HomeMy WebLinkAboutStaff Report 2682
City of Palo Alto (ID # 2682)
Finance Committee Staff Report
Report Type: Meeting Date: 4/18/2012
April 18, 2012 Page 1 of 14
(ID # 2682)
Summary Title: Electric Utility Financial Projections
Title: Electric Utility Five Year Financial Projections (FY 2013 - FY 2017)
From: City Manager
Lead Department: Utilities
Recommendation
This report presents the projected costs and revenue requirem ents for the Electric Fund for
Fiscal Year (FY) 2013 through FY 2017. No action is required.
Executive Summary
Staff assessed major cost drivers and expected costs as well as the short-term assessment of
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 FY
2013 and FY 2014. Staff is projecting a need to adjust rates upward by 4%, 6%, and 5% in FY
2015 and the following two years. The rate increase projections are provided for information
purposes only; staff is not requesting any revenue adjustments at this time. The projected
revenue adjustments achieve the goals of ensuring that the balances of the Rate Stabilization
Reserves are adequate and within the Council-approved reserve guideline levels for the five-
year forecast horizon.
Background
The City of Palo Alto Utility (CPAU) serves 29,500 electric customers over an area of
approximately 26 square miles. The City’s maximum demand for electricity in FY 2011 was
180 megawatts (MW) with a total consumption of electricity of 947 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 the City, with the exception of a 4.8 MW
back-up generating facility.
In order to maintain the financial viability of the Electric Fund, staff annually reviews its major
cost drivers, evaluates the risks and 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 including sales
revenue projections, electric supply costs, distribution system operating and Capital
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Improvement Program (CIP) expenses, prudent funding of the Electric Rate Stabilization
Reserves, the Emergency Plant Replacement (EPR) Reserve, and debt service payments. Any
change in one or more of these components can trigg er 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 2012
through FY 20171. For FY 2011 both budgeted and realized actuals based on the City’s
Comprehensive Annual Financial Report (CAFR) are shown. For FY 2012 both budgeted and
projected financial expectations are shown. The projected column for FY 2012 reflects known
variations from budget as of January 2012. The projections for FY 2013 through FY 2017 are
based on estimates prepared for the FY 2013 budget in December 2011.
1 Details of financial projections for the Electric Fund are provided in Attachment A.
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Table 1
Five-Year Financial Projections
($'000)
Adopted Actual Adopted Projected Projected Projected Projected Projected Projected
2011 2011 2012 2012 2013 2014 2015 2016 2017
1 % CHANGE IN TOTAL SYSTEM RETAIL RATE 0%0%0%0%0%0%4%6%5%
2 TOTAL AVERAGE RATE ($/KWH)0.116$ 0.117$ 0.117$ 0.117$ 0.117$ 0.117$ 0.121$ 0.128$ 0.135$
3 COMMODITY COST ($/KWH)0.061$ 0.049$ 0.059$ 0.047$ 0.061$ 0.066$ 0.075$ 0.076$ 0.078$
4 SALES IN GWH 967 947 957 960 1,010 1,013 1,043 1,041 1,041
5 CHANGE IN RETAIL SALES REVENUE ($'000)- - 29 11 (1) - 4,625 7,522 6,635
6
7 Utilities Retail Sales 111,379 109,993 110,615 110,996 116,827 117,120 125,029 132,249 138,852
8 Surplus Energy Sales 2,759 3,680 1,179 4,586 1,627 1,887 1,428 2,888 3,109
9 Carbon Offset Revenues - - 2,597 5,285 5,396 5,534 5,833
10 Service Connection Charges 800 1,329 850 850 900 925 950 1,000 1,050
11 CVP O&M Loan Credit 7,000 4,763 5,756 6,613 7,000 7,000 7,000 7,000 7,000
12 Other Revenues plus Transfers In 2,342 4,420 2,796 2,796 2,696 3,234 4,991 5,018 4,398
13 Interest plus Gain or Loss on Investment 4,299 3,203 4,012 4,012 4,144 4,039 3,774 3,379 3,199
14 Total Sources of Funds 128,579 127,388 125,208 129,853 135,791 139,489 148,567 157,067 163,441
15
16 Purchases to Serve Load 64,031 51,080 62,035 49,420 63,442 69,276 78,711 79,198 81,147
17 Surplus Energy Cost 1,967 4,879 975 5,424 1,577 1,641 1,148 2,100 2,131
18 Joint Venture Debt Service 8,849 7,243 8,863 8,863 9,383 9,099 9,103 9,114 8,928
19 CVP O&M Loan Advance 7,000 4,763 5,756 6,613 7,000 7,000 7,000 7,000 7,000
20 Supply Operations 5,700 3,477 6,170 6,170 6,752 7,310 8,163 8,588 8,937
21 Distribution Operations 19,268 15,443 24,039 24,039 24,620 25,112 25,615 26,127 26,649
22 Rent 3,498 3,498 3,598 3,598 3,670 3,743 3,818 3,895 3,972
23 General Fund Transfers 11,195 11,195 11,587 11,587 11,638 11,891 12,254 12,645 13,040
24 Other Transfers Out 866 995 299 304 304 304 304 304 304
25 Capital Improvement Programs 9,285 13,071 8,685 9,510 10,910 12,955 15,605 14,115 12,020
26 Total Uses of Funds 131,659 115,644 132,007 125,528 139,295 148,330 161,720 163,085 164,129
27
28 Into/ (Out of) Reserves (3,080) 11,743 (6,799) 4,325 (3,504) (8,841) (13,153) (6,018) (688)
FINANCIAL PROJECTIONS (Jan 2012)
City of Palo Alto
Electric Utility
Fiscal Year
Total expenses (Row 26 in Table 1) totaled $115.6 million in FY 2011, or $16.0 million lower than
budgeted. Total revenues (Row 14 in Table 1) were $127.4 million, or $1.2 million lower than
budgeted for FY 2011.
