HomeMy WebLinkAboutStaff Report 2412-3868CITY OF PALO ALTO
Finance Committee
Regular Meeting
Tuesday, April 15, 2025
Agenda Item
2.Recommendation to the City Council to Adopt a Resolution Approving the FY 2026 Gas
Utility Financial Forecast and Reserve Transfers, the Natural Gas Cost of Service and Rate
Study, and General Fund Transfer; and Amending Rate Schedules G-1 (Residential Gas
Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-3 (Large
Commercial Gas Service), and G-10 (Compressed Natural Gas Service) and Implement a
Climate Credit in FY 2026 Staff Presentation
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Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: April 15, 2025
Report #: 2412-3868
TITLE
Recommendation to the City Council to Adopt a Resolution Approving the FY 2026 Gas Utility
Financial Forecast and Reserve Transfers, the Natural Gas Cost of Service and Rate Study, and
General Fund Transfer; and Amending Rate Schedules G-1 (Residential Gas Service), G-2
(Residential Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas Service),
and G-10 (Compressed Natural Gas Service) and Implement a Climate Credit in FY 2026
RECOMMENDATION
The Utilities Advisory Commission and Staff request that the Finance Committee recommend
that the City Council adopt a resolution (Attachment A):
1. Approving the Fiscal Year 2026 Gas Utility Financial Forecast shown in this staff report and
attachments; and
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve to
the Distribution Rate Stabilization Reserve at the end of FY 2025; and
3. Approving the Natural Gas Cost of Service and Rate Study (Attachment F); and
4. Transferring up to 18% of gas utility gross revenues received during FY 2024 to the
General Fund in FY 2026; and
5. Amending Rate Schedules (Attachment B) effective July 1, 2025 (FY2026):
a. G-1 (Residential Gas Service)
b. G-2 (Residential Master-Metered and Commercial Gas Service)
c. G-3 (Large Commercial Gas Service)
d. G-10 (Compressed Natural Gas Service)
The Utilities Advisory Commission also recommends that the Finance Committee recommend
that the City Council approve the use of approximately $1.6 million of Cap-and-Trade allowance
auction proceeds to provide a one-time flat climate credit of $73.20 to each residential (G-1)
customer only in FY 2026.
EXECUTIVE SUMMARY
The City of Palo Alto Utilities (CPAU) provides electricity, water, wastewater, natural gas, and
fiber optic services to the Palo Alto community. The Public Works Department also provides
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refuse collection and processing for recycling, compost and garbage, wastewater treatment and
stormwater management. The City’s primary goals are to manage these services in a way that
ensures continued safe, reliable, environmentally sustainable, and cost-effective operations.
The City is proposing rate increases this year for electric, natural gas, wastewater and water
services. As a locally owned municipal utility, CPAU’s rates by law, are designed to recover the
costs of purchasing and delivering these utility services to customers. The City strives to be
transparent with utilities customers about the reason for rate changes, including explaining the
cost drivers, benefits to customers, what the City is doing to keep costs low for ratepayers, and
the services and programs provided by the City to help customers keep utility bill costs
low. Attachment E outlines CPAU’s plan for communicating rate changes to customers. Staff
are presenting an overview of the financial forecast and rate change proposal for each utility
service to the Utilities Advisory Commission (UAC) and Finance Committee prior to City Council
review and approval in June 2025.
Table 1: Current Year (FY2025) and Projected Overall Rate Trajectory from FY 2026 to FY 2030
BACKGROUND
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This staff report provides the Finance Committee with a financial forecast for the Gas Utility,
provides an overview of the utility’s operations costs, capital costs, and debt and includes
recommended rate adjustments required to maintain the utility’s financial health. Attachment D
contains a set of Reserves Management Practices describing the reserves. This work is done
annually as part of the budget and rate-setting cycle.
ANALYSIS
Past Trends
Table 2: FY 2024 Actuals vs. Prior Year’s Forecast ($000)
Net Cost/
(Benefit)
Variance
Type of Change
Net Cost / (Benefit) of Variances 3,859 Net Cost Increase
Projections
Overview
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2025, reflecting a deferral of a rate-funded Gas Main Replacement project construction (from FY
2025 to FY 2027 and FY 2029), to be replaced by a federally grant-funded project.1
Looking ahead to the five-year forecast period from FY 2026 to FY 2030, supply-related costs are
expected to increase at an average annual rate of 6%, with commodity prices projected to grow
by 3% annually. Furthermore, distribution expenses are forecasted to rise by an average of 7%
annually.
Figure 1 shows the actual overall system average rate percentage change from FY 2018 through
FY 2025 (grey) and the projected overall system average rate change for FY 2026 through FY 2030
(red), excluding supply-related rate changes. The rate increases shown in Figure 6 include the
needed increase for the distribution rate as a percentage of the base Gas Utility sales revenue.
Figure 1: Gas Utility Expenses, Revenues, Rate Changes Excluding Supply-Related Changes
Actual Costs through FY 2024 and Projections through FY 2030
*FY25 Commitments and Reappropriations reserves balances for Operations and Capital Investment are
anticipated to be utilized in FY 2026 and FY 2027.
Note: Revenues and Expenses exclude Cap-and-Trade auction sales revenue, which goes directly to the Cap-and-
Trade reserve.
1 Staff Report 2411-3777, February 3, 2025;
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=83226 Council unanimously voted to
authorize the City Manager or their Designee to Execute an Assistance Agreement with the United States
Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) in the amount of
$16,519,879 through January 31, 2030.
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Load Forecast
Gas usage in Palo Alto declined from FY 2020 to FY 2022, mainly due to the impacts of the COVID-
19 pandemic. However, FY 2023 saw an increase in gas usage, likely driven by a modest recovery
from COVID-19 effects and colder than average winter temperatures. However, similar to
previous declines in gas usage due to economic factors, it is unlikely that consumption will return
to pre-conservation or pre-pandemic levels. Instead, a long-term decline in gas usage is expected.
Further changes, such as the voluntary replacement of gas appliances with electric appliances
and building electrification are also expected to lower long run usage. Staff will conduct strategic
planning and financial analysis separately from this financial forecast to develop a financial and
infrastructure strategy for the Gas Utility as the community electrifies. Any insights from that
analyses will be integrated into future financial forecasts.
Staff worked with a consultant to assist in the development of an updated gas load forecast,
which included statistically adjusted end-use (SAE) modeling, weather-normalized modeling,
economic factors, and an electrification assumption. The result, shown in Figure 2, projects gas
supply load for FY 2026 at 26,172,070 therms, about 5% lower than prior year’s forecast.
Projections for subsequent years have also been adjusted downward by about 5% compared with
last year’s forecast. This reduction reflects decreased consumption in FY 2024, which has slightly
shifted the long-term trend. Over time, declining gas consumption is expected to increase
pressure on rates, as rising and fixed costs for gas operations and distribution will need to be
allocated across fewer units sold.
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Fiscal Year
FY25 Load Forecast FY26 Load Forecast Actual
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Revenues
This financial forecast bases sales revenue projections on the load forecast. Except where stated
otherwise, these load forecasts are based on normal weather. Weather can vary substantially,
however, and this can affect revenues substantially. Changes in customer behavior,
improvements to gas appliances efficiency, and electrification all impact gas usage. Staff regularly
monitor emerging trends and make updates to forecasts as needed.
The Gas Utility’s costs fall into two main categories: gas supply costs and distribution-related
costs. Gas supply costs encompass the cost of the gas itself, its transmission to Palo Alto, and
associated environmental expenses. These supply-related costs vary with the market or are set
by other entities and are passed through to customers. Distribution-related costs cover the
operation of the distribution system, capital improvement, and overall business operations and
are collected through a distribution rate adjusted annually.
Table 3 shows total Gas Utility costs. The operations and capital costs are considered distribution
costs. Current projections show distribution costs increasing 7% on average from FY 2025 through
FY 2030.
Commodity 11,789 10,087 12,487 12,838 12,640 12,153 11,803
Transportation 4,418 6,836 7,370 7,638 8,106 8,593 9,092
Carbon Offset 2,705 1,616 1,855 2,151 2,343 2,701 2,950
Cap-and-Trade 3,860 3,857 4,380 4,933 5,518 6,131 6,763
Operations 32,873 34,843 36,692 38,123 39,554 41,562 43,597
Capital 7,225 3,682 15,775 22,120 10,571 17,707 11,179
Supply Costs
Supply costs consist of the commodity cost of natural gas, gas transmission charges, and
environmental compliance costs. These costs are passed directly to customers and are shown as
line items on their utility bills.
