplus energy costs, which were higher
than budgeted due to the higher than budgeted surplus energy availability. The CVP O&M loan
advance was reduced by $2.1 million due to changes in project plans. The Electric Fund also
realized a $3.7 million savings in distribution operations, and $2.8 million savings in supply
operations costs.
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As a result of these variations from budgeted amounts, the Electric Supply Rate Stabilization
Reserve (E-SRSR) was funded by a total of $8.8 million, instead of the $1.3 million budgeted
drawdown in FY 2012. A total of $0.6 million was drawn from the Electric Distribution Rate
Stabilization Reserve (E-DRSR) instead of a budgeted funding of $0.4 million.
FY 2013 Expenses and Revenues
The projections for FY 2013 follow a similar pattern. Total expenses are expected to be $8.7
million lower than budgeted. This is mainly due to $6.9 million lower -than-budgeted supply
costs (Rows 16, 17, 18 and 19 in Table 1). The lower supply co sts are due to lower-than-
expected load, reduced renewable energy purchase costs due to delays in the start dates of
three new landfill gas renewable energy projects, lower-than-projected transmission rates, and
the greater availability of hydro resources. Increased hydro generation projections are
expected to result in increased surplus energy sales as well as increased surplus energy costs.
In addition, the CIP budget was decreased by $1.8 million, mainly due to reduced cost
projections for a 60kV re-conductoring project, as well as the removal of a substation project
from CIP budget consideration in order to conduct further evaluation. The operating expenses
are expected to fall within the budgeted amount.
Expected sales revenues for FY 2013 are below budgeted levels, with usage being lower across
all customer groups, but the main driver of the decrease in usage is a delay in the schedule of a
significant load addition for a large customer. With the expected increases in surplus energy
sales offsetting, total revenues in FY 2013 are expected to be $5.1 million lower than budgeted.
The net result of reduced expenses and revenues is an expected funding of the Electric RSRs by
$0.6 million in FY 2013, instead of the budgeted drawdown of $3.4 million.
FY 2014 to FY 2018 Cost Drivers
Electric Fund expenses are projected to be $6.8 million higher in FY 2014 than in FY 2013,
mainly due to expected increases in the electric purchase costs ($9.6 million) due to additional
renewable projects coming on line, higher transmission cost expectations and Western cost
increases. The higher purchase costs are partially offset by CIP projects in FY 2014 that are
projected to be lower by $1.3 million, mainly due to a restructuring of existing and future
project timelines to reflect a backlog of projects. In addition, the General Fund transfer is
projected to decrease by $0.7 million in FY 2014 because the Council -adopted equity transfer
methodology calculation uses PG&E’s allowed Return on Equity, which was recently lowe red by
the California Public Utilities Commission (CPUC) from 11.35% to 10.4%. Additionally, CVP
O&M loan advances are projected to be lower by $0.8 million, but this will be offset by an
equivalent revenue decrease.
For the longer term horizon, Electric Fund costs are expected to increase by $27.2 million from
$130.7 in FY 2013 to $157.9 million in FY 2018, an average annual increase of 3.9 percent. This
is mainly driven by the expected increases in electric purchase costs ($16.8 million). The
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increase in electric purchase costs is largely driven by the increased California Independent
System Operator (CAISO) costs associated with high-voltage and low-voltage transmission
access charges (HV/LV TAC) ($3.4 million); more renewable resources in the portf olio in order
to meet the Renewable Portfolio Standard (RPS) ($12.7 million); expected increases in the costs
for Western ($1.6 million); resource adequacy requirements for local capacity ($1.0 million);
and a 3% increase in demand over the forecast horizon. These cost increases will be partially
offset by a projected decrease in market purchases ($1.8 million).
Other operating expenditures such as operations, maintenance, and rent are projected to
increase by 3% per year. Salary and benefit cost projections are from the City’s long-range
financial forecast.
Capital Improvement Program (CIP)
CIP project funding accounts for 6.9% of the operating budget in FY 2013 and is expected to
increase by $2.4 million from $9.1 million in FY 2013 to $11.5 million in FY 2018. Table 2 shows
the planned CIP expenditures by project for FY 2014 through FY 2018.
Major ongoing CIP projects in FY 2014 include electric system improvements of $2.4 million and
customer connections of $2.2 million. Customer connection expense s are partially offset by
customer connection service fee revenues of $0.93 million. Special CIP projects include $0.5
million for FY 2014 for a project to upgrade all City street lighting to high efficiency LED lights
(EL-10009), and a smart grid technology project (EL-11014). It is expected that the smart grid
project expense will be partially offset by reimbursements and grant funding of about 65% of
this amount.