FY 2011 Expenses and Revenues
For FY 2011, the biggest variation in expenses, $13.0 million, was due to lower than expected
purchase costs to serve load. Lower electric consumption accounted for a portion of the cost
savings, but consumption was only 2.0% below budget . The lower costs were primarily related
to significantly higher hydroelectric generation than was budgeted. Other factors include the
decreased costs for renewable power due to the removal of the Butte County renewable power
project and a later than anticipated start date for the Johnson Canyon and Western Geo
renewable power projects and a refund from the Northern California Power Agency (NCPA)
related to FY 2010 settlements. Other supply related expenses include surplus energy costs ,
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which were higher than budgeted due to the higher than budgeted surplus energy availability.
Additionally, $1.6 million savings were realized in joint venture2 debt service payments due to
the refinancing of a portion of the Calaveras Hydroelectric Project debt at a lower interest rate.
The CVP O&M loan advance3 was reduced by $2.2 million due to changes in project plans . The
Electric Fund also realized $2.2 million savings in supply operations costs mainly due to lower
than anticipated solar program participation and other alternative energy program related
costs. Overall distribution expenses remained at budgeted levels.
As a result of these variations from budgeted amounts, the Electric Fund returned $11.7 million
to its reserves, instead of the $3.1 million budgeted drawdown in FY 2011.
FY 2012 Expenses and Revenues
The projections for FY 2012 follow a similar pattern. Total expenses are expected to be $6.5
million lower than budgeted. This is mainly due to $8.2 million lower than budgeted supply
costs (Rows 16, 17 and 18 in Table 1). The lower than budgeted supply costs are due to greater
availability of hydro resources, lower market prices, reduced renewable energy purchase costs
due to project delays and the replacement of renewable resources with purchases at l ower
market prices. Increased hydro generation projections are expected to result in increased
surplus energy sales as well as increased surplus energy costs. The Central Valley Project (CVP)
O&M loan advance was increased by $0.9 million due to changes in project plans. The capital
improvement budget was increased by $0.8 million for a 60kV reconductoring and pole
installation project. The operating and capital improvement program related expenses are
expected to be within budget, and variations to budget, if any, will not be available until fiscal
year-end close of the financial books.
Expected sales revenues for FY 2012 are almost unchanged from budgeted levels. With the
expected increases in surplus energy sales and CVP O&M credit, total revenues in FY 2012 are
expected to be $4.6 million higher than budgeted.
As a result of the changes in expenses and revenues, the Electric Fund is expected to return
$4.3 million to its reserves, instead of the budgeted drawdown of $6.8 million in FY 2012.
FY 2013-FY 2017 Cost Drivers
Electric Fund expenses are projected to be $13.8 million higher in FY 2013 than in FY 2012,
mainly due to expected increases in the electric purchase costs ($14.0 million) due to lower
hydro availability, higher market price expectations, higher transmission cost expectations, and
additional renewable projects that are coming on line. This is partially offset by the reduction
2 Joint Venture refers to the Calaveras hydroelectric resource.
3 CVP O&M Loan Advance (Row 18, Table 1) and CVP O&M Loan Credit (Row 10, Table 1) are planned payments
and equal amounts of credits associated with the financing of operations and maintenance of eleven federal dams,
power plants, and transmission facilities as part of the Western Area Power Administration (Central Valley Project,
or CVP) system. The loan advance and loan credits are a financing mechanism to facilitate the maintenance and
upgrades at these federal facilities. The actual cost of these projects is included in the charges associated with the
Western Power.
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in surplus energy costs ($3.8 million) due to lower surplus energy projected for FY 2013. In FY
2013, CIP costs are expected to increase by $1.4 million due to electric system upgrade
projects. Distribution operations costs are expected to increase by $0.6 million and supply
operations costs are expected to increase by $0.5 million mainly due to increased fundin g for
energy efficiency (EE) and alternative resource programs.
For the longer term horizon, Electric Fund costs are expected to increase by $24.8 million from
$139.3 in FY 2013 to $164.1 million in FY 2017, an average annual increase of 5.5 percent. T his
is mainly driven by the expected increases in electric purchase costs ($17.7 million), increases in
funding of alternative resource programs ($1.7 million) included in supply operations budget,
and investments in planned CIP expenditures ($1.1 million).