Overall, supply expenses are projected to increase by an average of about 6% per year from FY
2025 through FY 2030. Gas commodity costs, which are the most variable component, account
for the largest share of overall costs. Although market forecasts currently indicate that gas prices
will remain relatively steady over the next several years, those forecasts are highly uncertain. The
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financial forecast assumes that gas prices increase by an average of about 3% annually during the
forecast period.
Transportation and environmental compliance costs are also expected to rise gradually over the
forecast period. PG&E's local transportation rates, which have experienced steady increases in
recent years, are expected to rise by an average of 6% per year throughout the forecast period2.
Because the Gas Utility is regulated under California’s greenhouse gas (GHG) regulations, the Gas
Utility incurs Cap-and-Trade compliance costs. The regulation requires Palo Alto to purchase
allowances based on actual gas load. Staff estimates that Cap-and-Trade allowance costs will
increase on average by 12% annually over the forecast period.3
The Gas Utility also generates revenue from the sale of free allocated allowances. In FY 2024 and
in accordance with Council-approved Cap-and-Trade revenue uses (Council Resolution 100774)
and Council’s goal of reducing GHGs 80% by 2030, Palo Alto began allocating Cap-and-Trade
reserves to support programs such as the Full-Service Heat Pump Water Heater Program.
The City also has a Carbon Neutral Natural Gas plan (Staff Report 74415), which involves
purchasing carbon offsets equivalent to the emissions generated by the community's natural gas
use. These high-quality offsets fund projects that reduce GHG emissions, such as forest
conservation or methane capture from dairy farms. While purchasing carbon offsets is an
important initial step in reducing carbon emissions, the long-term goal is to decrease the
community's natural gas usage by maximizing efficiency and transitioning to high-efficiency
electric appliances where feasible. Carbon offset costs are projected to rise by 13% annually
through the forecast period.
In response to the dramatically high natural gas prices that occurred during winter 2022-23 and
to mitigate the impact of short-term price spikes, staff implemented a gas hedging program
effective beginning winter 2023-24. The program currently calls for the inclusion of a gas price
mitigation adder in the gas commodity charge to customers while maintaining the practice of
purchasing gas at market prices. Funds collected from the gas price mitigation adder will accrue
in the Gas Distribution Rate Stabilization Reserve and be used to offset the impact of a potential
gas market price spike above the maximum gas commodity charge to customers.
Operations
Operations costs are projected to increase by about 4% annually on average from FY 2025 to FY
2030, primarily due to higher allocated charges and salary and benefit expenses. The operations
2 The transportation rates for calendar years 2023-2026 reflect the rates in the December 15, 2021 prepared
testimony (A.21-09-018) regarding PG&E’s 2023 Gas Transmission & Storage (GT&S) Cost Allocation and Rate
Design (CARD), afterward a 3% escalation rate is applied.
3 Based on allowance broker quotes.
4 Council Resolution 10077 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61567
5 Staff Report 7441; https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=80132
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costs in this forecast include $0.7 million for the cross-bore program in FY 2026. The safety
program ensures that gas pipelines have not crossed through sewer laterals, which is rare but
possible during trenchless installation. This "cross-bore" configuration poses a risk of gas leaks as
due to accidental cut by a plumber using a cutting tool to clear a sewer line. While a majority of
sewer laterals have been inspected, staff has come across several services which are unable to
be scoped, due to either infiltration by roots or broken/collapsed pipe segments. Figure 3 shows
the actual operations costs through FY 2024 and projected operations costs for the Gas Utility
from FY 2025 through FY 2030.
Figure 3: Actual and Projected Operations Costs
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will replace and provide the full funding for GMR 25 and this replacement will take place in FY
2026 and FY 2027. About $3.7 million that was already reappropriated for this project from FY
2024 will return to the Operations Reserve. The original GMR 25 budget of $9.8 million, initially
scheduled for FY 2025, has been reallocated and split between GMR 26 and GMR 27, with
construction now planned for FY 2027 and FY 2029, respectively. CPAU will continue to look for
other grant opportunities to help fund the replacement of PVC and steel distribution mains in the
gas system.
Table 4: Budgeted Gas CIP Spending ($000)
Table 5: Debt Service Coverage Ratio ($000)
FY 2025 FY 2026
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Reserves
The unprecedented and extreme gas prices experienced in FY 2023 depleted the Gas Utility's
reserves. A series of multi-year rate increases to the distribution rates were planned to bring the
reserves back within guideline levels. The rate increases in this financial forecast continue that
plan to replenish the Gas Utility’s reserves over the next several years. The FY 2025 Financial Plan
proposed allowing the Operations Reserve to fall below the risk assessment levels for FY 2024
and FY 2025, with a plan to return to within the guideline range by the end of FY 2026. The
Operations Reserve is now expected to be above minimum at the end of FY 2025. However, due
to the CIP Reserve contributions starting in FY 2027, the Operations Reserve is expected to
remain close to the minimum guideline levels: it is expected to be at target levels by FY 2030.
Figure 4 shows the actual year-end balance in the Operations Reserve from FY 2018 to FY 2024
and projected from FY 2025 through FY 2030.
Table 6 summarizes the risk assessment calculation for the Gas Utility through FY 2030. The risk
assessment is intended to be covered by the Operations Reserve and includes the revenue
shortfall that could occur due to:
1. Maximum non-commodity revenue percentage variance from the previous ten years; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget year.
Reserve Maximum
Reserve Target
Reserve Minimum
Risk Assessment
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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Fiscal Year
Reserve (Year-End)
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Table 6: Gas Risk Assessment ($000)
Total non-commodity revenue 36,754 41,131 45,295 49,599 54,285 59,344
Risk of Revenue Loss @14% 5,157 5,771 6,356 6,960 7,617 8,327
CIP Budget 2,068 14,070 20,375 8,784 15,877 9,303
CIP Contingency @10% 207 1,407 2,037 878 1,588 930
Staff estimates that the gas price mitigation adder in the gas commodity charge will collect about
$1.126 million in FY 2025 for the gas hedging program. Although these funds are initially collected
in the Operations Reserve, they should be transferred to the Gas Distribution Rate Stabilization
Reserve to be available to mitigate the impact of potential gas market price spikes exceeding the
maximum gas commodity charge to customers. To support this objective, staff proposes
transferring up to $1.5 million from the Gas Utility Operations Reserve to the Gas Distribution
Rate Stabilization Reserve at the end of FY 2025. The exact transfer amount will be determined
at year end based on calculations aligned with the gas hedging program.
Figure 5 shows the CIP Reserve balances from FY 2018 through FY 2030. The CIP Reserve is
currently depleted; however, planned transfers in FY 2027 through FY 2030 will replenish the CIP
Reserve to within guideline range. With these transfers, the CIP Reserve would reach the
minimum guideline level by FY 2028. Per the Reserves Management Practices (Attachment D),
Section 6, any rate plan that does not return CIP reserves above minimum levels within one year
requires Council approval.
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Figure 5: Gas CIP Reserve Levels for FY 2018 through FY 2030
Figure 6 shows year-end reserve balance levels for each reserve from FY 2018 through FY 2030.
Table 7 shows reserve starting and ending balances, revenues, transfers expenses, capital
program contribution and operations reserve guideline levels from FY 2025 to FY 2030.
Reserve Minimum
Reserve Maximum
$0
$2
$4
$6
$8
$10
$12
$14
$16
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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CIP Reserve (Year-End)
$0
$5
$10
$15
$20
$25
$30
$35
2018 2019 2020 2021 2022 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
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Fiscal Year
Rate Stabilization
Commitments &
Reappropriations
CIP Reserve
Operations Reserve
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Table 7: Operations, CIP, Cap-and-Trade, and Debt Service Reserve Starting and Ending
Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contribution To/(From)
Reserves, and Reserve Guideline Levels for FY 2025 to FY 2030 ($000)
*Operations Reserve represents the Gas Supply Fund Rate Stabilization Reserve and the Gas Distribution Fund
Operations Reserve combined.
