HomeMy WebLinkAboutStaff Report 1542City of Palo Alto (ID # 1542)
Finance Committee Staff Report
Report Type:Meeting Date: 4/19/2011
April 19, 2011 Page 1 of 12
(ID # 1542)
Summary Title: Electric Utility Financial Projections
Title: Recommendation of Approval of Transfer of $5.238 Million from the
Calaveras Reserve into the Electric Utility Operating Budget for Fiscal Year 2012
and Electric Utility Long Term Financial Projections and Revenue Requirements
From:City Manager
Lead Department: Utilities
Recommendation
Staff requests that the Finance Committee recommend that the City Council approve a total
transfer of $5.238 million from the Calaveras Reserve into the Electric Utility Operating Budget
for Fiscal Year (FY) 2012, which is the minimum transfer amount required by Calaveras Reserve
Guidelines. The guidelines establish the minimum in order to return to the ratepayers the pre-
collected funds the cover the over market costs of the Calaveras asset.
Executive Summary
This report discusses the projected costs and revenue requirements for the Electric Utility for FY
2012 through FY 2016.
Staff assessed major cost drivers and expected costs, the short-term assessment of risks, reserve
guidelines, and determined the revenue requirements for the Electric Utility for the next five
years. The financial forecast shows that after the proposed minimum transfer amount
established by the Calaveras Reserve Guidelines, revenues are forecast to be adequate for the
Electric Utility for FY 2012 and FY 2013. Staff is projecting five percent annual rate increases for
FY 2014 through FY 2016. The rate increase projections for FY 2014 through FY 2016 are
provided for information purposes only; staff is not requesting any rate changes at this time.
The projected rate adjustments achieve the goals of ensuring that the balances of the Electric
Supply and Distribution Rate Stabilization Reserves (E-SRSR and E-DRSR, respectively) are
adequate and within the Council-approved reserve guideline levels for the long-term forecast
horizon.
Background
The City of Palo Alto (City)’s Electric Utility serves 29,500 customers over an area of
approximately 26 square miles. The City’s maximum demand for electricity in FY 2010 was 186
megawatts (MWs) with a total consumption of electricity of 965 million kilowatt-hours (kWhs).
The Electric Utility is responsible for operations and maintenance of the system and purchases
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almost all of its electricity from outside the City through its contracts with electric generators
and wholesale power providers, with the exception of its small 4.8 MW generating facility
within the City.
In order to maintain the financial viability of the Electric Utility, staff annually reviews its major
cost drivers, evaluates the risks and adequateness of its reserves, and determines the revenue
requirements for the Electric Utility for the next five years. The revenue requirements and
resulting rate adjustment targets depend on a number of components including sales revenue
projections, electric supply costs, distribution system operating and Capital 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 trigger a change, up or down, to the revenue requirement.
During the budget process, staff forecasts customer load, revenues and utility expenses to
quantify the annual revenue requirement. Changes to forecasted revenues or expenses are
reflected in adjustments during the mid-year budget adjustment process.
Discussion
Financial Projections
Table 1 below shows the summary of financial projections for the Electric Utility for FY 2010 –
FY 20161. For FY 2010 both budgeted and realized actuals based on the City’s Audited Financial
Report (CAFR) are shown. For FY 2011 both budgeted and projected financial expectations are
shown. The projected column for FY 2011 reflects known variations from budget as of February
2011. The projections for FY 2012 –FY 2016 are based on FY 2012 budget submissions as of
December 2010.
Total expenses (Row 25 in Table 1) totaled $126.6 million in FY 2010. This is $10.4 million lower
than budgeted. Total revenues (Row 13 in Table 1) were $128.0 million, which is $1.9 million
lower than budgeted. The biggest variation in expenses was $7.8 million due to lower than
expected supply purchase costs. Lower electric consumption accounted for a portion of the
cost savings, but consumption was only 2.3% below budget. The lower costs were primarily
related to lower prices for market energy purchases, and lower than expected transmission
costs. The Electric Utility also paid less for renewable power than it budgeted. This was
because wind resources did not produce as much as expected at budget time and because a
renewable supply contract did not become operational as budgeted. The Electric Utility also
realized a $3.3 million savings in Distribution Operations, and $2.3 million savings in Supply
Operations costs. Counterbalancing this was an increase of $3.4 million for CIP. As a result, the
Electric Utility returned a net sum of $1.4 million to its reserves, instead of the $7.1 million
budgeted drawdown.
The projections for FY 2011 follow a similar pattern. Total expenses are expected to be $10.6
million lower than budgeted. This is mainly due to $10.0 million lower than budgeted supply
1 Details of financial projections for the Electric Fund are provided in Attachment A.
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costs. The lower than budgeted supply costs are due to the decrease in market prices of 34%,
the increase in the availability of hydro resources, and the decrease in renewable purchase
costs2. Another supply cost savings resulted from the refinancing of the Calaveras debt at a
lower interest rate. These cost reductions are partially offset by increased transmission charges
in FY 2011. 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 2011 are $1.5 million lower than budgeted due to a downward
revision of expected demand for electricity in the City as a result of the general economic
conditions in the region. Although expected surplus energy sales are increased by $1.2 million,
the total revenues for the Electric Utility are expected to be $1.9 million lower than budgeted
due to the lower than expected sales revenues as well as downward revisions in the payback
schedules for the Central Valley Project Operations and Maintenance (CVP O&M) Loan Credits
($1.6 million)3.