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Table 2: Capital Improvement Program Plan (FY 2014 - FY 2018)
2013-14 2014-15 2015-16 2016-17 2017-18
WBS Desc.Exp.Rev.Exp.Rev.Exp.Rev.Exp.Rev.Exp.Rev.
EL-02010 SCADA System Upgrade $0 $0 $60,000 $0 $65,000 $0 $270,000 $0 $60,000 $0
EL-02011 Electric Utility GIS $225,000 $0 $165,000 $0 $165,000 $0 $165,000 $0 $165,000 $0
EL-04010 Foothills System Reb $75,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-04012 Utility Site Securit $0 $0 $250,000 $0 $250,000 $0 $0 $0 $0 $0
EL-05000 El Camino Undergroun $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-06001 230 kV Electric Inte $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-06003 Utility Control Cent $75,000 $0 $0 $0 $0 $0 $400,000 $0 $0 $0
EL-08001 UG District 42 Embar $0 $0 $0 $0 $150,000 $0 $150,000 $0 $2,000,000 -$750,000
EL-09002 Middlefield/Colorado
EL-09004 W. Charleston/Wilkie $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-10009 Street Light System $500,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-11000 Seale/Waverley 4/12k $0 $0 $75,000 $0 $325,000 $0 $0 $0 $0 $0
EL-11002 St. Francis Oregon 4 $0 $0 $100,000 $0 $350,000 $0 $0 $0 $0 $0
EL-11003 Rebuild UG Dist 15 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-11009 UG District 43 Alma/$0 $0 $0 $0 $150,000 $0 $2,000,000 -$700,000 $500,000 $0
EL-11010 UG District 47 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-11014 Smart Grid Technolog $1,000,000 -$666,667 $500,000 -$333,333 $3,000,000 -$2,000,000 $3,000,000 -$2,000,000 $3,000,000 -$2,000,000
EL-11015 Reconductor 60kV OH $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-11016 EV Charger
EL-12000 Rebuild UG Dist 12 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-12001 UG District 46 $0 $0 $800,000 -$400,000 $150,000 -$150,000 $0 $0 $0 $0
EL-12002 Hanover 22 - Tfmr Re $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-12003 HO Sub Rebuild $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-13000 Edgewood / Wildwood $0 $0 $0 $0 $50,000 $0 $400,000 $0 $0 $0
EL-13002 Relocate QR/HO 60kV $0 $0 $0 $0 $100,000 $0 $750,000 $0 $0 $0
EL-13003 Rebuild UG Dist 16 $0 $0 $0 $0 $300,000 $0 $0 $0 $0 $0
EL-13004 HW / HV 12kV Ties $200,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-13005 Repl CO 20/21 Transf $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-13006 Sand Hill / Quarry 1 $200,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-13007 UG Dist System Secur $0 $0 $300,000 $0 $300,000 $0 $0 $0 $0 $0
EL-13008 Upgrade Estimating S $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-14000 Coleridge/Cowper/Ten $0 $0 $120,000 $0 $400,000 $0 $0 $0 $0 $0
EL-14002 Rebuild UG Dist 20 $0 $0 $500,000 $0 $500,000 $0 $0 $0 $0 $0
EL-14003 Hanover 24/25 Lineup $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-89028 Electric Customer Co $2,200,000 -$1,000,000 $2,300,000 -$1,025,000 $2,400,000 -$1,075,000 $2,500,000 -$1,125,000 $2,600,000 -$1,200,000
EL-89031 Communications Syste $0 $0 $100,000 $0 $100,000 $0 $100,000 $0 $100,000 $0
EL-89038 Substation Protectio $275,000 $0 $280,000 $0 $290,000 $0 $300,000 $0 $300,000 $0
EL-89044 Substation Facility $180,000 $0 $185,000 $0 $190,000 $0 $195,000 $0 $195,000 $0
EL-98003 Electric System Imp $2,400,000 -$160,000 $2,450,000 -$170,000 $2,500,000 -$180,000 $2,550,000 -$190,000 $2,600,000 -$200,000
EL-14004 MB 1 & 2 - 4/12kV Conv $450,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
EL-14005 Quarry Feeder Reconfig $50,000 $0 $400,000 $0 $0 $0 $0 $0 $0 $0
$0 $0
$0 $0
Total $7,830,000 -$1,826,667 $8,585,000 -$1,928,333 $11,735,000 -$3,405,000 $12,780,000 -$4,015,000 $11,520,000 -$4,150,000
FY 2014-FY 2018 Revenue Projections
Retail sales constitute the largest source of revenue for the Electric Fund, and electric demand
projections are discussed in detail in the following section. Interest and gains on investments in
future years are calculated assuming a 2.2% return on investment. Other revenues include:
grant funding of $0.7 million to $2.0 million for smart grid technology; surplus energy sales that
are expected to increase from $2.3 million in FY 2013 to $5.5 million in FY 2018 due to
increased market prices and excess resources during certain times of the year throughout the
forecast horizon; and carbon allowance revenues resulting from the State’s cap -and-trade
program starting in FY 2013. It is expected that the cap-and-trade program will generate
revenues for the Electric Fund of over $4 million/year. Since this is a new program with
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regulatory requirements dictating how the revenues may be allocated or spent, its impact on
the overall revenue requirements is uncertain at this time.