The increase in electric purchase costs of $17.7 million during the forecast horizon is largely
driven by the increased California Independent System Operator (CAISO) costs mainly
associated with high voltage and low voltage transmission access charges (HV/LV TAC) ($5.9
million); more renewable resources in the portfolio in order to meet the Renewable Portfolio
Standards (RPS) ($4.4 million); expected increases in market prices for electricity ($2.2 million);
resource adequacy requirements for local capacity ($1.1 million); and a 3% increase in demand
over the forecast horizon.
Offsetting these costs are increases in revenues from the surplus energy sales (increasing from
$1.6 million in FY 2013 to $3.1 in FY 2017), and from sales of carbon allowances re sulting from
the State’s cap-and-trade program expected to start in FY 2013. It is expected that the cap -and-
trade program will provide revenues of $2.6 million in FY 2013, increasing to $5.3 million in FY
2014 and reaching $5.8 million in FY 2017. Since this is a new program with significant
uncertainty around the terms, rules, start date, and compliance requirements, including how
the revenues may be allocated or spent, its impact on the overall revenue requirements is
highly uncertain at this time.
Alternative resource program funding of $2.8 million in the supply operations budget in FY 2013
includes $1.1 million of incentives for solar rooftops, $1.3 million of additional funding for EE
programs, and $0.4 million for other programs such as the feed -in tariff program development,
and pilot program development for demand response and electric vehicle time -of-use rate
programs. EE programs also utilize most of the $3.8 million of funding under the Public Benefit
programs in the distribution operations budget in FY 2013. Funding of alternative resource
programs is projected to increase by $1.7 million during the forecast horizon from $2.8 million
in FY 2013 to $4.6 million in FY 2017.
CIP project funding accounts for 7.8% of the operating budget in FY 2013 and is expected to
increase by $1.1 million from $10.9 million in FY 2013 to $12.0 million in FY 2017. Table 2
shows the planned CIP expenditures by project for FY 2013 – FY 2017.
Major ongoing CIP projects in FY 2013 include electric system improve ments of $2.3 million and
customer connections of $2.1 million. Customer connection expenses are partially offset by
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customer connection service fee revenues of $0.9 million. Special CIP projects include $1.7
million for a project to upsize the 60 kV system to eliminate a bottleneck in FY 2013 (EL-11015),
$1.2 million for both FY 2013 and 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. Another major CIP expenditure is to install a new substation
lineup for the growing load in Park Research Stanford (EL -14003).
Table 2
Capital Improvement Program Plan (FY 2013 – FY 2017)
Prj #Description Expense Revenue Expense Revenue Expense Revenue Expense Revenue Expense Revenue
EL-02010 SCADA System Upgrade 50,000 - 55,000 - 60,000 - 65,000 - 270,000 -
EL-04012 Utility Site Securit 200,000 - 225,000 - 250,000 - - - - -
EL-05000 El Camino Undergroun 300,000 - - - - - - - - -
EL-06001 230 kV Electric Inte 100,000 - 100,000 - - - - - - -
EL-06003 Utility Control Cent - - 75,000 - - - - - 400,000 -
EL-08001 UG District 42 Embar - - 150,000 - 2,000,000 (750,000) 500,000 - - -
EL-09004 W.Charleston/Wilkie-550,000 - - - - - - - - -
EL-10009 Street Light System 1,200,000 - 1,200,000 - - - - - - -
EL-11000 Seale/Waverley 4/12k - - - - 75,000 - 325,000 - - -
EL-11002 St. Francis Oregon 4 - - - - 100,000 - 350,000 - - -
EL-11003 Rebuild UG Dist 15 400,000 - 270,000 - - - - - - -
EL-11009 UG District 43 Alma/- - - - 150,000 - 2,000,000 (700,000) 500,000 -
EL-11010 UG District 47 - Mid 200,000 (600,000) - - - - - - - -
EL-11014 Smart Grid Technolog - - 1,000,000 (666,667) 3,000,000 (2,000,000) 3,000,000 (2,000,000) 3,000,000 (2,000,000)
EL-11015 Reconductor 60kV OH 1,750,000 - - - - - - - - -
EL-12000 Rebuild UG Dist 12 80,000 - 700,000 - 300,000 - - - - -
EL-12001 UG District 46 - Cha - - 800,000 (400,000) 150,000 - - - - -
EL-12002 Hanover 22 - Transfo 200,000 - - - - - - - - -
EL-13000 Edgewood/Wildwood 4/- - - - - - 50,000 - 400,000 -
EL-13002 Relocate QR/HO 60kV - - - - - - 100,000 - 750,000 -
EL-13003 Rebuild UG Dist 16 - - - - - - 300,000 - - -
EL-14000 Coleridge/Cowper/Ten - - - - 120,000 - 400,000 - - -
EL-14002 Rebuild UG Dist 20 - - - - 500,000 - 500,000 - - -
EL-89028 Electric Customer Co 2,100,000 (900,000) 2,200,000 (925,000) 2,300,000 (950,000) 2,400,000 (1,000,000) 2,500,000 (1,050,000)
EL-89031 Communications Syste 125,000 - 130,000 - 135,000 - 145,000 - 155,000 -
EL-89038 Substation Protectio 260,000 - 270,000 - 280,000 - 290,000 - 300,000 -
EL-89044 Substation Facility 170,000 - 180,000 - 185,000 - 190,000 - 195,000 -
EL-98003 Electric System Imp 2,300,000 (150,000) 2,400,000 (160,000) 2,450,000 (170,000) 2,500,000 (180,000) 2,550,000 (190,000)
EL-12003 HO Sub Rebuild 250,000 500,000 250,000
EL-13005 Repl CO20/21 Transformers 100,000 1,500,000
EL-14003 Hanover 24 / 25 Lineup 100,000 3,000,000 1,000,000 1,000,000
EL-13004 HW / HV 12kV Ties 75,000 350,000 -
EL-13007 UG Dist System Security 300,000 300,000 300,000
EL-13006 Sand Hill / Quarry 12kV Tie 50,000 300,000
EL-13008 Upgrade Est. Software 150,000 150,000
Total $10,910,000 -$1,650,000 $12,955,000 -$2,151,667 $15,605,000 -$3,870,000 $14,115,000 -$3,880,000 $12,020,000 -$3,240,000
FY 2013 FY 2014 FY 2015 FY 2016 FY 2017
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Other increased funding requirements in the Electric Fund include an additional $1.4 million for
the General Fund Transfers, which increase from $11.6 million in FY 2013 to $13.0 million in FY
2017 based on the expected increases in value of utility assets.4
Additionally, staff projects a long-term net cost increase of 2% per year in other operating
expenditures such as supply and distribution operations, maintenance and administration costs,
allocated cost plan and administration charges, rent, and other transfers. The final operating
and CIP budget requests will be presented to the Finance Committee in May 2011.