The Gas Utility’s rates are evaluated and implemented in compliance with cost-of-service
requirements set forth in the California Constitution and applicable statutory law. Staff engaged
the services of EES Consulting (EES) to review and revise the Gas Utility’s Cost of Service (COS)
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for FY 2026.6 A copy of the FY 2026 COS study titled “City of Palo Alto Natural Gas Cost of Service
and Rate Study,” (Natural Gas Cost of Service and Rate Study), February 2025 is included as
Attachment F to this report. The study examines and allocates the Gas Utility’s costs to each rate
class to develop proposed FY 2026 distribution rates and includes a recommendation to refine
the G-2 rate schedule as explained below. This financial forecast is based on staff’s assessment
of the financial position of the Gas Utility using the methodology from the Natural Gas Cost of
Service and Rate Study described above.
Refinement of G-2 (Residential Master-Metered and Commercial Gas Service) Rate Schedule
Table 8: G-2 Service by Maximum Meter Capacity7
G-2 Service by Maximum
Meter Capacity Range # of
Services
≤ 220 scfh
≥ 4,000 scfh
Distribution Revenue Requirement
6 Since FY 2021, the City has adjusted its distribution rates annually based on the COS study for FY 2020, which was
also conducted by EES.
7 Meter capacities in this staff report are all at an assumed pressure of 7 inches of water column (equivalent to
0.25 pounds per square inch).
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of Service and Rate Study allocates these asset and expense estimates using updated
classification and allocation factors to ensure that the Gas Utility’s costs are properly assigned to
each rate class.
8 – the amount to be recovered through distribution rates via G-1, G-2 and
G-3 rate schedules. Current distribution rates (effective beginning July 1, 2024) at the same FY
2026 sales forecast would generate only $38.0 million in revenue and result in a $3.3 million
revenue shortfall. Thus, an 8.7% overall increase in distribution rates is needed to generate
sufficient revenue to cover FY 2026 distribution revenue requirement.
9 result in a revenue requirement
distribution (among the rate schedules) that differs from the prior cost study. Thus, the
percentage of revenue increase needed varies by rate schedule—ranging from 0% for G-2 to
15.6% for G-1. Tables 11 and 12 in the Proposed Rates section of this report present the current
and proposed rates associated with the following COS revenue requirement estimates.
Table 9: COS Revenue Requirement and Revenue Increase
8 This includes distribution costs, certain supply costs that are not paid for by pass-through supply charges (such as
administrative charges allocated to gas supply), and additional amounts required to restore the gas utility’s
operations reserve to within the guideline range in FY 2026.
9 For example: update in meter costs; adjustment to factor used to allocate General Fund Transfer to rate classes.
See Natural Gas Cost of Service and Rate Study (Attachment F of this report) for more details.
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Table 10: COS Revenue Requirement and Revenue Increase, G-2
Table 11 shows the current and proposed monthly service charges, while Table 12 shows the
volumetric charges related to distribution for all rate schedules. As previously noted, supply-
related charges are pass-through charges that update periodically. The latest charges are
shown in the City’s Rates website10. The proposed rates reflect the Natural Gas Cost of Service
and Rate Study adjustments conducted this year, which recommends a refinement of the G-2
rate schedule by establishing three meter capacity groupings.
10 City’s Rates Website https://www.cityofpaloalto.org/files/assets/public/v/25/utilities/rates-schedules-for-
utilities/residential-utility-rates/monthly-gas-volumetric-and-service-charges-residential-3.pdf
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Table 11: Current and Proposed Monthly Service Charges
G-1 (Residential)$ 16.93 $ 19.52 $ 2.59 15.3%
G-2 (Small Commercial)
G-2 (≤ 220 scfh)156.90 29.06 (127.84)(81.5%)
G-2 (> 220 and < 4,000 scfh)156.90 94.94 (61.96)(39.5%)
G-2 (≥ 4,000 scfh)156.90 417.62 260.72 166.2%
G-3 (Large Commercial)717.89 1,731.67 995.78 138.7%
G-10 (CNG)106.11 115.34 9.23 8.7%
(Residential)
Tier 1 Rates $ 0.8229 $ 1.2274 $ 0.4045 49.2%
Tier 2 Rates 2.1043 1.8972 (0.2071) (9.8%)
(Residential Master-Metered and Small Commercial)
Uniform Rate $ 1.0809 $ 1.2616 $ 0.1807 16.7%
(Large Commercial)
Uniform Rate $ 1.0702 $ 1.1616 $ 0.0914 8.5%
(Compressed Natural Gas)
Uniform Rate $ 0.0175 $ 0.0190 $ 0.0015 8.6%
Table 13 shows the impact of the proposed July 1, 2025 rate changes on the median monthly
residential bill for representative average winter and summer bills, excluding supply-related
cost changes. The annual gas bill for the median residential customer is projected to be 21%
higher in FY 2026 than FY 2025. This increase is due to the overall 5% revenue increase needed
system-wide together with the cost of service adjustments. The actual impact may be different
because customer gas usage varies and commodity price changes monthly. Table 13 shows a
representative winter period (November thru March) and summer period (April through
October) bill comparison.
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Table 13: Impact on Residential Monthly Bill due to Proposed Gas Rate Changes11
ChangeUsage
(Therms/month)
Bill Amount
(Current Rates)
Bill Amount
(Proposed Rates)$/mo.%
Summer
10 $ 33.75 $ 40.38 $ 6.64 19.7%
17 (median) 45.52 54.99 9.47 20.8%
30 79.70 86.50 6.80 8.5%
45 124.15 127.84 3.69 3.0%
Winter
30 $ 68.69 $ 83.41 $ 14.73 21.4%
51 (median) 104.92 128.14 23.22 22.1%
80 180.07 203.03 22.96 12.8%
150 390.54 399.00 8.47 2.2%
Annual Median $ 70.27 $ 85.47 $ 15.20 21.6%
Table 14 shows the impact of the proposed rate changes, effective July 1, 2025, on
representative commercial customer bills, excluding supply-related cost changes. The G-2 usage
levels listed below represent the median usage for the three G-2 rate class groupings, as
recommended by the Natural Gas Cost of Service and Rate Study. G-2 customers with meter
capacity within the lowest (proposed) capacity range and corresponding lower usage would see
a significant reduction in monthly bill because of the proposed change in Monthly Service
Charge (e.g., representative bill at 35 therms/month in Table 14 below reflects a reduction of
$127.84 in Monthly Service Charge, partially offset by the volumetric rate increase). For the G-3
rate class, the usage reflects a sample large commercial customer with an annual consumption
of approximately 250,000 therms.
11 Current rates are derived from actual commodity prices up to January 2025 and forecasted prices until June
2025. Proposed rates, while based on the same supply-related rates as current rates, incorporate adjustments
solely in the increase of distribution rates.
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Table 14: Impact on Commercial Monthly Bill due to Proposed Gas Rate Changes12
ChangeUsage
(Therms/month)
Bill Amount
(Current Rates)
Bill Amount
(Proposed Rates)$/mo %
G-2 (Residential Master-Metered and Small Commercial)
35 $ 226.51 $ 105.07 $ (121.44)-54%
280 706.04 694.62 (11.42)-2%
2,648 5,356.93 6,096.22 739.29 14%
G-3 (Large Commercial)
20,834 $ 41,287.45 $ 44,187.46 $ 2,900.01 7%
Bill Comparisons/Competitiveness
Table 15 presents the median residential bills for Palo Alto and PG&E customers from FY 2022
to FY 2026. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an
area which includes Palo Alto’s surrounding communities.
In FY 2023, the annual gas bill for the median Palo Alto residential customer was about $892, or
6% higher compared to a PG&E customer with equivalent consumption. This is attributed to the
gas price spike during the winter of 2022/2023, which impacted all California utilities except
PG&E, which avoided exceptionally high gas prices.
In FY 2025, the estimated annual gas bill for the median Palo Alto residential customer is
projected to be about 16% lower than that of a PG&E customer with equivalent consumption.
With the implementation of the Natural Gas Cost of Service and Rate Study adjustment and the
proposed rate increases, Palo Alto median residential bills are expected to be about 3% lower
than PG&E bills in FY 2026. It is important to note that this 3% difference is likely understated,
as this projection assumes PG&E does not implement additional rate increases between now
and July 2026.
Table 15: Residential Annual Natural Gas Bill Comparison ($/year)
Time Period Median Usage Palo Alto PG&E Zone X % Difference
FY 2022 $ 657.83 $ 724.24 (9%)
FY 2023 891.89 845.03 6%
FY 2024 753.28 764.70 (1%)
FY 2025* 843.26 1,008.72 (16%)
FY 2026 **
Annual
(374 Therms)
1,025.62 1,052.11 (3%)
*Calculated based on actual and projected rates
**Calculated based on projected rates
12 Current rates are derived from actual commodity prices up to January 2025 and forecasted prices until June
2025. Proposed rates, while based on the same supply-related rates as current rates, incorporate adjustments
solely in the increase of distribution rates.