Electricity Usage
Electric usage has generally been stable in the City over the past 10 years. After a significant
drop of 15% from its peak of 1,124 gigawatt hours (GWh) in FY 1999 to 956 GWh in FY 2003 due
to the regional economic downturn, usage increased at an average ra te of 1.0% per year during
the following six years until FY 2008. From 2008, usage began decreasing due to the latest
economic slowdown together with energy efficiency (EE) savings, dropping by a total of 8% over
the last four years. In FY 2014 usage is expected to be 3.7% higher than in FY 2013. In FY 2015
and beyond, demand is expected to decline at an average rate of 0.2% per year until FY 2018.
The projections of electricity usage are developed using an econometric model that takes into
account the effect of local weather conditions as well as recent changes in customers’ energy
usage patterns. The projections also incorporate assumptions about the impact of current and
future EE and conservation programs, known changes in large customer demands, deployment
of photovoltaic (PV) systems and market penetration of electrical vehicles (EVs). EE programs
are expected to account for total energy savings of about 8.1% or 83 GWh by FY 2022.
Similarly, it is expected that by 2022, local PV systems will be replacing 16 GWh of electricity
purchases, reducing Palo Alto’s peak demand by 9 MW by the end of FY 2022.
On the other hand, the City expects that by 2022 roughly 10,700 residential and commercial
customers will be charging their EVs in the City, increasing demand by roughly 31 GWh, and
adding 700 kW to the City’s peak demand in 2022. The combined effects of EVs, PV systems,
and EE programs will account for a net decrease of 68 GWh of electricity demand and 11 MW of
peak demand by FY 2022 from what would otherwise be projected.
In the short term, a sizable load increase due to a customer’s plans to move some of its
operations to Palo Alto is expected to increase electricity demand by 3.0%. Another significant
customer project is expected to increase electricity demand by 1.8% after partial completion in
2015. Full completion of this project is expected to occur by 2025.
Figure 1 presents the City’s historical electric consumption levels from FY 2001 through FY 2012
and projections for FY 2013 through FY 2022.
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Figure 1
Revenue Requirement
The revenue requirement is the total amount of revenue that must be collected in order to
meet the planned expenditures for the Electric Fund. Based on the expected revenues and
costs presented in this report, the Electric Fund is projected to have a revenue shortfall during
most of the forecast horizon. However, given the level of its RSRs, the Electric Fund does not
require any revenue adjustments until FY 2016. It is expected that revenue adjustments of 6 %,
8% and 2% will be necessary in FY 2016, FY 2017 and FY 2018 respectively, in order to maintain
adequate reserves for the forecast horizon.
The Electric Fund’s projected costs and revenues from FY 2012 through FY 2018 are depicted in
Figure 2 below.
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Figure 2
Reserves and Risk Assessment
The Council-approved guidelines for the Electric Supply Rate Stabilization Reserve (E -SRSR) and
Electric Distribution Rate Stabilization Reserve (E-DRSR) require an annual assessment of short-
term uncertainties and risks for the supply and distribution business units.
The short-term risks considered for the E-SRSR include:
1. “Load net revenue” risk is defined as the cost of purchasing additional supplies to meet
higher than expected demands at market prices higher than the average retail supply rate;
2. Hydro generation risk is the cost of purchasing additional electricity to offset one year of
low hydroelectric production (in a 1-in-10 year dry hydro scenario);
3. Renewable energy production risk is the cost of purchasin g more electricity from the
market than expected due to lower than expected renewable energy production from
existing, low-cost (wind and landfill-gas-to-energy) renewable resources;
4. Expected market price uncertainty is a function of the exposed portion of the supply
portfolio for energy and capacity and market price uncertainty. As of December 2012, 12%
and 10% of the electric supply portfolio was exposed to market prices for FY 2014 and FY
2015, respectively; and
5. Other risks assessed include transmission related cost uncertainties, plant outage
probabilities, Western hydroelectric resource cost uncertainties, regulatory and legal risks,
supplier credit default risks for both renewable and wholesale power counterparties,
carbon neutral costs and local capacity costs.
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Table 3 summarizes short-term cost uncertainties evaluated for the next two years. The sum of
these adverse outcomes totals $23.7 million in FY 2014 and $28.4 million in FY 2015. As shown,
the largest single risk by far is related to hydro p roduction.