As a net result, the Electric Utility is expected to return a net amount of $1.6 million to its
reserves, instead of the budgeted drawdown of $7.0 million in FY 2011.
2 Removal of two planned projects from the portfolio (Western Geo and Butte County) and the delayed start of the
Johnson Canyon project.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)
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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Table 1
Five-Year Financial Projections
Five Year Financial Projections
as of Feb 24, 2011
$ (000's)
Adopted Actual Adopted Projected Projected Projected Projected Projected Projected
2010 2010 2011 2011 2012 2013 2014 2015 2016
1 % CHANGE IN TOTAL SYSTEM RETAIL RATE 10.0%10.0%0.0%0.0%0.0%0.0%5.0%5.0%5.0%
2 PROJECTED TOTAL AVERAGE RATE ($/KWH)0.116$ 0.117$ 0.116$ 0.117$ 0.117$ 0.117$ 0.122$ 0.129$ 0.135$
3 PROJECTED COMMODITY COST ($/KWH)0.066$ 0.058$ 0.061$ 0.052$ 0.059$ 0.058$ 0.063$ 0.066$ 0.069$
4 SALES IN GWH 981 965 967 958 957 956 954 968 968
5 PROJECTED CHANGE IN RETAIL SALES REVENUE 10,338 10,303 - - - - 5,549 5,926 6,171
6
7 Utilities Retail Sales 112,719 111,177 111,381 109,915 110,554 110,366 115,445 123,147 129,229
8 Surplus Energy Sales 2,566 1,354 2,759 3,967 1,179 1,576 2,263 3,607 4,025
9 Service Connection Charges 750 1,042 800 800 850 900 925 950 1,000
10 CVP O&M Loan Credit 7,000 6,550 7,000 5,359 5,756 6,141 6,386 6,500 6,800
11 Other Revenues plus Transfers In 1,884 2,116 2,340 2,340 3,028 3,690 4,726 4,848 4,173
12 Interest plus Gain or Loss on Investment 5,024 5,749 4,299 4,299 4,012 3,767 3,498 3,150 2,936
13 Total Sources of Funds 129,943 127,988 128,579 126,680 125,379 126,440 133,242 142,202 148,162
14
15 Purchases to Serve Load 68,026 60,172 64,031 54,015 62,035 61,091 66,177 69,488 71,898
16 Surplus Energy Cost 1,632 1,439 1,967 4,467 975 1,332 1,868 2,826 3,060
17 Joint Venture Debt Service 7,859 7,819 8,849 7,420 8,863 9,383 9,099 9,103 9,114
18 CVP O&M Loan Advance 7,000 6,398 7,000 5,359 5,756 6,141 6,386 6,500 6,800
19 Supply Operations 6,626 4,344 5,700 5,700 6,523 6,815 7,413 8,218 8,635
20 Distribution Operations 22,094 18,775 23,223 23,223 23,751 23,555 23,892 24,304 23,873
21 Rent 3,498 3,813 3,498 3,498 3,598 3,634 3,670 3,707 3,744
22 General Fund Transfers 11,120 11,120 11,195 11,195 11,568 11,596 11,796 12,159 12,504
23 Other Transfers Out 692 785 866 866 900 900 900 900 900
24 Capital Improvement Programs 8,535 11,967 9,285 9,285 7,885 10,497 13,125 12,310 10,590
25 Total Uses of Funds 137,082 126,633 135,614 125,028 131,854 134,942 144,325 149,514 151,117
26
27 Into/ (Out of) Reserves (7,134) 1,355 (7,035) 1,652 (6,475) (8,503) (11,082) (7,312) (2,955)
28
29 Ending Supply RSR 32,541 44,855 41,974 51,585 49,816 47,065 40,797 36,067 36,318
30 Ending Distribution RSR 8,396 9,485 9,443 8,714 9,633 8,265 6,708 7,221 6,955
31 Ending Public Benefits Reserve 4,280 3,750 3,750 3,750 3,363 3,363 3,363 3,363 3,363
32 Ending Calaveras Reserve 64,209 59,865 55,753 55,558 50,320 45,937 42,679 39,584 36,644
34 Ending Plant Replacement Reserve 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
35
36 Risk Assessment Value -Supply RSR 33,600 33,600 26,700 26,700 18,100 24,100 49,633 52,116 53,924
37 Risk Assessment Value- Distribution RSR 5,784 5,784 6,934 6,934 6,600 6,800 9,789 10,436 10,168
38
39 Rate Stabilization Guidelines
40 Supply RSR Minimum 34,013 34,013 32,016 32,016 31,018 30,545 33,088 34,744 35,949
41 Supply RSR Maximum 68,026 68,026 64,031 64,031 62,035 61,091 66,177 69,488 71,898
42
43 Distribution RSR Minimum 6,450 6,450 6,355 6,355 6,391 6,380 6,526 6,957 6,779
44 Distribution RSR Maximum 12,901 12,901 12,711 12,711 12,782 12,760 13,051 13,914 13,558
City of Palo AltoElectric Utility
Fiscal Year
Cost Drivers
Electric Utility expenses are projected to be $6.8 million higher in FY 2012 than in FY 2011,
mainly due to expected increases in the electric purchase costs ($8.0 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
in Surplus Energy Costs ($3.5 million) due to lower surplus energy projected for FY 2012. There
is also an expected increase in the Joint Venture4 Debt Service, and a reduction of CIP by the
same amount of $1.4 million based on deployment plans for infrastructure upgrade projects.