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Table 16 presents the median commercial bills for Palo Alto and PG&E customers from FY 2022
to FY 2026. Palo Alto bills have been higher than PG&E’s bills over the years, mainly due to
higher customer charges. With this COS adjustment, commercial customer charges have been
adjusted downward for the majority of commercial customers, making bills more competitive
with PG&E. With the implementation of the COS adjustment and the proposed rate increases,
Palo Alto median commercial bills are expected to be about 24% higher than PG&E bills in FY
2026, assuming PG&E does not implement additional rate increases.
Table 16: Commercial Annual Natural Gas Bill Comparison ($/year)
Time Period Median Usage*** Palo Alto PG&E Zone X % Difference
FY 2022 6,507.57 5,602.19 16%
FY 2023 8,844.11 6,506.91 36%
FY 2024 7,426.78 6,022.59 23%
FY 2025* 8,472.51 6,523.21 30%
FY 2026**
Annual G-2
(3,356 Therms)
8,335.42 6,727.68 24%
*Calculated based on actual and projected rates
**Calculated based on projected rates
***Calculated based on G-2 with meter capacity of >220 and <4,000 scfh
Climate Credit Option
As shown in Table 13 above, median residential gas bills are expected to increase by about 21.6%
(approximately $15.20 per month or $182.40 per year) in FY 2026, compared with FY 2025. The
Gas Utility is a covered entity under California’s Cap-and-Trade program. CARB’s Cap-and-Trade
regulations authorize utilities to distribute Cap-and-Trade auction proceeds to some or all
ratepayers in a non-volumetric manner. Thus, Council may authorize staff to distribute
approximately $1.6 million in Cap-and-Trade reserve funds to provide a one-time flat $73.20
climate credit to each residential gas customer in FY 2026,13 lessening the rate increase impact
to the median residential customer from approximately $182.40 to $109.20 for FY 2026. While
the credit only applies to gas customers, the $73.20 credit would be the equivalent of reducing
an overall utility median bill increase for electric, gas, water, wastewater, refuse, and stormwater
from 11% to 9% for FY 2026. Cap-and-Trade revenues are earmarked for the benefit of retail
natural gas ratepayers and for GHG emission reduction activities, and subject to any limitations
imposed by Council. For context, $1.6 million is approximately the cost to fully electrify 182
homes.
13 In accordance with the California Cap-and-Trade Program, specifically California Code of Regulations, Title 17,
Section 95893(d)(3)(C) https://ww2.arb.ca.gov/sites/default/files/2021-02/ct_reg_unofficial.pdf, utilities are
authorized to distribute Cap-and-Trade auction proceeds to some or all ratepayers in a non-volumetric manner.
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Cap-and-Trade Reserve Transfer
In accordance with Section 11 of the Gas Reserve Management Practices and Council-approved
Cap-and-Trade revenue uses (Council Resolution 1007714), staff is authorized to transfer
revenues from allocated allowance auction proceeds to the Cap-and-Trade Reserve at the end of
each fiscal year. Additionally, staff may utilize funds from the Cap-and-Trade Reserve to support
greenhouse gas (GHG) reduction programs by transferring funds from the Cap-and-Trade Reserve
to the Operations Reserve.
Under the Cap-and-Trade Regulation, interest earned on allocated allowance auction proceeds
is considered value derived from the allocation of allowances and is subject to the same
distribution requirements. Staff has determined that the accumulated interest amounts to
$1,092,855.17 from Calendar Year (CY) 2015 to CY 2024. Therefore, staff will transfer this amount
from the Operations Reserve to the Cap-and-Trade Reserve in addition to the annual transfers of
allocated allowance revenue and program expenses. Going forward this calculation and transfer
will be done annually.
General Fund Transfer
The Gas Utility's transfer to the City’s General Fund is a component of the City’s gas rates. This
transfer was first authorized by voters in 1950 and reaffirmed in November 2022 with the
passage of Measure L, which authorizes a transfer amount up to 18% of the gross revenues of
the Gas Utility. This financial forecast proposes a transfer of $9.735 million in FY 2026, 18% of FY
2024 gross revenues. This transfer of 18% is in alignment with the assumptions in the FY 2025
Adopted Budget process.
Next Steps
Staff will incorporate the Finance Committee’s recommendations into the draft financial forecast and
attachments and bring those to the City Council in June. The City Council will consider the proposed
financial forecast and rate schedules with the FY 2026 budget review and adoption process in
June 2025. If Council approves the proposed rate changes, the rates will become effective July 1,
2025.
FISCAL/RESOURCE IMPACT
The resource impact of the recommendations summarized in this report is the continued
financial solvency of the Gas Utility and, as the City is a ratepayer, an increase to General Fund
expenses (due to the rate increases) and revenues (due to the General Fund transfer).
Based on the proposed rates increase as shown, the estimated revenue impacts in FY 2026 would
be an increase of $3.3 million in the Gas Fund, not including fluctuations in commodity
14 Council Resolution 10077 https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=61567
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revenue/cost. Utility rate increases impact the general fund because the City is a customer of the
Gas Utility. The impact to the general fund from the proposed rate increases is a $0.17 million
expense increase. Additionally, the change in General Fund revenues from FY 2025 to FY 2026
would decrease from $10.917 million in FY 2025 to $9.735 million in FY 2026, a decrease of about
$1.183 million. The FY 2025 transfer was unusually high because it was based on FY 2023 revenue,
which was elevated due to the gas price spike during the winter of 2022-23.
POLICY IMPLICATIONS
The proposed Gas Utility rate adjustments are consistent with Council-adopted Reserve
Management Practices (Attachment D) and were developed using a cost-of-service study and
methodology consistent with the California constitution and industry-accepted cost of service
principles. If reserves fall below the minimum guidelines, Council approval is required for a rate
plan that requires more than one year to return reserves to within guideline levels. This staff
report serves as the required plan.
STAKEHOLDER ENGAGEMENT
Staff presented preliminary rate proposals to the Finance Committee on December 3, 202415 for
discussion only. One Committee member asked about the impact of population changes and one
Committee member said that demographic changes should be included. Staff explained that the
projection assumes lower gas sales due to electrification and we are considering population and
factoring in electrification.
Staff presented preliminary rate proposals to the UAC on December 4, 202416 for discussion only.
One Commissioner asked about how electrification was incorporated in the forecast and staff
explained that an outside consultant performed a regression with an electrification scenario that
was used for the gas purchase forecast. Commissioners asked about reserve guidelines and
reserve levels. One Commissioner expressed interest in the true cost of gas, considering the
environmental externalities.
On April 2, 2025, staff presented rate proposals to the UAC. The UAC recommended approval of
this proposal with a 5-1 vote with one abstention. The Commissioner who voted against the staff
proposal expressed concern about the cost of service study results and in particular the increase
in rates for the residential (G-1) customer class. The UAC also recommended through a 6-1 vote
to recommend to the Finance Committee and Council to approve the use of approximately $1.6
million of Cap-and-Trade allowance auction proceeds to provide a one-time flat climate credit of
15 December 3, 2024 Finance Committee Meeting, Staff Report
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=64761 , Minutes
https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=39017 , Video
https://www.youtube.com/watch?v=-tshOdaDA3A%3Ffeature%3Dshare
16 December 4, 2024 Utilities Advisory Commission, Staff Report
https://cityofpaloalto.primegov.com/Portal/viewer?id=0&type=7&uid=d7cd6030-1d05-412e-a96b-cabd33557bc1,
Minutes https://recordsportal.paloalto.gov/Weblink/DocView.aspx?id=41244 , Video
https://www.youtube.com/watch?v=tfznidSYXiU%3Ffeature%3Dshare
23
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$73.20 to each residential (G-1) customer only in FY 2026. The Commissioner who voted against
the climate credit option said that green funds should not be used to subsidize the use of fossil
fuels. The video of the meeting is available on the City’s website at the following link:
https://www.youtube.com/watch?v=021zJQHLADI
ENVIRONMENTAL REVIEW
ATTACHMENTS:
APPROVED BY:
Attachment A
NOT YET APPROVED
Resolution No.