Table 3: Short-Term Electric Supply Cost Risks
Electric Supply Cost Uncertainties Estimates of Adverse Outcomes (M$)
FY 2014 FY 2015
1. Load Net Revenue 0.5 0.9
2. Hydro Production: Western and Calaveras 9.6 11.6
3. Renewable Production: Landfill and Wind 0.5 0.5
4. Carbon Neutral Cost 0.3 0.4
5. Market Price 1.4 1.8
6. Local Capacity 0.4 0.8
7. Transmission/CAISO 1.3 2.6
8. Plant Outage 1.0 1.0
9. Western Cost 2.9 3.1
10. Regulatory & Legal 4.3 4.2
11. Supplier Default 1.5 1.5
Electric Supply Fund Risks $23.7 $28.4
For the E-DRSR, the two sources of uncertainty are 1) the revenue shortfall due to a reduction
in electric demand; and 2) unforeseen cost increases in the planned CIP program. The estimate
of revenue shortfall is calculated based on the maximum observed budget to actual variance in
one year during the past ten years, and the unforeseen cost increase is calculated based on a
variance of 10% in planned CIP expenditures for the budget year. The sum of these two risks is
$6.8 million in FY 2014 and $6.9 million in FY 2015.
It should be noted that the risks accounted for in this analysis are both disparate and
independent, and there is an extremely remote probability that a number of these risks would
be realized simultaneously. As a result, the total should be treated as an indicative number
only, and not a reflection of the expected risk exposure. Additionally, the risks listed for the
supply RSR are inversely correlated with some of the risks identified for the distri bution RSR.
Specifically, load uncertainty is a risk to the supply RSR when loads are higher than expected,
but a risk to the distribution RSR when loads are lower than expected. As such, the summation
of the supply RSR risks is not considered as additio nal to the risks in the distribution RSR.
Rate Stabilization Reserve Adequacy
Table 4 summarizes electric supply and distribution long-term RSR guidelines, short-term
assessment of risks, and estimated end-of-year reserve balances for the E-SRSR and the E-DRSR
for the current and the next two fiscal years.
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Table 4: Electric RSR Guideline Levels and Short Term Risk Assessment ($M)
Electric Supply Rate Stabilization Reserve FY 2013 FY 2014 FY 2015
Estimated End of Year Balance 66.8 58.2 45.1
Risk Assessment 23.4 23.7 28.4
Minimum Level Guideline (50% of supply purchase costs) 31.7 32.6 36.2
Maximum Level Guideline (100% of supply purchase costs) 63.4 65.2 72.5
Electric Distribution Rate Stabilization Reserve
Estimated End of Year Balance 8.4 10.7 11.1
Risk Assessment 7.0 6.8 6.9
Minimum Level Guideline (15% of sales revenues) 6.7 6.7 6.7
Maximum Level Guideline (30% of sales revenues) 13.5 13.4 13.3
The estimated end-of-year balance for the E-SRSR in FY 2013 is above the long-term maximum
reserve guideline levels. With no revenue increase projected, the reserve level in FY 2014 falls
within the long-term minimum and maximum reserve guideline levels and still remains above
the short-term risk assessment level. The E-DRSR estimated year-end balance is projected to be
above the short-term risk assessment levels and within the long-term minimum and maximum
reserve guideline levels in all three years.
Figures 3 and 4 show E-SRSR and E-DRSR levels, short-term risk assessment levels, and long-
term reserve maximum and minimum guideline levels for the duration of financial projections.
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Figure 3
Figure 4
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Rate Comparison with Neighboring Cities
The City currently has an electric cost advantage compared to neighboring cities served by the
Pacific Gas and Electric Company (PG&E). However, Santa Clara, served by Silicon Valley Power,
has rates that result in a lower bill for all but the lowest use residential customers. Table 5
presents residential monthly bills for Palo Alto and surrounding cities for a several usage levels
based on published rates as of February 1, 2013. Comparisons for the median are based on
Palo Alto’s median residential usage levels of 365 kWh/month in the summer months (May -
Oct) and 453 kWh/month in the winter months (Nov-Apr). Note that for the median residential
usage, PG&E customers pay 28% more than Palo Alto’s customers.