Total revenues, on the other hand, are expected to decline by $1.3 million in FY 2012 compared
to FY 2011 projections. This is mainly driven by the decrease in expected Surplus Energy Sales
($2.8 million) due to lower hydro availability projected for FY 2012, and offsetting smaller
increases expected in Retail Sales due to slightly higher electric demand, and increase in Other
4 Joint Venture refers to the Calaveras hydroelectric resource.
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Revenues due to increases in reimbursements from a telecommunications provider for joint
projects.
For the longer term horizon, Electric Utility costs are expected to increase from $131.9 in FY
2012 to $151.1 million in FY 2016, an average annual increase of 3.5 percent. This is mainly
driven by the expected increases in electric purchase costs and planned CIP expenditures.
Electric purchase costs are expected to increase from their projected levels of $62.0 million in
FY 2012, to $71.9 million in FY 2016, which is an average annual increase of 3.8%. This increase
is largely driven by the expected increases in market prices for electricity as shown in Chart 1,
higher share of renewable resources in the portfolio in order to meet the Renewable Portfolio
Standards (RPS) of 33% by 2015, resource adequacy requirements for local capacity, and
increased California Independent System Operator (CAISO) costs mainly associated with high
voltage and low voltage transmission access charges (HV/LV TAC).
Chart 1
Northern California Peak Electric Prices as of January 31, 2011
0
20
40
60
80
100
120
140
160
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Peak Electric Prices ($/MWh)
ProjectedHistorical
The projections also include the increased funding for Energy Efficiency (EE) resources as part of
the Supply Operations expenditures. It is expected that additional funding in this area will
result in an overall increase of $1.7 million, raising expenditures from $2.5 million in FY 2012 to
$4.2 in FY 2016.
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CIP project funding is also forecast to increase starting in FY 2013, when the Electric Utility
smart grid technology project is estimated to start. Project costs will be between $2 million to
$3 million annually, but is expected to be partially offset by reimbursements and grant funding
of about 65 percent of this amount.
General Fund Transfers are expected to increase from their current levels of $11.6 million in FY
2012 to $12.5 million in FY 2016 based on primarily the expected increases in utility assets as
projected by the CIP expenditures.5
Additionally, staff projects a long-term net cost increase of 1% 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.This conservative
assumption reflects the current expectations for the economic activity for the region.
Depending on the final outcome of other budgetary decisions, final operating budget proposals
will be determined and presented to the Finance Committee at its May 2011 meeting.
Revenue Projections
Retail sales constitute the largest source of revenue in the Electric Utility. Electric demand
projections are discussed in detail in the following section. Going forward, interest and gains
on investments in future years are calculated assuming a 3% return on investment. Other
revenues assume grant funding of $1.5 million to $2.0 million towards the smart grid
technology in future years. Surplus Energy Sales are expected to increase due to increased
market prices and excess resources during certain times of the year throughout the forecast
horizon.
Electricity Demand
Electric demand has generally been very stable in the City. After its 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, it averaged a 0.7% per year increase during the following six years
until FY 2009. The City’s electricity demand experienced another decrease in FY 2010 due to
the recent economic slowdown. This time it only dropped by 3% over FY 2009. The projection
for the short term is almost no change from the current levels in the City’s annual electricity
demand until FY 2014 followed by a modest increase of 0.25% per year on average for the rest
of the forecast horizon.
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
future EE and conservation programs, changes in known large customer attrition/addition,
deployment of photovoltaic systems (PV) and market penetration of electrical vehicles (EVs).
5 General Fund Transfers are calculated using the Council approved (CMR:260:09) Utility Enterprise Methodology
(UEM).