Resolution of the Council of the City of Palo Alto Approving the Fiscal
Year 2026 Gas Utility Financial Forecast and Reserve Transfers, the
Natural Gas Cost of Service and Rate Study and General Fund
Transfer, and Amending Rate Schedules G-1 (Residential Gas
Service), G-2 (Residential Master-Metered and Commercial Gas
Service), G-3 (Large Commercial Gas Service), and G- 10 (Compressed
Natural Gas Service)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations, including reserves.
This includes making long-term projections of market conditions, the physical condition of the
system, and other factors that could affect utility costs, and setting rates adequate to recover
these costs. It does this with the goal of providing safe, reliable, and sustainable utility services
at competitive rates. The City adopts Financial Forecasts or Plans to summarize these
projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Forecasts or Plans.
C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of
the City of Palo Alto may by resolution adopt rules and regulations governing utility services,
fees and charges.
D. On June 9, 2025, the City Council heard and approved the proposed rate
increase at a noticed public hearing.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby adopts the fiscal year (“FY”) 2026 Gas Utility Financial
Forecast and Cost of Service Study attached to and made a part of the staff report presented to
the City Council;
SECTION 2. The Council hereby approves the transfer of up to 18% of gas utility
gross revenues received during FY 2024 to the general fund in FY 2026;
SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-1 (Residential Gas Service) is hereby amended to read as attached and
Attachment A
NOT YET APPROVED
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2025
(Attachment B);
SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-2 (Residential Master-Metered and Commercial Gas Service) is hereby
amended to read as attached and incorporated. Utility Rate Schedule G-2, as amended, shall
become effective July 1, 2025 (Attachment B);
SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-3 (Large Commercial Gas Service) is hereby amended to read as attached and
incorporated. Utility Rate Schedule G-3, as amended, shall become effective July 1, 2025
(Attachment B);
SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility
Rate Schedule G-10 (Compressed Natural Gas Service Service) is hereby amended to read as
attached and incorporated. Utility Rate Schedule G-10, as amended, shall become effective
July 1, 2025 (Attachment B);
SECTION 7. The City Council finds that revenues derived from the gas rates approved
by this resolution do not exceed the funds required to provide gas service and shall not be used
for any purpose other than providing gas service, and the purposes set forth in Article VII,
Section 2, of the Charter of the City of Palo Alto.
SECTION 8. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor
that are not provided to those not charged, and do not exceed the reasonable costs to the City
of providing the service or product.
SECTION 9. The Council finds that approving the FY 2026 Gas Utility Financial
Forecast does not meet the California Environmental Quality Act’s (CEQA) definition of a
project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5),
because it is an administrative governmental activity which will not cause a direct or indirect
physical change in the environment, and therefore, no environmental assessment is required.
The Council finds that changing gas rates to meet operating expenses, purchase supplies and
materials, meet financial reserve needs and obtain funds for capital improvements necessary to
maintain service 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). After reviewing the staff report and all attachments presented to
/ /
/ /
/ /
Attachment A
NOT YET APPROVED
Council, the Council incorporates these documents herein and finds that sufficient evidence has
been presented setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
Assistant City Attorney City Manager
Director of Utilities
Director of Administrative Services
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-1 Effective 7-1-2025Sheet No G-1-1
dated 117-1-2024 Sheet No G-1-1Effective 11-1-2024
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from City of Palo Alto
Utilities:
1. Separately-metered single-family residential Customers;
2.Separately-metered multi-family residential Customers in multi-family residential
facilities.
B.TERRITORY:
This schedule applies everanywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES:Per Service
Monthly Service Charge: ................................................................................................$ 19.526.93
Tier 1 Rates: Per Therm
Supply Charges:
1. Commodity (Monthly Market- Based) ........................................ $0.10-$4.00
2.Cap and Trade Compliance Charge ............................................ $0.00-
$0.25Pass-through
3. Transportation Charge ................................................................. Pass-
through$0.00-$0.30
4. Carbon Offset Charge .................................................................. $0.00-$0.10
Distribution Charge:....................................................................................... $
1.20930.8229
Tier 2 Rates: (All usage over 100% of Tier 1)
Supply Charges:
1.Commodity (Monthly Market- Based) ........................................ $0.10-$4.00
2.Cap and Trade Compliance Charge ............................................. $0.00-
$0.25Pass-through
3. Transportation Charge ................................................................. Pass-
through$0.00-$0.30
4.Carbon Offset Charge .................................................................. $0.00-$0.10
Attachment B
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-2 Effective 7-1-2025Sheet No G-1-2
dated 117-1-2024 Sheet No G-1-2Effective 11-1-2024
Distribution Charge:............................................................................................. $
2.10431.8792
D.SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount 1 and $0.055 per therm for mitigating the impact of short-term natural
gas market price spikes 2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s
compliance obligations. The Cap and Trade Compliance Charge will changes in
response to changing market conditions, retail sales volumes and the quantity of
allowances required, . The Cap and Trade Compliance Chargeand is a pass-through
charge and itis calculated based on the Cap-and-Trade Pprogram’s quarterly auction
allowance closing prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse
gases produced when Gas is burned. The Carbon Offset Charge will changes in response
to changing market conditions, changing sales volumes and the quantity of offsets
purchased within the Council-approved per therm cap.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
Attachment B
RESIDENTIAL GAS SERVICE
UTILITY RATE SCHEDULE G-1
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-1-3 Effective 7-1-2025Sheet No G-1-3
dated 117-1-2024 Sheet No G-1-3Effective 11-1-2024
The Transportation Charge is a pass-through charge , and it is based on the current PG&E
G-WSL 3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity and, Cap and Trade Compliance, Carbon Offset and Transportation
Charges will fall within the minimum/maximum ranges set forth in Section C. Current
and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon
Offset and Transportation Charges are posted on the City Utilities website.4
2. Seasonal Rate Changes:
The Summer period is effective April 1 to October 31 and the Winter period is effective
from November 1 to March 31. When the billing period includes use in both the Summer
and the Winter periods, the usage will be prorated based on the number of days in each
seasonal period, and the charges based on the applicable rates for each period. For further
discussion of bill calculation and proration, refer to Rule and Regulation 11.
3. Calculation of Usage Tiers
Tier 1 natural gas usage shall beis calculated and billed based upon a level of 23 therms
per 30 day billing period during the Summer period, and 60 therms per 30 day billing period
during the Winter period, based on meter reading days of service, and rounded to the
nearest whole therm. As an example, Tier 1 natural gas usage would beis calculated at
0.767667 therms per day during the Summer period (0.767 therms per day x 30 days = 23
therms) and 2.0 therms per day during the Winter period (2.0 therms per day x 30 days =
60 therms) months,. rounded to the nearest whole therm, based on meter reading days of
service. As an example, for a 30 day bill, the Tier 1 level would be 20 therms during the
Summer period and 60 therms during the Winter period months. For further discussion of
bill calculation and proration, refer to Rule and Regulation 11.
{End}
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.cityofpaloalto.org/files/assets/public/utilities/rates-schedules-for-utilities/residential-utility-rates/monthly-gas-
volumetric-and-service-charges-residential.pdf
Attachment B
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-1 Effective 711-1-20254
dated 117-1-2024 Sheet No G-2-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use less than 250,000 therms per year at one site;
2. Master-metered residential Customers in multi-family residential facilities.
B. TERRITORY:
This schedule applies everanywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge:
For meters with maximum capacity:
1. .................................................................. Up to 220 Standard Cubic Feet per Hour (scfh)
..................................................................................................................................$ 29.06
2. Above 220 scfh butand less than 4,000 scfh ............................................................$ 94.94
3. 4,000 scfh and above ................................................................................$ 417.62$ 156.90
..............................................................................................................................................
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) ......................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ........................................................... $0.00-
$0.25Pass-through
3. Transportation Charge .................................................................................. Pass-
through$0.00-$0.30
4. Carbon Offset Charge ................................................................................... $0.00-$0.10
Distribution Charge: .................................................................................................. $1.26160809
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as
calculated under Section C.