Table 5: Residential Electric Bill Comparison
Residential Monthly Electric Bill As of February 1, 2013
Usage (KWh/mo) Palo Alto Mountain
View
Redwood
City
Menlo
Park
Santa
Clara
Average City
Benchmark
300 $ 28.57 $ 39.69 $ 39.69 $ 39.69 $ 30.37 $ 37.36
(Median) 365/453 $ 42.76 $ 54.58 $ 54.58 $ 54.58 $ 41.81 $ 51.39
650 $ 76.33 $ 120.43 $ 120.43 $ 120.43 $ 67.11 $ 107.10
1200 $ 172.03 $ 305.49 $ 305.49 $ 305.49 $ 124.84 $ 260.33
Commission Review and Recommendations
At their February 13 and March 6, 2013 meetings, the UAC reviewed the 5 -year financial
forecasts for the Electric Fund. The February meeting was a preview of the financial forecasts
and the UAC discussed the CIP deferrals and their impact on operations, and the reasons for the
backlog of projects and staffing shortages. At their following March me eting, the UAC clarified
that the costs of the carbon neutral plan were included in the forecasted expenses and that
these costs did not result in the need for a rate increase for FY 2012.
On March 6, 2013 the UAC voted 6-0, with one Commissioner absent, to recommend that
Council not adjust Electric Rates effective July 1, 2013. The excerpted draft notes from the
UAC’s March 6, 2013 meeting are provided as Attachment B, and excerpted final minutes from
the February meeting are provided in Attachment C.
Environmental Review
This recommendation does not meet the California Environmental Quality Act’s definition of a
“project” under Public Resources Code Section 21065.
Attachments:
Attachment A: Electric Utility Financial Projections (FY 2014 -FY 2018) (PDF)
Attachment B: Excerpted Draft Minutes of March 6, 2013 UAC Meeting (PDF)
Attachment C: Excerpted Final Minutes of Feb 13, 2013 UAC Meeting (PDF)
$ (000's)
Actual Adopted Projected
2012 2013 2013 2014 2015 2016 2017 2018
1 % CHANGE IN RETAIL RATE 0%0%0%0%0%6%8%2%
2 TOTAL AVERAGE RATE (MILLS/KWh)115 119 119 119 119 126 136 139
3 SALES UNITS (GWh)943 991 951 981 979 977 975 973
4 ELECTRIC FUND REVENUE
5 BASE SALES REVENUES:
6 COMMODITY SALES 64,101 69,580 66,720 68,875 68,737 68,570 75,240 82,280
7 DISTRIBUTION SALES 41,238 44,978 43,130 44,523 44,433 44,325 44,256 46,542
8 PUBLIC BENEFIT REVENUE 3,035 3,159 3,135 3,232 3,225 3,218 3,406 3,671
9 SUB-TOTAL BASE SALES REVENUE 108,374 117,717 112,985 116,629 116,396 116,112 122,901 132,493
10 RATE ADJUSTMENT:
11 COMMODITY 0 0 0 0 0 6,788 7,223 0
12 DISTRIBUTION 0 0 0 0 0 0 2,390 2,560
13 PUBLIC BENEFIT (31)111 (5)0 (0)193 274 73
14 TOTAL RATE ADJUSTMENT (31)111 (5)0 (0)6,982 9,887 2,633
15 PRORATION IMPACT 1 (5)0 (0)0 (291)(412)(110)
16 TOTAL ADJUSTED SALES REVENUE 108,344 117,823 112,980 116,629 116,396 122,803 132,376 135,016
17 DISCOUNTS/UNCOLLECTABLES (929)(996)(996)(996)(996)(996)(996)(996)
18 INTEREST 4,099 3,635 3,635 3,226 2,765 2,485 2,256 2,206
19 SURPLUS ENERGY REVENUE 2,323 1,627 2,289 2,316 3,473 4,001 5,321 5,497
20 CARBON ALLOWANCE REVENUE 0 2,597 2,162 4,296 4,148 4,117 4,340 4,536
21 PA-GREEN SALES REVENUE 1,133 1,220 1,220 1,281 1,345 1,412 1,483 1,557
22 SERVICE CONNECTION CHARGES 1,468 900 900 1,160 1,595 1,405 2,015 2,150
23 CVP O&M FUNDING 4,856 7,000 6,808 6,000 6,000 6,000 6,000 6,000
24 OTHER REVENUE 9 1,453 1,453 1,370 1,036 2,703 2,703 2,703
25 FROM RESERVES:
26 SUPPLY RSR 0 3,142 0 4,549 13,112 8,062 569 142
27 DISTRIBUTION RSR 560 239 290 0 0 2,341 1,681 0
28 CALAVERAS 5,238 0 0 0 0 0 0 0
29 P.B. RESERVE 1,990 833 967 0 0 0 0 0
30 ENCUMBRANCES / REAPPROPRIATIONS (3,689)
31 TOTAL FROM RESERVES 7,789 4,213 1,257 4,549 13,112 10,403 2,250 142
32 TOTAL FINANCIAL RESOURCES 125,403 139,473 131,709 139,830 148,874 154,333 157,747 158,812
33 OPERATING EXPENSES
34 SUPPLY
35 PURCHASES 50,527 63,442 55,638 65,233 72,468 73,264 72,905 72,519