FY 2013-FY 2017 Revenue Projections
Retail sales constitute the largest source of revenue for the Electric Fund. Electric demand
projections are discussed in detail in the following section. Interest and gains on investments in
future years are calculated assuming a 3% return on investment. Other revenues include grant
funding of $0.7 million to $2.0 million for smart grid technology. Surplus energy sales are
expected to increase by $1.5 million due to increased market prices and excess resources
during certain times of the year throughout the forecast horizon. Carbon offset reven ues are
projected to increase by $3.2 million based on assumptions about carbon allowance allocations
and their value. The rules on allocations of carbon offset revenues are not yet completely
known at this time and, therefore, this source of revenue is n ot guaranteed. PaloAltoGreen
Program revenue is expected to grow by 5% per year throughout the forecast horizon.
Electricity Demand
Electric demand has generally been very stable in the City. 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, demand increased at an average of 1.0% per year during the following six
years until FY 2009. Demand has been decreasing since FY 2009 again due to the recent
economic slowdown, dropping by a total of 6% over the last two years. The projection for the
forecast period is a reversal of this trend, mainly due to expected changes in large customer
demands. In FY 2012 demand is expected to be 1.3% higher than the demand in FY 2011. In FY
2013, demand is expected to increase by another 5.2% in large part as a result of a large
customer site expansion. Demand is expected to grow at an average rate of 1.1% per year from
FY 2012 to FY 2020.
The projections of electricity demand 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 8.9% or 97 GWh by FY 2020. This
represents a peak demand reduction of 7 MW, or 4%. Similarly, it is expected that by 2020,
local PV systems will be replacing 17 GWh of electricity purchases, reducing Palo Alto’s peak
4 General Fund Transfers are calculated using the Council approved (CMR:260:09) Utility Enterprise Methodology
(UEM), which depend primarily on the asset value of the Electric Fund.
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demand by 9 MW by the end of FY 2020. On the other hand, the City expects that by 2020
roughly 10,700 residential and commercial customers will be charging their EVs in the City,
increasing demand by roughly 22 GWh, and adding 500 kW to the City’s peak demand in 2020.
The combined effects of EVs, PV systems, and EE programs will account for a net decrease of
92 GWh of electricity demand and 15 MW of peak demand by FY 2020. In the short term, a
sizable load increase due to one customer’s plans to move some of its operations to Palo Alto is
expected to increase electricity demand by 5.0%. 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.
Chart 1 presents the City’s historical electric consumption levels from FY 2001 through FY 2011
and projections for FY 2012 through FY 2020.
Chart 1
Palo Alto Electricity Consumption
600
700
800
900
1000
1100
1200
1300
FY2001 FY2003 FY2005 FY2007 FY2009 FY2011 FY2013 FY2015 FY2017 FY2019
GW
h
Forecast
w/o EE programs
Actual
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 rate stabilization reserves, the
Electric Fund does not require any revenue adjustments until FY 2015. It is expected that
revenue adjustments of 4%, 6% and 5% for the last three years will be necessary in order to
maintain adequate reserves for the forecast horizon. The Electric Fund’s projected costs and
revenues from FY 2011 through FY 2017 are depicted in Chart 2 below.
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Chart 2
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
2011 2012 2013 2014 2015 2016 2017
Electric Fund Revenue and Cost Projections
($million)
Purchases
CIP
Operations
CVP O&M
Debt Service
GF Transfers
Revenue
0%0%
0%4%6%5%
0%
Reserves and Risk Assessment
Guidelines for the Electric Supply Rate Stabilization Reserve (E -SRSR) and Electric Distribution
Rate Stabilization Reserve (E-DRSR) are established by the City Council. The current minimum
and maximum guideline levels for the E-DRSR are 15% and 30% of sales revenues, respectively.