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Specifically, the City plans to increase its EE programs from their current levels. This increased
effort is expected to result in incremental energy savings of about 2.9% by FY 2020. In addition,
the City expects that by 2020 roughly 7,500 residential and commercial customers will be
charging their EVs in the City, which is expected to increase electricity demand by roughly 21
GWh. EVs are also expected to increase Palo Alto’s peak demand by 500 kW in 2020. Similarly,
it is expected that by 2020, local PV systems will be replacing 12 GWhs of electricity and these
new systems are expected to reduce Palo Alto’s peak demand by 6 MWs by the end of the
forecast horizon. The combined effects of EVs, PV, and increased levels of EE programs will
account for a net increase of 13 GWhs of electricity purchases at Citygate and for a decrease of
6 MWs of peak demand by FY 2020. A sizeable customer attrition is expected to lower
electricity demand in the short term by 2.0%, while another significant customer project, which
is expected to go into effect starting FY2015, will increase electricity demand by 1.8% after
partial completion in 2015. Full completion of this project is expected to occur by 2025, which
is outside of the forecast horizon for this report.
Chart 2 presents the historical electric consumption levels in the City from FY 1985 through FY
2010 and projections for FY 2011 through FY 2010.
Chart 2
Palo Alto Electric Consumption
400
500
600
700
800
900
1,000
1,100
1,200
1985 1990 1995 2000 2005 2010 2015 2020
Fiscal Year
Annual Gigawatt hour (GWh) usage
Actual Forecast
Calaveras Reserve Funding
In 1983, the City Council established the Calaveras Reserve in the Electric Utility to help defray a
portion of the annual debt service costs associated with the Calaveras Hydroelectric Project,
which was put in service at that time. The reserve has a balance of $59.9 million as of the end
of FY 2010. Council approved Calaveras Reserve Guidelines (CMR:275:09) require that staff
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annually calculate the “stranded costs” of certain supply-related assets for the upcoming
budget year and for the long-term. Stranded costs are the amount that the cost of an asset is
greater than its value. The guidelines require that the minimum transfer from the Calaveras
reserve to the electric supply operating budget for the upcoming budget year is to be equal to
the stranded cost estimate for that budget year. An additional amount could be transferred
depending on the overall financial circumstances of the Electric Utility.
Based on staff’s assessment of stranded costs, the minimum transfer from the Calaveras
reserve to fund the Electric Utility expenses for FY 2012 is $5.2 million.6 Staff estimated the
stranded cost for the Calaveras Project for FY 2012 taking into consideration: a) the value of
Calaveras generation given expected current reservoir levels, median precipitation and inflows
in the future; b) current wholesale market prices for capacity, energy and ancillary services; and
c) the value associated with the inclusion of a greenhouse gas adder as a value to the Calaveras
Project starting in January 2012. The total value is measured against expected costs of
operations, maintenance and debt service. The portion of the cost that is above market value is
the stranded cost. Table 2 provides the minimum transfers projected from the Calaveras
reserves and fiscal year ending balances for the Calaveras reserves for the next five years.
Table 2
Transfers from Calaveras Reserves ($1000)
FY 2012 FY 2013 FY 2014 FY 2015 FY 2016
Estimated Stranded Costs $5,238 $4,383 $3,258 $3,095 $2,940
Proposed and Projected Transfers $5,238 $4,383 $3,258 $3,095 $2,940
Calaveras Reserve Balance $50,320 $45,937 $42,679 $39,584 $36,644
Revenue Requirement
The revenue requirement is defined as the total amount of revenue that must be collected in
order to meet the planned expenditures for the Electric Utility. Based on the expected
revenues and costs presented in this report, including the transfers from the Calaveras reserve,
the Electric Utility is projected to have a revenue shortfall of $6.5 million in FY 2012 and $8.5
million in FY 2013. Given the level of its rate stabilization reserves discussed in the section
below, the Electric Utility does not require additional revenue adjustments in FY 2012 and FY
2013. Starting in FY 2014 an average rate adjustment of 5% per year will be needed to maintain
the financial viability of the Electric Utility.
Reserves and Risk Assessment
The City’s guidelines for the Electric Supply Rate Stabilization Reserves (E-SRSR) and Electric
Distribution Rate Stabilization Reserves (E-DRSR) are established by the City Council. The
Council reviews reserve adequacy periodically and adjusts the guidelines as needed. The
currently-adopted reserve guideline levels for the E-DRSR are 30% and 15% of sales revenues
6 Staff’s assessment of stranded costs and resulting minimum transfers from the Calaveras reserves was provided
to the UAC in a separate informational report at its April 2011 meeting.
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for maximum and minimum reserve levels respectively. Maximum and minimum guidelines for
the E-SRSR are 100% and 50%, respectively, of supply purchase costs.
These minimum and maximum guidelines represent long term 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 guidelines, staff performs an annual assessment of
short term uncertainties and risks for each of the supply and distribution funds. For the E-SRSR,
the analysis is driven by several factors presented in Table 3. The primary and largest risk is
hydro and renewable production risk, calculated as the cost of purchasing additional electricity
to offset one year of low hydroelectric production (in a 1-in-10 year dry hydro scenario) and low
renewable energy production from existing renewable resources. Another risk considered is
the load net revenue risk, which is defined as the cost of purchasing additional supplies at
market prices higher than the supply portion of the retail rates. Expected market price
uncertainty is a function of the un-hedged portion of the supply portfolio for energy and
capacity and market price uncertainty. As of December 2010, 12% and 25% of the electric
supply portfolio for FY 2012 and FY 2013 was un-hedged, respectively. 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 are also assessed.