36 SURPLUS ENERGY COST 3,198 1,577 2,828 2,304 3,446 3,683 4,804 4,882
37 PA-GREEN POWER PURCHASES 133 972 972 1,021 1,072 1,125 1,181 1,241
38 CALAVERAS DEBT SERVICE 8,803 9,383 9,268 9,024 9,028 9,040 8,854 8,855
39 CVP O&M FUNDING 4,866 7,000 6,808 6,000 6,000 6,000 6,000 6,000
40 SUPPLY FUNDED ALTERNATIVE RESOURCES 1,165 3,025 3,025 3,501 4,276 4,634 4,919 5,175
41 RESOURCE MANAGEMENT, OTHER ADMIN 1,489 2,186 2,186 2,267 2,351 2,438 2,528 2,622
42 ALLOCATED CHARGES:
43 COST PLAN CHARGES & OTHER 353 154 154 160 166 172 178 185
44 UTILITIES ADMINISTRATION 274 296 296 307 319 330 343 355
45 SUB-TOTAL SUPPLY 70,809 88,036 81,174 89,817 99,125 100,686 101,712 101,834
46 DISTRIBUTION
47 OPERATIONS & MAINT, OTHER ADMIN 11,606 12,960 12,960 13,439 13,936 14,452 14,987 15,541
48 PUBLIC BENEFITS PROGRAMS 5,010 4,098 4,098 3,232 3,225 3,403 3,668 3,741
49 CUSTOMER DESIGN & CONNECTION CIP 2,000 2,100 775 2,200 2,300 2,400 2,500 2,600
50 SYSTEM IMPROVEMENT (CIP)6,590 7,485 7,013 5,130 6,185 9,235 10,180 8,820
51 STREET LIGHT, TRAFFIC SIGNAL O&M 623 874 874 907 940 975 1,011 1,048
52 STREET LIGHT, TRAFFIC SIGNAL CIP 800 1,200 1,200 500 0 0 0 0
53 COMMUNICATIONS O&M & CIP 384 391 391 276 386 397 408 419
54 ALLOCATED CHARGES:
55 COST PLAN CHARGES & OTHER (156)3,111 3,111 3,226 3,346 3,469 3,598 3,731
56 UTILITIES ADMINISTRATION 2,945 3,425 3,425 3,551 3,683 3,819 3,960 4,107
57 SUB-TOTAL DISTRIBUTION 29,802 35,643 33,846 32,461 34,001 38,150 40,311 40,008
58 TRANSFERS:
59 GENERAL FUND TRANSFER 11,587 11,768 11,768 11,110 11,112 11,129 11,233 11,439
60 RENT 3,598 3,704 3,704 3,815 3,929 4,047 4,168 4,293
61 OTHER TRANSFERS 299 322 322 322 322 322 322 322
62 TOTAL OPERATING EXPENSES 116,095 139,472 130,814 137,525 148,489 154,333 157,747 157,896
63 RESERVE FUNDING:
64 PLANT REPLACEMENT 0 0 0 0 0 0 0 0
65 SUPPLY RSR 8,839 0 895 0 0 0 0 0
66 DISTRIBUTION RSR 0 0 0 2,305 386 0 0 915
67 P.B. RESERVE 0 0 0 0 0 0 0 0
68 CALAVERAS INTEREST 0 0 0 0 0 0 0 0
69 TOTAL RESERVE FUNDING 8,839 0 895 2,305 386 0 0 915
70 TOTAL REVENUE REQUIREMENT 124,934 139,472 131,709 139,830 148,875 154,333 157,747 158,811
71 RESERVES BALANCES
72 PLANT REPLACEMENT 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
73 DISTRIBUTION RSR 8,681 8,442 8,391 10,695 11,081 8,740 7,059 7,974
74 SUPPLY RSR 65,930 62,788 66,825 58,239 45,128 37,065 36,497 36,355
75 SPECIAL PROJECTS 50,320 50,320 50,320 50,320 50,320 50,320 50,320 50,320
76 P.B. RESERVE BALANCE 1,148 316 181 316 316 316 316 316
77 TOTAL RESERVES BALANCE 127,079 122,866 126,717 120,571 107,845 97,441 95,191 95,965
78 COMMITEMENTS AND REAPPROPRIATIONS 19,169 19,169
79
80 Short Term Risk Assessment Value -Supply RSR 18,100 23,400 23,400 23,700 28,400
81 Short Term Risk Assessment Value- Distribution RSR 6,600 7,085 7,085 6,785 6,878
82
83 Long Term Rate Stabilization Guidelines
84 Supply RSR Minimum 31,018 31,721 31,721 32,617 36,234 36,632 36,452 36,260
85 Supply RSR Maximum 62,035 63,442 63,442 65,233 72,468 73,264 72,905 72,519
86
87 Distribution RSR Minimum 6,391 6,747 6,747 6,678 6,665 6,649 6,997 7,365
88 Distribution RSR Maximum 12,783 13,494 13,494 13,357 13,330 13,298 13,994 14,731
89
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Excerpted Draft
Utilities Advisory Commission Meeting
Minutes of March 6, 2013
ITEM 2: ACTION: Staff Recommendation that the Utilities Advisory Commission Review the 5 -
Year Financial Forecast for the Electric Fund and Take Action on Whether to Recommend that
Council Approve an Adjustment to Electric Rates Effective July 1, 2013
Director Fong stated that the commission had a preview of the financial forecasts for all funds
at the February meeting, but that during today’s presentation, staff will point out any changes
from the presentation last month.