The guidelines for minimum and maximum reserve levels for the E-SRSR are 50% and 100% of
supply purchase costs, respectively.
These minimum and maximum guidelines represent assessments of reserve level requirements
based on long-term expected changes in commodity costs, hydro risk and credit risk. In
addition to the long-term reserve guideline levels, the guidelines require an annual assessment
of short-term uncertainties and risks for each of the supply and distribution business units. The
risks considered in the short-term risk assessment include:
1. “Load net revenue” risk, 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, 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, the cost of purchasing more electricity 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, a function of the un-hedged portion of the supply
portfolio for energy and capacity and market price uncertainty. As of December 2011, 20%
and 30% of the electric supply portfolio for FY 2012 and FY 2013 was un -hedged,
respectively; and
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5. Other risks, including transmission related cost uncertainties, plant outage probabilities,
Western hydroelectric resource cost uncertainties, regulatory and legal risks, and supplier
credit default risks for both renewable and wholesale power counterparties.
Table 3 summarizes short-term cost uncertainties evaluated for the next two years.
Table 3
Electric Supply Cost Risks
Electric Supply Cost Uncertainties Estimates of Adverse Outcomes
(M$)
FY 2013 FY 2014
1. Load Net Revenue 0.4 1.3
2. Hydro Production: Western and Calaveras 9.6 12.6
3. Renewable Production: Landfill and Wind 1.0 0.8
4. Market Price 1.8 4.0
5. Transmission/CAISO 2.2 2.4
6. Plant Outage 1.0 1.0
7. Western Cost 2.8 2.9
8. Regulatory & Legal 2.6 5.3
9. Supplier Default 2.0 2.0
Electric Supply Fund Risks $23.4 $32.3
The sum of these adverse outcomes totals $23.4 million in FY 2013 and $32.3 million in FY 2014.
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 distribution 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 can not be considered as additional to the risks in the distribution RSR.
For the distribution RSR, 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 $7.0 million in FY 2013 and $7.3 million in FY 2014.
Rate Stabilization Reserve Adequacy
Table 4 summarizes electric supply and distribution lo ng-term reserve level guidelines, short-
term assessment of risks, and estimated end-of-year reserve balances for the E-SRSR and the E-
DRSR for the current and the next two fiscal years.
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Table 4
Electric Rate Stabilization Reserve Guideline Levels and Short Term Risk Assessment ($M)
The estimated end-of-year balance for the E-SRSR is above the short-term risk assessment
levels as well as the long-term maximum reserve guideline levels in FY 2012 and FY 2013. With
no revenue increase projected, the reserve level in FY 2014 falls withi n the long-term minimum
and maximum reserve guideline levels but 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.
Charts 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.
Electric Supply Rate Stabilization Reserve FY
2012
FY
2013
FY
2014
Estimated End of Year Balance 67.6 64.9 59.1
Risk Assessment 18.1 23.4 32.3
Minimum Level Guidelines 31.0 31.7 34.6
Maximum Level Guidelines 62.0 63.4 69.3
Electric Distribution Rate Stabilization
Reserve
Estimated End of Year Balance 11.6 11.3 8.8
Risk Assessment 6.6 7.0 7.3
Minimum Level Guidelines 6.4 6.7 6.8
Maximum Level Guidelines 12.8 13.5 13.5
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Chart 3
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
2011 2012 2013 2014 2015 2016 2017
Electric Fund Supply Rate Stabilization Reserve Levels
($Million)
LT Min & Max
ST Risk Assessment
FY Ending SRSR
Chart 4
$0
$2
$4
$6
$8
$10
$12
$14
$16
$18
2011 2012 2013 2014 2015 2016 2017
Electric Fund Distribution Rate Stabilization Reserve Levels
($Million)
LT Min & Max
ST Risk Assessment
FY Ending RSR
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Rate Comparison with Neighboring Cities
The City currently has an Electric Fund cost advantage compared to neighboring cities served by
Pacific Gas and Electric Company (PG&E). However, Santa Clara, served by its municipally-
owned Silicon Valley Power, has rates that result in a lower bill for a typical residential customer.
Table 5 below presents the average monthly bill for a residential customer in Palo Alto and in
four neighboring cities using current local rates. Comparisons 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).
Table 5
Electric Fund Residential Benchmark Comparison
Current FY 2012 (as of January 1, 2012)
Palo
Alto
Mountain
View
Redwood
City
Menlo
Park
Santa
Clara
Average
Benchmark
City
Monthly Bill ($) 42.76 53.74 53.74 53.74 41.81 50.76
Difference from CPAU 25.7% 25.7% 25.7% -2.2% 18.7%
Commission Review and Recommendations
On March 7, 2012 the Utilities Advisory Commission reviewed the Electric Fund’s Five-Year
Financial Forecast. Commissioners had comments about the increasing transmission related
costs and whether those costs can be cont rolled. Staff responded that the potential new
tranmission line project that is being evaluated could help to mitigate those cost increases.