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 RSRs are inversely correlated with some of the risks identified for the distribution RSRs.
Specifically, load uncertainty is a risk to the supply RSRs when loads are higher than expected,
but a risk to the distribution RSRs 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 RSRs.
Table 3 summarizes short term cost uncertainties evaluated for the next two years. The sum of
these adverse outcomes totals $18.1 million in FY 2012 and 24.1 million in FY 2013.
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Table 3
Electric Supply Cost Risks
Estimates of Adverse Outcomes
(M$)
Categories of Electric Supply Cost
Uncertainties
FY 2012 FY 2013
1.Load Net Revenue 0.4 0.4
2.Hydro Production: Western & Calaveras 8.8 11.4
3.Renewable Production: Landfill & Wind 0.3 0.4
4.Market Price 1.7 3.7
5.Transmission/CAISO 1.5 1.6
6.Plant Outage 1.0 1.0
7.Western Cost 1.8 2.0
8.Regulatory & Legal 0.6 1.6
9.Supplier Default 2.0 2.0
Electric Supply Fund Risks $18.1 $24.1
For the distribution RSR, the two sources of uncertainty are 1) the revenue shortfall due to a
reduction in electric demand; and 2) unforeseen cost increases in the planned CIP program.
The estimate of revenue shortfall is calculated based on the maximum observed budget to
actual variance in one year during the past ten years, and the unforeseen cost increase is
calculated based on a variance of 10% in planned CIP expenditures for the budget year.
Rate Stabilization Reserve Adequacy
Table 4 summarizes electric supply and distribution reserve requirement guidelines, short term
assessment of risks and estimated end of year reserve balances for E-SRSR and E-DRSR for the
current plus next two fiscal years.
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Table 4
Electric Rate Stabilization Reserve Guideline Levels and Short Term Risk Assessment ($M)
With no rate increase for the next two years, it is estimated that the end of year balance for
both E-SRSR and E-DRSR are expected to be within the long term reserve guideline levels as
well as above the short term risk assessment levels for the current and next two fiscal years.
Rate Comparison with Neighboring Cities
The City currently has a cost advantage with respect to the Electric Utility costs in comparison
with neighboring cities served by the Pacific Gas and Electric Company. However, Santa Clara,
served by Silicon Valley Power, has rates that result in a lower bill for the average residential
customer. Table 5 below presents the average residential customer’s monthly bill for four
neighboring cities using current rates. Comparisons are based on an average usage of 650 kWh
per month. Monthly bills are based on the most recently posted rates in each jurisdiction.
Table 5
Electric Utility Residential Benchmark Comparison
Current FY 2011 (as of February 1, 2011)
Palo
Alto
Mountain
View
Redwood
City
Menlo
Park
Santa
Clara
Average
Benchmark
City
Monthly Bill ($)76.33 106.44 106.44 106.44 66.88 96.55
Difference from
CPAU 39.4%39.4%39.4%-12.4%26.5%
Board/Commission Review and Recommendations
The UAC considered staff’s recommendation at its April 6, 2011 meeting. The Commissioners
discussed the need for the annual transfer from the Calaveras Reserves and requested more
information regarding how it was calculated and an evaluation of the current policy. Staff
explained that its proposal was to implement current Calaveras guidelines that have been
designed to return the Calaveras reserves to the ratepayers over a period of time. Staff also
Electric Supply Rate Stabilization Reserve FY 2011 FY 2012 FY 2013
Estimated End of Year Balance 51.6 49.9 47.1
Risk Assessment 26.7 18.1 24.1
Minimum Level Guidelines 32.0 31.0 30.5
Maximum Level Guidelines 64.0 62.0 61.1
Electric Distribution Rate Stabilization Reserve
Estimated End of Year Balance 8.7 9.6 8.3
Risk Assessment 6.9 6.6 6.8
Minimum Level Guidelines 6.4 6.4 6.4
Maximum Level Guidelines 12.7 12.8 12.8
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stated that the UAC would have an opportunity to review the policies related to the Calaveras
reserve in July, 2011.
On a 4-2 vote (Melton and Keller voting "no" and Eglash being absent), the UAC voted to
recommend a deferral of any transfer of Calaveras Reserves funds to the Electric Operating
Budget for six months. Staff indicated it would recommend to the Finance Committee to follow
the current Calaveras Reserve Guidelines and make the minimum transfer under those
guidelines for FY 2012, and come back to the UAC with an evaluation of Calaveras Reserves in
July 2011.
Resource Impact
Approval of this request will result in the transfer of $5.238 million from the Calaveras Reserve
into the Electric Utility Operating Budget for FY 2012, which is the minimum transfer amount
established by Calaveras Reserve Guidelines.
Policy Implications
This recommendation does not represent a change to current City policies.