Resource Planner Eric Keniston stated that no rate adjustments were warranted for the electric
fund for the next two years and only small rate adjustments were forecast in the last three
years of the financial forecast period.
ACTION:
Commissioner Melton made a motion to recommend that the Council not adjust Electric Rates
effective July 1, 2013. Commissioner Eglash seconded the motion. The motion carried (6 -0)
with Commissioner Chang absent.
Commissioner Eglash asked if the costs for the carbon neutral plan are included in the
forecasted expenses. Keniston stated that those costs were incorporated into the financial
forecast.
Chair Cook asked for clarification that the cost of implementing the carbon neutral plan would
not result in the need for a rate change in FY 2014. Keniston replied that these costs would not
require a rate increase for FY 2014.
Excerpted Final
Utilities Advisory Commission Meeting
Minutes of February 13, 2013
ITEM 2: PRESENTATION: Presentation on Financial Projections for the City’s Electric, Gas,
Water and Wastewater Collection Utilities
Assistant Director Jane Ratchye stated that the presentation on the financial forecasts is a
preview of next month's discussion. This month no information was provided in advance of the
presentation, but next month the full report will be provided with all information. In this
presentation, we will be showing options for the water and wastewater funds and would like to
get some feedback from the commission on these options.
Resource Planner Eric Keniston provided an overview of the 5-year financial forecasts for all
funds, stating it was possible to not have any rate increases for FY 2014. This is different from
last year’s financial projections, which had forecast the need for increases of 15% for water and
9% for wastewater. Electric and gas show no need for changes at this time. T here have been
some significant savings related to Capital Improvement Programs (CIP).
For the Electric Fund, no rate increases were shown to be needed, but supply costs
(renewables, transmission) were projected to increase, and distribution costs were pr ojected to
decrease due to decreased Capital Improvement Program (CIP) budgets in the next two years.
This was due to a backlog of projects as well as vacancies (under -filled positions, retirements,
fewer trainers for new employees). No rate increases are shown to be needed until FY 2016.
Commissioner Cook asked why there were vacancies in this economy, and whether it was a
structural issue. Director Fong stated that for skilled positions such as electric and gas
engineers there is a shortage.
Commissioner Eglash added that this is an industry wide problem for utilities.
Commissioner Hall observed that the large drop in CIP expenses is significant, and
Commissioner Cook asked whether this could cause a problem in the future with operations.
Director Fong stated that if a project came up that was required immediately, those would be
done.
Vice Chair Foster asked if there were zero dollars budgeted for undergrounding for FY 2014.
Keniston confirmed that this is true.
Regarding the Gas Fund, Keniston stated that since all customers now have market rate gas
commodity costs, the net revenue profile is relatively steady. In addition, other components
were brought into alignment with cost of service study as of the rates effective July 1, 2012. CIP
deferrals for two years will cause distribution costs to fall significantly so that the distribution
rate stabilization reserve (RSR) levels are projected to rise above the maximum guideline level
for several years. Options are to let the reserves be where they are, or to have rate decreases
(with increases later). The gas supply RSR is more of a cash flow reserve as market -based
commodity costs are passed through to customers. With a two month lag between billing and
revenue collection, funds should be in place to cover the potentially expensive float needed for
winter gas.
Commissioner Cook asked if the minimum and maximum guidelines are legal requirements.
Keniston replied that they are not legal requirements.
Commissioner Melton asked whether the high amount for the gas distribution RSR was all due
to CIP deferrals. Keniston confirmed that it was.
Commissioner Eglash asked if, given market prices for gas sales, whether RSR needs been re -
assessed. Assistant Director Ratchye stated staff will reasse ss the appropriate reserve levels
after completion of a rates policy. Director Fong added that the reserve is needed for cash
flow, so the reserve needs may not necessarily be reduced, but may be based on when we pay
for gas and when we receive the corresponding revenue from customers.