There was much discussion about the significant increases in the CIP costs that are projected
over the forecast horizon. Commissioners questioned why certain projects are included in th e
plan, especially those related to undergrounding and smart grid, and advised that inclusion of
such projects requires careful communication to the public since the projected rate increases
may be partly driven by these cost increases. Commissioners sugg ested that the projects
related to normal updating and replacement of distribution system infrastructure may need a
different level of discussion from other types of projects. Commissioners also questioned why
the potential new transmission project with SLAC was not included in the CIP plan.
The draft notes from the UAC’s March 7, 2012 meeting are provided as Attachment B.
Attachments:
-: Attachment A: Electric Utility Financial Projections (FY 2013 - FY 2017) (PDF)
-: Attachment B: Excerpted Minutes of the March 7 UAC Meeting (PDF)
5
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April 18, 2012 Page 14 of 14
(ID # 2682)
Prepared By: Ipek Connolly, Sr. Resource Planner
Department Head: Valerie Fong, Director
City Manager Approval: ____________________________________
James Keene, City Manager
5
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Five Year Financial Projections
$ (000's)
Adopted Actual Adopted Projected Projected Projected Projected Projected Projected
2011 2011 2012 2012 2013 2014 2015 2016 2017
1 % CHANGE IN RETAIL RATE 0% 0% 0% 0% 0% 0% 4% 6% 5%
2 TOTAL AVERAGE RATE (MILLS/KWh)116 117 117 117 117 117 121 128 135
3 SALES UNITS (GWh)967 947 957 960 1,010 1,013 1,043 1,041 1,041
4 ELECTRIC FUND REVENUE
5 BASE SALES REVENUES:
6 COMMODITY SALES 66,273 65,493 65,911 66,137 69,580 69,753 71,806 74,571 80,644
7 DISTRIBUTION SALES 42,367 42,374 42,607 42,752 44,978 45,090 46,417 47,973 49,147
8 PUBLIC BENEFIT REVENUE 3,095 3,047 3,065 3,092 3,265 3,273 3,369 3,492 3,699
9 SUB-TOTAL BASE SALES REVENUE 111,735 110,915 111,583 111,981 117,824 118,116 121,592 126,036 133,489
10 RATE ADJUSTMENT:
11 COMMODITY 0 0 0 0 0 0 2,872 6,115 6,451
12 DISTRIBUTION 0 0 0 0 0 0 1,625 1,199 0
13 PUBLIC BENEFIT 0 0 29 11 (1)0 128 208 184
14 TOTAL RATE ADJUSTMENT 0 0 29 11 (1)0 4,625 7,523 6,635
15 PRORATION IMPACT 0 0 (1) (0)0 (0) (193) (313) (276)
16 TOTAL ADJUSTED SALES REVENUE 111,735 110,915 111,611 111,992 117,823 118,116 126,025 133,245 139,848
17 DISCOUNTS/UNCOLLECTABLES (356) (922) (996) (996) (996) (996) (996) (996) (996)
18 INTEREST 4,299 3,203 4,012 4,012 4,144 4,039 3,774 3,379 3,199
19 SURPLUS ENERGY REVENUE 2,759 3,680 1,179 4,586 1,627 1,887 1,428 2,888 3,109
20 CARBON OFFSET REVENUES 0 2,597 5,285 5,396 5,534 5,833
21 PA-GREEN SALES REVENUE 1,080 1,093 1,220 1,220 1,215 1,276 1,340 1,407 1,477
22 SERVICE CONNECTION CHARGES 800 1,329 850 850 900 925 950 1,000 1,050
23 CVP O&M FUNDING 7,000 4,763 5,756 6,613 7,000 7,000 7,000 7,000 7,000
24 OTHER REVENUE 1,262 2,122 1,576 1,576 1,481 1,958 3,651 3,611 2,921
25 FROM RESERVES:
26 SUPPLY RSR 2,881 0 1,319 0 2,676 5,748 11,200 5,876 1,212
27 DISTRIBUTION RSR 42 244 0 0 306 2,504 1,506 0 0
28 CALAVERAS 4,112 4,307 5,238 5,238 0 0 0 0 0
29 P.B. RESERVE 0 611 619 553 521 589 447 326 223
30 ENCUMBRANCES / REAPPROPRIATIONS 2,715
31 TOTAL FROM RESERVES 7,035 5,162 7,177 5,791 3,504 8,841 13,153 6,202 1,435
32 TOTAL FINANCIAL RESOURCES 135,614 131,346 132,384 138,359 139,295 148,331 161,720 163,270 164,876
33 OPERATING EXPENSES
34 SUPPLY
35 PURCHASES 64,031 51,080 62,035 49,420 63,442 69,276 78,711 79,198 81,147
36 SURPLUS ENERGY COST 1,967 4,879 975 5,424 1,577 1,641 1,148 2,100 2,131
37 PA-GREEN POWER PURCHASES 1,080 525 1,080 1,080 972 1,021 1,072 1,125 1,181