Attachment B
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-2 Effective 711-1-20254
dated 117-1-2024 Sheet No G-2-2
The meter’s maximum capacity used to determine the applicable Monthly Service Charge
for G-2 Gas Service is the installed meter’s City of Palo Alto-approved maximum
capacity in standard cubic feet per hour (scfh), measured at 7 inches of water column or
equivalent to 0.25 pounds per square inch.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
purchase discount 1 and $0.055 per therm for mitigating the impact of short-term natural
gas market price spikes 2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge will changes in response to changing
market conditions, retail sales volumes and the quantity of allowances required,. and is
calculated based on the Cap-and-Trade Program’s quarterly auction allowance closing
prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge will changes in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is a pass-through chargeis based on the current PG&E G-
WSL 3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation
Charges will fall within the minimum/maximum ranges set forth in Section C. Current
and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon
Offset and Transportation Charges are posted on the City Utilities website.4
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.cityofpaloalto.org/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-
Attachment B
RESIDENTIAL MASTER-METERED AND COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-2
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-2-3 Effective 711-1-20254
dated 117-1-2024 Sheet No G-2-3
{End}
charges-commercial.pdf
Attachment B
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-1 Effective 711-1-20254
dated 711-1-2024 Sheet No G-3-1
A. APPLICABILITY:
This schedule applies to the following Customers receiving Gas Service from the City of Palo Alto
Utilities:
1. Commercial Customers who use at least 250,000 therms per year at one site;
2. Customers at City-owned generation facilities including the City’s Natural Gas fueling
station at the Municipal Services Center.
B. TERRITORY:
This schedule applies everyanywhere the City of Palo Alto provides Gas Service.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: $ 1,731.67717.89
Per Therm
Supply Charges:
1. Commodity (Monthly Market Based) .................................................... $0.10-$4.00
2. Cap and Trade Compliance Charges ................................ Pass-through$0.00-$0.25
3. Transportation Charge .......................................................................... Pass-
through$0.00-$0.30
4. Carbon Offset Charge ........................................................................... $0.00-$0.10
Distribution Charge: ............................................................................................................$ 1.0702
D. SPECIAL NOTES:
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill
statement, the bill amount may be broken down into appropriate components as calculated
under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for
delivery at PG&E Citygate, adjusted to account for delivery losses to the Customer’s
Meter. The Commodity Charge also includes adjustments to account for Council-
approved programs implemented to reduce the cost of Gas, including a municipal
Attachment B
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-2 Effective 711-1-20254
dated 711-1-2024 Sheet No G-3-2
purchase discount 1 and $0.055 per therm for mitigating the impact of short-term natural
gas market price spikes 2.
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s
cost of regulatory compliance with the state’s Cap and Trade Program, including the cost
of acquiring compliance instruments sufficient to cover the City’s Gas Utility’s compliance
obligations. The Cap and Trade Compliance Charge will changes in response to changing
market conditions, retail sales volumes and the quantity of allowances required,. and is
calculated based on the Cap-and-Trade Program’s quarterly auction allowance closing
prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge will changes in response to
changing market conditions, changing sales volumes and the quantity of offsets purchased
within the Council-approved per therm cap.
The Transportation Charge is a pass-through chargeis based on the current PG&E G-
WSL 3 (Gas Transportation Service to Wholesale/Retail Customers) rate for Palo Alto,
accounting for delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation
Charges will fall within the minimum/maximum ranges set forth in Section C. Current
and historic per therm rates for the Commodity, Cap and Trade Compliance, Carbon
Offset and Transportation Charges are posted on the City Utilities website.4
2. Request for Service
A qualifying Customer may request service under this schedule for more than one account
or meter if the accounts are located on one site. A site consists of one or more contiguous
parcels of land with no intervening public right-of- ways (e.g. streets).
3. Changing Rate Schedules
Customers may request a rate schedule change at any time to any applicable City of Palo
Alto full-service rate schedule.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.cityofpaloalto.org/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-
charges-commercial.pdf
Attachment B
LARGE COMMERCIAL GAS SERVICE
UTILITY RATE SCHEDULE G-3
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-3-3 Effective 711-1-20254
dated 711-1-2024 Sheet No G-3-3
{End}
Attachment B
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-1 Effective 711-1-20254
dated 117-1-2024 Sheet No. G-10-1
A. APPLICABILITY:
This schedule applies to the sale of Gas to the City-owned compressed natural gas (CNG) fueling
station at the Municipal Service Center in Palo Alto.
B. TERRITORY:
Applies to the City’s CNG fueling station located at the Municipal Service Center in City of Palo Alto.
C. UNBUNDLED RATES: Per Service
Monthly Service Charge: ..........................................................................................$ 115.34106.11
Per Therm
Supply Charges:
Commodity (Monthly Market Based) ................................................................ $0.10-$4.00
Cap and Trade Compliance Charges ............................................. $0.00-$0.25Pass-through
Transportation Charge .................................................................. Pass-through$0.00-$0.30
Carbon Offset Charge ........................................................................................ $0.00-$0.10
Distribution Charge ........................................................................................................$ 0.0190175
D. SPECIAL CONDITIONS
1. Calculation of Cost Components
The actual bill amount is calculated based on the applicable rates in Section C above and adjusted
for any applicable discounts, surcharges and/or Taxes. On a Customer’s bill statement, the bill
amount may be broken down into appropriate components as calculated under Section C.
The Commodity Charge is based on the monthly natural gas Bidweek Price Index for delivery at
PG&E Citygate, adjusted to account for delivery losses to the Customer’s Meter. The
Commodity Charge also includes adjustments to account for Council-approved programs
implemented to reduce the cost of Gas, including a municipal purchase discount1 and $0.055 per
therm for mitigating the impact of short-term natural gas market price spikes 2.
1 Adopted via Resolution 9451, on September 15, 2014.
2 Adopted via Resolution 10187 on August 19, 2024.
Attachment B
COMPRESSED NATURAL GAS SERVICE
UTILITY RATE SCHEDULE G-10
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Supersedes Sheet No G-10-2 Effective 711-1-20254
dated 117-1-2024 Sheet No. G-10-2
The Cap and Trade Compliance Charge is a pass-through charge that reflects the City’s cost of
regulatory compliance with the state’s Cap and Trade Program, including the cost of acquiring
compliance instruments sufficient to cover the City’s Gas Utility’s compliance obligations. The
Cap and Trade Compliance Charge will changes in response to changing market conditions, retail
sales volumes and the quantity of allowances required,. and is calculated based on the Cap-and-
Trade Program’s quarterly auction allowance closing prices.
The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases
produced when Gas is burned. The Carbon Offset Charge will changes in response to changing
market conditions, changing sales volumes and the quantity of offsets purchased within the
Council-approved per therm cap.
The Transportation Charge is a pass-through chargeis based on the current PG&E G-WSL 3 (Gas
Transportation Service to Wholesale/Retail Customers) rate for Palo Alto, accounting for
delivery losses to the Customer’s Meter.
The Commodity, Cap and Trade Compliance, and Carbon Offset and Transportation Charges
will fall within the minimum/maximum ranges set forth in Section C. Current and historic per
therm rates for the Commodity, Cap and Trade Compliance, Carbon Offset and Transportation
Charges are posted on the City Utilities website.4
{End}
3 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
4 Monthly gas and commodity and volumetric rates are available here, or by visiting
https://www.cityofpaloalto.org/files/assets/public/utilities/business/business-rates/monthly-gas-volumetric-and-service-
charges-commercial.pdf
Attachment B
Attachment C
6
7
5
6
Attachment C
6
7
5
6
Gas Utility Capital Improvement Program (CIP) Financial Details
Attachment D
GAS UTILITY RESERVES MANAGEMENT PRACTICES
The following reserves management practices shall be used when developing the Gas Utility
Financial Plan:
Section 1. Definitions
a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal
years covered by the Financial Plan. For example, if the Financial Plan delivered in
conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015
to FY 2019 would be the Financial Planning Period.
b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers
to the Utility’s Unrestricted Net Assets.
c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets
as the difference between its assets and liabilities.
d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital
assets (net of related debt) or restricted for debt service or other restricted purposes.
Section 2. Supply Fund Reserves
The Gas Utility’s Supply Fund Balance is reserved for the following purposes:
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
Section 3. Distribution Fund Reserves
a) For existing contracts, as described in Section 4 (Reserve for Commitments)
b) For operating and capital budgets re-appropriated from previous years, as described in
Section 5 (Reserve for Re-appropriations)
c) For cash flow management and contingencies related to the Gas Utility’s Capital
Improvement Program (CIP), as described in Section 6 (CIP Reserve)
d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve)
e) For operating contingencies, as described in Section 8 (Operations Reserve)
f) For tracking unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility under the State’s Cap and
Trade Program, as described in Section 11 (Cap and Trade Program Reserve)
g) Any funds not included in the other reserves will be considered Unassigned Reserves and
shall be returned to ratepayers or assigned a specific purpose as described in Section 9
(Unassigned Reserves)
Attachment D
Section 4. Reserve for Commitments
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Commitments will be set to an amount equal to the total remaining spending authority for
all contracts in force for the Wastewater Collection Utility at that time.