Keniston stated that the Water fund has seen large cost increases over the last few years. In FY
2014, it is possible to have no rate increase, although large increases would be needed starting
in FY 2015 if there were no rate increase for FY 2014. The reasons for lower expenses this year
include a return of capital funds in FY 2013 and a deferral of main replacement projects by one
year. Therefore, the Water RSR will be near to the maximum guideline level instead of the
minimum for FY 2013. Keniston stated that an alternative rate increase profile would be 7%
annual increases for the 5-year period.
Commissioner Hall asked if the SFPUC rates rising will be offset by the CIP decreases. Keniston
replied that this is the case for next year.
Commissioner Melton stated that if there is no rate increase next year, the following year
increase will be much higher and that in the past, the UAC generally counseled against that.
Commissioner Hall stated he preferred a level rate increase trajectory.
Regarding the wastewater fund, Keniston stated last year a 9% increase was projected for FY
2014, but with CIP main replacement deferrals of one year, revenues are expected to be above
expenses and the wastewater RSR is expected to be above the maximum guideline for FY 2014.
A double digit rate increase will possibly be needed in FY 2015. An alternative plan could have
a small increase in FY 2014, but reserves would be pushed above maximum guideline levels
with anything more than a small increase.
Commissioner Melton asked whether the cost growth was due to the treatment plant cost
going up. Keniston confirmed that this was the case.
Commissioner Melton stated that temporarily exceeding the maximum guideline level is not as
significant as dipping below the minimum guideline level. A one year peak over maximum is
not a big deal.
Commissioner Eglash stated he was uncomfortable with taking more money from ratepayers
simply to bank it for future cost increases. He would rat her leave the money with ratepayers,
especially when the reserve levels are above the maximum guideline level.
Commissioner Waldfogel stated the reserves should reflect deferred or accrued maintenance
cost. It sounds like there isn’t a plan to try and catch up with CIP projects.
Commissioner Eglash agreed, saying he was on a UAC committee reviewing the CIP in the past
and was impressed with the long-term plan to be current with infrastructure replacements. It is
a reason to be very proud of CPAU, but the notion when you can't spend at the rate you would
like to, or to treat CIP deferrals as a savings instead of a known cost or deferred expense for the
future creates some unease.
Director Fong added that CPAU has always practiced ‘pay as you go’ for CI P expenditures. The
consideration of budgeting for future CIP expenses is possibly in conflict the idea of not holding
more of ratepayer funds than actual expenses indicate.
Commissioner Eglash wondered if there is a matter of degree and of predictabilit y that makes
CIP different, but agreed that there is a conflict in objectives.
Commissioner Melton agreed that, if because of other limitations we have to defer CIP, it
seems appropriate to bank funds for the future when costs start coming along, includi ng that,
as a representative to the City’s Infrastructure Task Force, this is how the General Fund got into
trouble. If in the future Utilities has to do three years of work to get back on track, there should
be money in an infrastructure reserve fund to handle that.
Vice Chair Foster asked if there would be a situation of doing multiple projects at once in the
future, or if this would be a steady deferral out one year. Director Fong stated it was the latter.
Commissioner Waldfogel stated that ratepayers should expect to pay a portion of the life of
infrastructure, even if there are no expenses in one year, that it should not be a ‘jubilee’ of
sorts. Director Fong stated this would be an excellent discussion for the rates policy.
Assistant Director Ratchye asked whether the UAC had any direction for staff as to the
proposals to be provided in March.
Commissioner Eglash said that he is supportive of a flatter rate increase for water, rather than
zero in FY 2014, as this has always been expected. However, he would support zero for
wastewater as the reserves would go above the maximum guideline level.
Commissioner Melton said that he supports the steady, moderate rate increase alternative for
water as he would like to avoid double digit rate increases in water in the future. However, he
said he feels less strongly for wastewater since the dollars are not that large.
Commissioner Eglash encouraged staff to think about the input provided on the CIP funding as
he is very interested in not treating the CIP deferrals as savings, but look at opportunity to bank
the money for catching up with the CIP projects.
Commissioner Melton asked about how much of the fixed costs for the gas distribution and
water costs are collected with fixed charges and how much is collected with volumetric charges.
Ratchye stated that according to the cost of service study, some of the fixed costs are assigned
to be collected with fixed charges, but not all the fixed costs.
Commissioner Waldfogel asked if staff will be coming back with the fiber fund financial
information. Keniston said that there are no plans to do that at this time since rate increases
for the fiber fund are based on the Consumer Price Index.
Director Fong stated that the City Auditor completed an audit of CPAU's reserves and that their
advice was not to store money in reserves, but to only charge customers what is needed in a
particular year.
Vice Chair Foster indicated his support for steady rate increases for water, but said that he did
not have a strong opinion on wastewater.