38 CALAVERAS DEBT SERVICE 8,849 7,243 8,863 8,863 9,383 9,099 9,103 9,114 8,928
39 CVP O&M FUNDING 7,000 4,763 5,756 6,613 7,000 7,000 7,000 7,000 7,000
40 SUPPLY FUNDED ALTERNATIVE RESOURC 2,185 973 2,605 2,605 2,845 3,296 4,038 4,348 4,579
41 RESOURCE MANAGEMENT, OTHER ADMIN 1,915 1,408 1,929 1,929 2,368 2,415 2,463 2,513 2,563
42 ALLOCATED CHARGES:
City of Palo Alto
Electric Utility
Fiscal Year
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U
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42 ALLOCATED CHARGES:
43 COST PLAN CHARGES & OTHER 315 335 309 309 315 321 328 334 341
44 UTILITIES ADMINISTRATION 206 236 247 247 252 257 262 268 273
45 SUB-TOTAL SUPPLY 87,547 71,442 83,799 76,490 88,154 94,325 104,124 106,000 108,144
46 DISTRIBUTION
47 OPERATIONS & MAINT, OTHER ADMIN 12,257 11,571 13,042 13,042 13,403 13,671 13,944 14,223 14,508
48 PUBLIC BENEFITS PROGRAMS 3,095 3,491 3,712 3,712 3,786 3,862 3,939 4,018 4,098
49 CUSTOMER DESIGN & CONNECTION CIP 2,000 2,000 2,000 2,000 2,100 2,200 2,300 2,400 2,500
50 SYSTEM IMPROVEMENT (CIP)7,170 10,956 5,765 6,590 7,485 9,425 13,170 11,570 9,365
51 STREET LIGHT, TRAFFIC SIGNAL O&M 816 583 842 842 859 876 894 912 930
52 STREET LIGHT, TRAFFIC SIGNAL CIP 800 806 800 800 1,200 1,200 0 0 0
53 COMMUNICATIONS O&M & CIP 440 336 452 452 464 476 488 505 522
54 ALLOCATED CHARGES:
55 COST PLAN CHARGES & OTHER 2,772 (460)2,903 2,903 2,961 3,020 3,080 3,142 3,205
56 UTILITIES ADMINISTRATION 3,049 2,697 3,208 3,208 3,272 3,337 3,404 3,472 3,542
57 SUB-TOTAL DISTRIBUTION 32,398 31,979 32,724 33,549 35,530 38,067 41,220 40,242 38,669
58 TRANSFERS:
59 GENERAL FUND TRANSFER 11,195 11,195 11,587 11,587 11,638 11,891 12,254 12,645 13,040
60 RENT 3,498 3,498 3,598 3,598 3,670 3,743 3,818 3,895 3,972
61 OTHER TRANSFERS 866 995 299 304 304 304 304 304 304
62 TOTAL OPERATING EXPENSES 135,504 119,110 132,007 125,528 139,295 148,330 161,720 163,085 164,129
63 RESERVE FUNDING:
64 PLANT REPLACEMENT 0 0 0 0 0 0 0 0 0
65 SUPPLY RSR 0 12,236 0 10,474 0 0 0 0 0
66 DISTRIBUTION RSR 0 0 377 2,357 0 0 0 185 747
67 P.B. RESERVE 0 0 0 0 0 0 0 0 0
68 CALAVERAS INTEREST 0 0 0 0 0 0 0 0 0
69 TOTAL RESERVE FUNDING 0 12,236 377 12,831 0 0 0 185 747
70 TOTAL REVENUE REQUIREMENT 135,504 131,346 132,384 138,359 139,295 148,330 161,720 163,270 164,876
71 RESERVES BALANCES
72 PLANT REPLACEMENT 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
73 DISTRIBUTION RSR 9,443 9,241 9,820 11,598 11,292 8,788 7,282 7,466 8,213
74 SUPPLY RSR 41,974 57,090 40,654 67,565 64,888 59,140 47,940 42,064 40,852
75 CALAVERAS 55,753 55,558 50,515 50,320 50,320 50,320 50,320 50,320 50,320
76 P.B. RESERVE BALANCE 3,750 3,139 3,130 2,585 2,064 1,475 1,028 702 479
77 TOTAL RESERVES BALANCE 111,920 126,028 105,121 133,068 129,564 120,723 107,570 101,553 100,864
78
79 Short Term Risk Assessment Value -Supply RSR 26,700 26,700 18,100 18,100 23,400 32,300 60,861
80 Short Term Risk Assessment Value- Distribution RS 6,934 6,934 6,600 6,600 7,085 7,295
81
82 Long Term Rate Stabilization Guidelines
83 Supply RSR Minimum 32,016 32,016 31,018 31,018 31,721 34,638 39,355 39,599 40,574
84 Supply RSR Maximum 64,031 64,031 62,035 62,035 63,442 69,276 78,711 79,198 81,147
85
86 Distribution RSR Minimum 6,355 6,355 6,391 6,391 6,747 6,764 7,206 7,376 7,372
87 Distribution RSR Maximum 12,711 12,711 12,782 12,782 13,494 13,527 14,413 14,752 14,744
88
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2011 2011 2012 2012 2013 2014 2015 2016 2017ELECTRIC
2/22/201210:52 AM
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Excerpted Minutes of the March 7, 2012 UAC Meeting
NEW BUSINESS
ITEM 3: DISCUSSION: Electric Fund Financial Projections (FY 2013 – FY 2017)
Senior Resource Planner Ipek Connolly provided a presentation summarizing the written report.