Section 5. Reserve for Reappropriations
At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for
Reappropriations will be set to an amount equal to the amount of all remaining capital and
non-capital budgets, if any, that will be re-appropriated to the following fiscal year for each
fund in accordance with Palo Alto Municipal Code Section 2.28.090.
Section 6. CIP Reserve
The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for
capital contingencies. Staff will manage the CIP Reserve according to the following practices:
a) The following guideline levels are set forth for the CIP Reserve 1. These guideline levels are
calculated for each fiscal year of the Financial Planning Period and approved by Council
resolution.
a)
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve for
Commitments as a result of a change in contractual commitments related to CIP projects.
Any other additions to or withdrawals from the CIP reserve require Council action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve
for the purpose of determining compliance with the CIP Reserve minimum guideline
level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve reaching
its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is
below its minimum level at the end of FY 2017, staff must present a plan by June 30,
1 The guideline levels were corrected to match the Council-approved language updated from the
FY 2021 Financial Plan.
2 Each month is calculated based upon 1/12 of the annual budget.
3 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual
average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to
derive the annual average would be FY 2022 through FY 2025 etc.
of budgeted CIP expenses 3
Attachment D
2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff
may present, and the Council may adopt, an alternative plan that takes longer than
one year to replenish the reserve, or that does so in a shorter period of time.
d) Maximum Level: If, at any time, the CIP Reserve reaches its maximum level, no funds may
be added to this reserve. If there are funds in this reserve in excess of the maximum level
staff must propose to transfer these funds to another reserve or return them to
ratepayers in the next Financial Plan. Staff may also seek Council approval to hold funds
in this reserve in excess of the maximum level, if they are held for a specific future purpose
related to the CIP.
Section 7. Rate Stabilization Reserve
The Rate Stabilization Reserve is used to manage the trajectory of future Funds may be added
to the Rate Stabilization Reserve by action of the City Council and held to manage the
trajectory of future year rate increases. Withdrawal of funds from the Rate Stabilization
Reserve requires Council action. If there are funds in the Rate Stabilization Reserve at the end
of any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of
all funds from this Reserve by the end of the Financial Planning Period.
Section 8. Operations Reserve
The Operations Reserve is used to manage normal variations in costs and as a reserve for
contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves
described in Section 4-Section 7 above will be included in the Operations Reserve unless this
reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage
the Operations Reserve according to the following practices:
a) The following guideline levels are set forth for the Operations Reserve. These guideline
levels are calculated for each fiscal year of the Financial Planning Period based on the
levels of Operations and Maintenance (O&M) and commodity expense forecasted for that
year in the Financial Plan.
b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Operations
Reserve are lower than the minimum level set forth above, staff shall present a plan to
the City Council to replenish the reserve. The plan shall be delivered within six months of
the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its
minimum level by the end of the following fiscal year. For example, if the Operations
Reserve is below its minimum level at the end of FY 2014, staff must present a plan by
December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In
addition, staff may present, and the Council may adopt, an alternative plan that takes
longer than one year to replenish the reserve.
Attachment D
c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower
than the target level, any Financial Plan created for the Gas Utility shall be designed to
return the Operations Reserve to its target level by the end of the forecast period.
d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no
funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance
shall be automatically included in the Unassigned Reserve described in Section 9, below.
Section 9. Unassigned Reserve
If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s
Fund Balance will be held in the Unassigned Reserve. If there are any funds in the Unassigned
Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council
must include a plan to assign them to a specific purpose or return them to the Gas Utility
ratepayers by the end of the first fiscal year of the next Financial Planning Period. For
example, if there were funds in the Unassigned Reserves at the end of FY 2015, and the next
Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan
to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may
present an alternative plan that retains these funds or returns them over a longer period of
time.
Section 10. Intra-Utility Transfers Between Supply and Distribution Funds
The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas
Distribution Fund. At the end of each fiscal year staff is authorized to transfer funds between
the Gas Supply Fund and Gas Distribution Fund if consistent with the purposes of the two
reserves involved in the transfer and in order to balance gas utility reserves to avoid negative
balances. For example, Gas Distribution revenues are needed to pay for certain supply-
related costs such as administration of the Gas Supply Fund. Such transfers shall be included
in the ordinance closing the budget for the fiscal year.
Section 11. Cap and Trade Program Reserve
This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely
allocated by the California Air Resources Board to the gas utility, under the State’s Cap and
Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the
Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy),
adopted by Council Resolution 9487 in January 2015. At the end of each fiscal year, the Cap
and Trade Program Reserve will be adjusted by the net of revenues and expenses associated
with the Cap and Trade program.
ATTACHMENT E
COMMUNICATIONS PLAN AND OUTREACH EX AMPLES
The fiscal year (FY) 2026 gas utility communications strategy addresses cost drivers for rate increases
including the need to rebuild financial reserves and ongoing capital investment in the natural gas
distribution system. Financial reserves need to be replenished following a drawdown during the
pandemic to keep customer rate changes at a minimal level. Additionally, the City used financial reserves
to protect customers from surging gas prices in the winter of 2022-2023. Maintaining healthy financial
reserves also ensures that the City of Palo Alto Utilities (CPAU) can continue to invest in capital
improvement of the natural gas distribution system for safe and reliable service delivery.
CPAU continues to explore cost-containment measures for each utility fund, consistent with the Utilities
Strategic Plan. CPAU was recently awarded a $16.5 million grant by the U.S. Department of
Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) which was intended to
provide financial assistance for capital-related work that is additional to the utility’s already planned
capital work over the next five-year period. CPAU is awaiting an update from the federal administration
about the ultimate issuance of this grant.
CPAU purchases gas as a commodity on the market, thus monthly gas rates can fluctuate due to external
factors. Staff post the monthly rates online at www.cityofpaloalto.org/RatesOverview and provide
updates on the rate setting process so members of the public can be informed and get involved in the
public process. CPAU promotes gas use efficiency year-round, but most heavily during winter months to
impact heating activities. Messaging emphasizes the importance of saving energy to keep utility costs
low even if gas prices are high or utility rates are increasing. Programs such as advisor services for energy
efficiency and electrification offer residents assistance for home upgrades. CPAU provides free
consulting services and rebates for commercial energy efficiency upgrades. Throughout the year, CPAU
hosts free educational workshops to help residents and businesses better understand energy usage and
learn ways to improve efficiency to keep utility costs low. The MyCPAU online account management
portal provides customers with direct access and more information about utility account and
consumption data.
CPAU communicates about safety for all utility services year-round including the need to call USA (811)
before digging to check for underground utility lines. Staff also emphasize the importance of contacting
CPAU to check for potential sewer and gas line cross-bores prior to clearing a sewer line. Every year,
CPAU publishes a gas safety awareness brochure and mails it to all customers in Palo Alto as well as other
stakeholders. Staff talk with business customers at special facilities meetings and attend neighborhood
safety and emergency preparedness fairs. While print materials and webpages still feature prominently,
CPAU is increasing use of other outreach channels such as email newsletters, social media and online
videos. The Gas Safety Public Awareness Plan contains saved copies of all outreach materials and activity
logs. Additional CPAU communication methods include the utilities webpages, utility bill inserts,
messaging on bills and envelopes, informational fliers and brochures, email newsletters, social media,
print and digital ads in local publications, and participation in community outreach events.
ATTACHMENT E
Natural Gas Cost of Service and
Rate Study
City of Palo Alto
P R E P A R E D B Y E E S C O N S U L T I N G
February 202 5
Attachment F
16701 NE 80th Street Suite 102 Redmond, WA 98052 425-889-2700 Fax 866-611-3791 www.eesconsulting.com
G e o r g i a T e x a s A l a b a m a N e w H a m p s h i r e W i s c o n s i n M a i n e W a s h i n g t o n C a l i f o r n i a
Amber Gschwend, Director
amber.gschwend@gdsassociates.com
direct 425-655-1042
cell 360-319-7946
February 2025
Lisa Bilir
Senior Resource Planner
City of Palo Alto
250 Hamilton Avenue
Palo Alto, CA 94301
SUBJECT: Natural Gas Cost of Service and Rate Study
Dear Lisa:
Attached please find the Natural Gas Cost of Service and Rate Study report for the City of Palo Alto (City)
prepared by EES Consulting (EES), a GDS Associates company.