Environmental Review
The transfer of $5.238 million from Calaveras Reserves into the Electric Operating Budget is not
subject to the California Environmental Quality Act (CEQA), pursuant to California Public
Resources Code Sec. 21080(b)(8) and Title 14 of the California Code of Regulations Sec.
15273(a)(1) and (3).
Attachments:
·Attachment A: Electric Utility Financial Projections (FY 2012 -FY 2016)(PDF)
·Attachment B Excerpted UAC Draft Minutes of 4-6-11 (DOC)
Prepared By:Ipek Connolly, Sr. Resource Planner
Department Head:Valerie Fong, Director
City Manager Approval: James Keene, City Manager
Five Year Financial Projections
as of Feb 24, 2011
$ (000's)
Adopted Actual Adopted Projected Projected Projected Projected Projected Projected
2010 2010 2011 2011 2012 2013 2014 2015 2016
1 % CHANGE IN RETAIL RATE 10.0% 10.0% 0.0% 0.0% 0.0% 0.0% 5.0% 5.0% 5.0%
2 TOTAL AVERAGE RATE (MILLS/KWh)105 117 116 117 117 117 122 129 135
3 SALES UNITS (GWh)981 965 967 958 957 956 954 968 968
4 ELECTRIC FUND REVENUE
5 BASE SALES REVENUES:
6 COMMODITY SALES 67,266 66,450 66,273 65,536 65,911 65,800 65,659 71,067 74,573
7 DISTRIBUTION SALES 32,952 32,916 42,369 42,339 42,607 42,535 42,444 44,173 46,352
8 PUBLIC BENEFIT REVENUE 2,854 2,864 3,095 3,095 3,092 3,088 3,081 3,284 3,446
9 SUB-TOTAL BASE SALES REVENUE 103,072 102,231 111,737 110,971 111,610 111,422 111,183 118,524 124,371
10 RATE ADJUSTMENT:
11 COMMODITY 0 0 0 0 0 0 4,333 3,553 7,159
12 DISTRIBUTION 10,050 10,039 0 0 0 0 1,061 2,209 (1,159)
13 PUBLIC BENEFIT 288 264 0 0 0 (0)154 164 171
14 TOTAL RATE ADJUSTMENT 10,339 10,304 0 0 0 (0)5,548 5,926 6,171
15 PRORATION IMPACT (431) (429)00(0)0 (231) (247) (257)
16 TOTAL ADJUSTED SALES REVENUE 112,980 112,105 111,737 110,971 111,611 111,422 116,500 124,203 130,285
17 DISCOUNTS/UNCOLLECTABLES (260) (928) (356) (1,056) (1,056) (1,056) (1,056) (1,056) (1,056)
18 INTEREST 5,024 5,749 4,299 4,299 4,012 3,767 3,498 3,150 2,936
19 SURPLUS ENERGY REVENUE 2,566 1,354 2,759 3,967 1,179 1,576 2,263 3,607 4,025
20 PA-GREEN SALES REVENUE 1,039 1,037 1,080 1,080 1,127 1,184 1,243 1,305 1,370
21 SERVICE CONNECTION CHARGES 750 1,042 800 800 850 900 925 950 1,000
22 CVP O&M FUNDING 7,000 6,550 7,000 5,359 5,756 6,141 6,386 6,500 6,800
23 OTHER REVENUE 845 1,079 1,260 1,260 1,901 2,506 3,483 3,543 2,803
24 FROM RESERVES:
25 SUPPLY RSR 8,966 0 2,881 0 1,769 2,751 6,268 4,730 0
26 DISTRIBUTION RSR 0 0 42 771 0 1,369 1,556 0 266
27 CALAVERAS 2,907 4,670 4,112 4,307 5,238 4,383 3,258 3,095 2,940
28 P.B. RESERVE 0 530 0 0 386 0 0 0 0
29 TOTAL FROM RESERVES 11,873 5,201 7,035 5,078 7,394 8,503 11,082 7,825 3,206
30 TOTAL FINANCIAL RESOURCES 141,817 133,189 135,614 131,758 132,773 134,942 144,324 150,027 151,368
31 OPERATING EXPENSES
32 SUPPLY
33 PURCHASES 68,126 60,172 64,031 54,015 62,035 61,091 66,177 69,488 71,898
34 SURPLUS ENERGY COST 1,632 1,439 1,967 4,467 975 1,332 1,868 2,826 3,060
35 PA-GREEN POWER PURCHASES 1,039 704 1,080 1,080 1,080 1,134 1,191 1,250 1,313
36 CALAVERAS DEBT SERVICE 7,759 7,819 8,849 7,420 8,863 9,383 9,099 9,103 9,114
37 CVP O&M FUNDING 7,000 6,398 7,000 5,359 5,756 6,141 6,386 6,500 6,800
38 SUPPLY FUNDED ALTERNATIVE RESOUR 2,665 469 2,185 2,185 2,635 2,846 3,358 4,076 4,400
39 RESOURCE MANAGEMENT, OTHER ADMIN 2,331 2,565 1,915 1,915 2,282 2,305 2,328 2,351 2,374
40 ALLOCATED CHARGES:
41 COST PLAN CHARGES & OTHER 345 355 315 315 318 321 324 327 331
42 UTILITIES ADMINISTRATION 246 251 206 206 208 210 212 214 216
43 SUB-TOTAL SUPPLY 91,143 80,173 87,547 76,961 84,152 84,761 90,942 96,135 99,507
44 DISTRIBUTION
45 OPERATIONS & MAINT, OTHER ADMIN 12,496 11,169 12,367 12,367 12,482 12,607 12,733 12,860 12,989
46 PUBLIC BENEFITS PROGRAMS 3,131 4,048 3,095 3,095 3,479 3,088 3,228 3,442 3,610
47 CUSTOMER DESIGN & CONNECTION CIP 2,010 3,116 1,900 1,900 2,000 2,100 2,200 2,300 2,400
48 SYSTEM IMPROVEMENT (CIP)6,315 8,682 7,270 7,270 5,765 8,272 10,795 9,875 8,045
49 STREET LIGHT, TRAFFIC SIGNAL O&M 809 641 816 816 824 832 840 849 857