She noted that costs are increasing over the five‐year financial forecast period, but that no
revenue adjustment is projected to be required until FY 2015. Connolly stated that the primary
driver for the revenue requirement increases over the forecast period is the cost of energy
supplies. The supply costs are increasing mainly due to transmission and the cost of renewable
energy as those projects come on line to meet the goals. Over the forecast horizon, volumes of
market purchases are falling as renewable supplies increase. Regarding the CIP program, there
are some trends worth noting such as system improvements that have relatively level annual
expenditures, two years of a street‐lighting project in FY 2013 and FY 2014, a project related to
a substation in Stanford Research Park starting in FY 2015, and the assumed start of the a smart
grid technology program starting in FY 2014 and increasing to $3 million per year in FY 2015 to
FY 2017. Connolly noted that the smart grid project is still being evaluated and staff expects
that two‐thirds of the project costs will be funded from grants. The smart grid plans are
indicative only and are not firm decisions that have been made at this time. Over the financial
forecast horizon, the supply and distribution rate stabilization reserves are planned to be
between the minimum and maximum guideline levels given the projected revenue increases.
Connolly concluded with advising that the Finance Committee will review the financial forecasts
in April and the UAC and Finance Committee will review the electric budget in May.
Commissioner Waldfogel asked whether we can control the transmission related costs that are
projected to increase so dramatically. He asked if the high voltage interconnection being
contemplated have any impact on those costs. Assistant Director Ratchye said that the
Transmission Access Charges are a large concern and that it is hoped that the potential new
transmission line would be a cost‐effective way to reduce those charges.
Commissioner Waldfogel asked if it was still Council policy that renewable energy supplies can
add only a half‐cent per kilowatt‐hour to the retail rate. Ratchye confirmed that this was
Council policy. Commissioner Waldfogel asked if we expect to be able to achieve the
renewable goals with that rate impact limit. Ratchye stated that we do plan to achieve the goal
within the rate impact constraint.
Commissioner Eglash commented that the forecasts show a significant increase in CIP costs
over the forecast horizon. Commissioner Eglash noted that we haven't had a systematic
discussion of the CIP and these costs are growing significantly and stated that there has not
been a systematic discussion of whether the UAC supports these large increases. He
highlighted items that dramatically impact the future costs – first, the smart grid expenditures
are shown, but the last time the UAC saw this, the decision was to wait until the technology
matured or savings could be shown. He also pointed out that no decision has been made on
the future for undergrounding the electric distribution lines and the assumption in this plan is
that the current program continues. Since the economics of undergrounding has changed, we
shouldn’t necessarily assume that the program will continue as in the past. Commissioner
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Eglash noted that the inclusion of these projects could be misleading to people. He advised
that it sends a message to Council and the community that somehow decisions have been
made. He noted that the chart shows that CIP costs are increasing from $9.5 million in FY 2012
to $15.6 million in FY 2015 and we need a communication. Smart grid plans as well as
undergrounding deserve more discussion. Ratchye advised that the UAC will have a chance to
review the five‐year CIP plans and discuss the projects when it considers the CIP budget at its
May meeting. Ratchye noted that staff may want to consider highlighting which projects have
not had policy direction. Commissioner Eglash advised that staff should consider the messaging
involved with the presentation of such a major increase in CIP expenditures and noted that over
the years, CPAU has focused on ensuring that the distribution infrastructure was being updated
and replaced prudently. However, something like smart grid is something else altogether as it
is adding new technology rather than maintaining existing infrastructure.
Commissioner Keller asked what projects are included in the CIP projections. She asked if all
the things on the list are committed to and she would like to know which ones are “nice to
have”, but haven't been decided at this point. Commissioner Keller added that it is helpful to
have a list of committed projects vs. other projects in the “nice to have” category.
Commissioner Eglash noted that this item is a discussion item and asked if the item went to the
Finance Committee. Ratchye replied that the item would go to the Finance Committee as a
discussion item and that the UAC’s discussion summary and minutes would be part of the
Finance Committee’s report.
Council Member Shepherd added that the Finance Committee has included undergrounding on
the short list of discussion items, along with fiber optics, for the year and noted that Council has
heard from the community that this is an important issue. The subject was raised recently as to
why the project was not included in the Blue Ribbon Infrastructure Task Force work.
Commissioner Eglash noted that the UAC has reviewed the undergrounding program and had
in‐depth discussions in the past and would be willing again to review the situation and provide
advice to the Finance Committee and Council.
Commissioner Waldfogel asked if the CIP program includes any software updates such as to the
SAP billing system. Connolly replied that costs related to the SAP system are funded separately
from the Electric Fund’s CIP. Commissioner Waldfogel asked if we are allocated a piece of this
project and said, that if it was a large expense, it should be discussed separately. Commissioner
Keller asked if project EL‐13008 in Table 2 (upgrade est. software) had to do with the SAP billing
system. Ratchye replied that it was not related to that system. Connolly noted that the
expenditures for the SAP billing system are shown under other transfers and allocated charges
and that she does not have the cost break‐out for what part of that is for SAP system upgrades.
Commissioner Keller asked whether the transmission project with SLAC is included in the CIP
plan. Ratchye said that the potential transmission line project is not included in the CIP
presented.
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