50 STREET LIGHT, TRAFFIC SIGNAL CIP 100 632 800 800 800 800 800 800 0
51 COMMUNICATIONS O&M & CIP 435 392 440 440 448 457 465 473 487
52 ALLOCATED CHARGES:
53 COST PLAN CHARGES & OTHER 3,036 (104)2,772 2,772 2,759 2,787 2,815 2,843 2,871
54 UTILITIES ADMINISTRATION 2,397 2,165 3,049 3,049 3,079 3,110 3,141 3,172 3,204
55 SUB-TOTAL DISTRIBUTION 30,729 30,742 32,508 32,508 31,636 34,052 37,017 36,614 34,463
56 TRANSFERS:
57 GENERAL FUND TRANSFER 11,120 11,120 11,195 11,195 11,568 11,596 11,796 12,159 12,504
58 RENT 3,498 3,813 3,498 3,498 3,598 3,634 3,670 3,707 3,744
59 OTHER TRANSFERS 692 785 866 866 900 900 900 900 900
60 TOTAL OPERATING EXPENSES 137,182 126,633 135,614 125,028 131,854 134,942 144,325 149,514 151,117
City of Palo Alto Electric Utility
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Five Year Financial Projections
as of Feb 24, 2011
$ (000's)
Adopted Actual Adopted Projected Projected Projected Projected Projected Projected
2010 2010 2011 2011 2012 2013 2014 2015 2016
City of Palo Alto Electric Utility
Fiscal Year
61 RESERVE FUNDING:
62 PLANT REPLACEMENT 000000000
63 SUPPLY RSR 0 3,413 0 6,731 0000251
64 DISTRIBUTION RSR 2,054 3,144 0 0 919 0 0 513 0
65 P.B. RESERVE 000000000
66 CALAVERAS INTEREST 2,581 0 0 0 00000
67 TOTAL RESERVE FUNDING 4,636 6,557 0 6,731 919 0 0 513 251
68 TOTAL REVENUE REQUIREMENT 141,817 133,189 135,614 131,758 132,773 134,942 144,325 150,027 151,369
69 RESERVES BALANCES
70 PLANT REPLACEMENT 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
71 DISTRIBUTION RSR 8,396 9,485 9,443 8,714 9,633 8,265 6,708 7,221 6,955
72 SUPPLY RSR 32,641 44,855 41,974 51,585 49,816 47,065 40,797 36,067 36,318
73 CALAVERAS 64,209 59,865 55,753 55,558 50,320 45,937 42,679 39,584 36,644
74 P.B. RESERVE BALANCE 4,280 3,750 3,750 3,750 3,363 3,363 3,363 3,363 3,363
75 TOTAL RESERVES BALANCE 110,526 118,955 111,920 120,607 114,132 105,630 94,548 87,235 84,280
76
77 Short Term Risk Assessment Value -Supply RSR 33,600 33,600 26,700 26,700 18,100 24,100 49,633 52,116 53,924
78 Short Term Risk Assessment Value- Distribution R 5,784 5,784 6,934 6,934 6,600 6,800 9,789 10,436 10,168
79
80 Long Term Rate Stabilization Guidelines
81 Supply RSR Minimum 34,013 34,013 32,016 32,016 31,018 30,545 33,088 34,744 35,949
82 Supply RSR Maximum 68,026 68,026 64,031 64,031 62,035 61,091 66,177 69,488 71,898
83
84 Distribution RSR Minimum 6,450 6,450 6,355 6,355 6,391 6,380 6,526 6,957 6,779
85 Distribution RSR Maximum 12,901 12,901 12,711 12,711 12,782 12,760 13,051 13,914 13,558
86
2010 2010 2011 2011 2012 2013 2014 2015 2016
ELECTRIC
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ATTACHMENT B
UTILITIES ADVISORY COMMISSION –MEETING
EXCERPTED DRAFT MINUTES OF APRIL 6, 2011
ITEM 3: ACTION: Electric Long Term Financial Projections and Revenue
Requirements
Senior Resource Planner Ipek Connolly provided a presentation summarizing the key
points from the Electric long term financial projections and revenue requirements report
and the annual Calaveras Reserve stranded cost calculation report. Connolly explained
that no rate increase was proposed for Fiscal Year (FY) 2012, and requested the UAC
recommend to Council a transfer of $5.238 million from the Calaveras Reserve into the
Electric Utility Operating Budget for FY 2012, which is the minimum transfer amount
established by the Council approved Calaveras Reserve Guidelines. Connolly presented
the five-year projected costs and revenue streams, explaining they are provided for
information and are subject to change. The Electric Utility Rate Stabilization Reserve
balances are projected to be within minimum and maximum guidelines for the next five
years with projected 5% per year rate adjustments for FY 2014 –FY 2016. Electric
Utility average customer bills are currently 39% lower than PG&E, and one of the lowest
in California. Connolly also gave a summary of the Calaveras Reserve, including a brief
history and the current guidelines and calculation.
Commissioner Cook asked if there was an explanation for Santa Clara’s low rates and
whether Palo Alto could achieve the lowest rates in the state. Connolly pointed out that
while Santa Clara’s residential rates were lower than Palo Alto’s, its commercial rates
were higher. Commissioner Cook also asked for further explanation about the customer
attrition resulting in lower electric demand expected in the short term. Connolly
explained that there is a large customer leaving Palo Alto and this is being reflected in the
demand forecast.
Commissioner Melton asked if the hospital expansion would have any major CIP
implications for the utility. Utilities’ Director Valerie Fong stated that the utility is not
anticipating anything significant and there was adequate capacity within the
infrastructure.
Commissioner Foster stated that he was not on the UAC when the Calaveras Reserve
guidelines were adopted, but he saw it basically as a subsidy for already low electric
rates, and would like to hold on to the funds for something more useful than a subsidy to
ratepayers. Director Fong said that the UAC would be reviewing the need and purpose of
the Calaveras Reserve later in the year in June. She also explained that the Calaveras
project was originally, and is still today, an above market resource, and so the reserve,
which was prepaid by electric ratepayers, is being used to bring the cost of the project
down to its market value.
Commissioner Berry requested that staff provide an explanation of how the stranded
costs were calculated for the UAC review of the Calaveras Reserve in June. He also
asked how the actual stranded cost compared to the forecasted stranded cost for FY 2011.
ATTACHMENT B
Senior Resource Planner Monica Padilla replied that she did not have the actual number
for 2011, but explained that the stranded costs for Calaveras were the above market costs
and, because market costs had fallen this year, she anticipated that the actual stranded
cost for Calaveras would be the same or even higher than the forecast. Commissioner
Berry questioned the need to transfer funds from the Calaveras Reserve to the rate
stabilization reserve when the rate stabilization reserve is above the minimum guideline
and is forecasted to be above the minimum by the end of FY 2012. Commissioner Berry
stated that he was trying to understand the policy and may want to recommend to the
Council that they reconsider the policy if he felt it was not necessary. Connolly
explained that the Calaveras Reserve was not transferred to the rate stabilization reserve
but to the electric operating budget to compensate ratepayers for the stranded cost of the
Calaveras project. Connolly further explained that the two reserves were independent of
one another and that Calaveras Reserve transfers were not proposed for rate stabilization
purposes but to compensate ratepayers for stranded (above market) costs. If staff had
indicated a need for a rate increase the UAC could have made a recommendation to
transfer additional funds from the Calaveras Reserves to defer such an increase.
Commissioner Melton summarized that the UAC could recommend that Council defer
the transfer from the Calaveras Reserve for a year and that there is a trade off between
using the reserves for projects and returning the reserves to ratepayers. Director Fong
suggested that the UAC could consider combining the reserves when they evaluated the
policy in June, if there were no legal restrictions.
Director Fong said that staff would still be making the recommendation to make the
minimum transfer from the Calaveras Reserve per the adopted guidelines, which were
based on a logical approach to calculating the stranded costs and compensating ratepayers
with the funds from the reserves that had been paid by ratepayers for that purpose.
ACTION:
Commissioner Foster made a motion to recommend Council defer decision on the level
of the transfer for six months until the UAC has time to study the issue further.
Commissioner Cook seconded the motion. The motion passed 4-2 (with Commissioners
Melton and Keller opposed and Commissioner Eglash absent).
Commissioner Melton voted against the motion because although the reserve funds are
segregated into buckets, they are all cash reserves, and he did not see the point in getting
tied up in discussing which reserves funds should be drawn down. Commissioner Keller
agreed with many of the issues that had been discussed, but did not see the benefit to
making the changes immediately rather than waiting for a later review. However, she did
see real costs in terms of staff resources in making changes immediately. Commissioner
Keller recommended a review of the guidelines in June.