We based the conclusions and recommendations contained within this report upon industry practice and
accepted rate setting principles. The assumptions are consistent with the financial and metering data
provided for revenue requirement, customer, and system data and costs.
EES developed the study with mutual aid of the City’s staff and appreciate the internal effort to refine the
study. The findings, conclusions and recommendations of this report supply the basis for the development
of fair and equitable rates for the City.
Very truly yours,
Amber Gschwend
Director, EES Consulting
amber.gschwend@gdsassociates.com
Russ Schneider
Senior Project Manager, EES Consulting
russ.schneider@gdsassociates.com
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING i
TABLE OF CONTENTS
1 EXECUTIVE SUMMARY ................................................................................................... 1
1.1 System Description ............................................................................................................................................. 1
1.2 Rate Study Overview .......................................................................................................................................... 3
1.2.1 Revenue Requirement ................................................................................................................ 3
1.2.2 Cost of Service Analysis ............................................................................................................. 4
1.2.3 Rate Design Recommendations ................................................................................................ 5
1.2.4 Rate Change Recommendations ............................................................................................... 8
2 REVENUE REQUIREMENT DEVELOPMENT ................................................................... 9
2.1 Overview of the City’s Revenue Requirement Methodology ............................................................. 9
2.2 Supply Costs .......................................................................................................................................................... 9
2.3 Distribution Costs ............................................................................................................................................. 10
2.4 Debt Service and Rate-Funded Capital Improvement Program (CIP) .......................................... 10
2.5 General Fund Transfer .................................................................................................................................... 11
2.6 Miscellaneous/Other Revenues .................................................................................................................. 11
2.7 Transfers to/from Reserves ........................................................................................................................... 11
2.8 Summary of Revenue Requirement........................................................................................................... 11
3 COST OF SERVICE ANALYSIS ....................................................................................... 13
3.1 COSA Definition and General Principles .................................................................................................. 13
3.2 City Natural GAs Distribution COSA Methodology ............................................................................. 14
3.2.1 Functionalization ..................................................................................................................... 14
3.2.2 Classification and Allocation of Costs .................................................................................... 14
3.3 Average & Excess (A&E) ................................................................................................................................ 19
3.3.1 Revised Average & Excess Calculation ................................................................................... 20
3.4 Customer Classes of Service ......................................................................................................................... 21
3.5 Cost of Service Results ................................................................................................................................... 21
4 RATE DESIGN ................................................................................................................ 25
4.1 Recommended Rate Design: Distribution ............................................................................................... 25
4.1.1 Residential (G1) ........................................................................................................................ 25
4.1.2 Small Commercial and Residential Master-Metered and (G2) ............................................. 28
4.1.3 Large Commercial (G3) ............................................................................................................ 30
4.2 Supply Charges ................................................................................................................................................. 31
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 1
1 Executive Summary
The City of Palo Alto (City) retained EES Consulting (EES), a GDS Associates company, to perform a natural
gas cost of service analysis (COSA) and rate study for Fiscal Year 2025-2026 (FY 2025-2026)1 as part of its
ongoing efforts to maintain fiscally prudent, fair, cost-based rates for its natural gas customers. The
natural gas COSA is primarily concerned with the development of distribution rates.
In addition to the distribution rates that are the subject of this Study, the City charges four additional rates
to customers that pass on costs that are outside of the immediate control of the City, such as the cost of
purchasing gas and transporting it to the City’s distribution system. These four rates are: 1) the gas
commodity rate, which represents the cost of buying gas in the markets, 2) the gas transportation rate,
which represents the cost of transporting purchased gas to Palo Alto, 3) the Cap and Trade compliance
rate, which represents the cost of mandated participation in the State’s cap and trade program, and 4)
the carbon offset rate, which represents the cost of buying offsets for the City’s Carbon Neutral Gas
Portfolio. These four charges are discussed at the end of this Study.
The starting point for the current study was the COSA that EES performed for FY 2019-2020 (COSA 2020).
The City updated that COSA model for FY 2020-2021 (COSA 2021), with some assistance by EES. Since
then, the City has implemented distribution rate adjustments by uniformly adjusting distribution rates
using the percent change in distribution revenue requirement; thus, distribution rates since 2021 have
reflected the COSA 2020 analysis framework.
This Study is a comprehensive update to the 2020 COSA. All Study assumptions and inputs have been
updated and new rate designs incorporated into the recommendations. EES also modernized and
streamlined the COSA model to facilitate future updates.
EES worked closely with the City’s technical staff and management to refine data inputs for gas sales and
updated expenses, and assets. EES had no issues obtaining appropriate data responses or clarification
when necessary and commends the transparency of the process and the capability of internal resources.
1.1 SYSTEM DESCRIPTION
The City’s gas utility serves approximately 23,500 customer accounts over an area of approximately 26
square miles. The gas utility is responsible for the operations and maintenance of the distribution system,
and it purchases all of its gas from outside suppliers. Total gas consumption in the City forecasted for FY
2025-2026 is 25.8 million therms. EES expects sales to continue near their current weather-adjusted level
of 25 to 26 million therms per year and near the current volume of services. Table 1-1 shows the number
of services and annual gas use for each rate class.
1 July 2025 through June 2026.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 2
TABLE 1-1: NUMBER OF SERVICES UNDER CURRENT RATE SCHEDULES AND
FORECASTED ANNUAL USE IN FY 2025-2026
Rate Schedule Services Annual Use, therms
G1 Residential 21,255 9,762,524
G2 Residential Master Metered and Commercial 2,193 11,506,051
G3 Large Commercial 30 4,510,914
Total 23,477 25,779,489
Gas utility rate schedules consist of a fixed monthly service charge and volumetric rates. The Monthly
Service Charge ($/meter/month) and Distribution Charges ($/therm) vary by rate class. Volumetric
charges are used for both commodity purchases and recovery of variable distribution costs.
Table 1-2 summarizes the rate classes and current rate design for the distribution portion of the rate
schedule. It does not include volumetric supply charges: Commodity Charge (Monthly Market Based), Cap
and Trade Compliance Charge, Transportation Charge and Carbon Offset Charge.
TABLE 1-2: CURRENT DISTRIBUTION RATE DESIGN
Utility Rate Schedule Description Current Rate Design
G1: Residential Separately metered:
Single-family residential customers
Multi-family residential customers
2-Tier Volumetric Charge with seasonal
lower-cost tier 1 quantities
Tier 1 Summer:1 20 therms/30-day-billing
Tier 1 Winter: 60 therms/30-day-billing
G2: Residential Master-
Metered and
Commercial (“Small
Commercial”)
Commercial customers who use less
than 250,000 therms per year at one
site, and master-metered residential
customers in multifamily residential
Volumetric Charge, $/therm
G3: Large Commercial
least 250,000 therms per year at one
2
Volumetric Charge, $/therm
1. Summer rates effective April 1 through October 31. Winter rates effective November 1 through March 31.
2 In addition to these standard rate classes, CPAU provides CNG service under the G10 rate schedule. The CNG
customer receives service using specific facilities. The service provided has not changed since the previous cost of
service study, and the cost to serve the G10 customer has increased at the same rate as for the distribution expenses
overall. For this reason, the G10 rate should be adjusted by the average system increases. For FY 2025-2026, the G10
rate should be increased 8.7%.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 3
1.2 RATE STUDY OVERVIEW
The purpose of this report is to discuss the data inputs, assumptions and results that were part of
developing the rate study. A comprehensive rate study generally consists of three separate, yet
interrelated analyses. These three analyses include a revenue requirement, COSA, and rate design
examination.
1. Revenue Requirement Analysis: This analysis examines the various sources and uses of funds for the
utility, and it determines the overall revenue required to operate the utility.
2. Cost-of-Service Analysis (COSA): COSA is used to determine the fair allocation of the total revenue
requirement to the various customer classes of service (e.g., residential, small commercial, large
commercial). This analysis provides a determination of the level of revenue responsibility of each class
of service and the adjustments from current revenues required to meet the cost of service.
3. Rate Design Analysis: The third analysis involves evaluating the rate design options available and
designing rate schedules that can be applied to each rate class to collect revenues to cover the cost
to serve customers in that class.
1.2.1 Revenue Requirement
The first step in completing a rate study is to develop the revenue required from rates (revenue
requirement). A revenue requirement analysis compares the overall revenues of the utility to its expenses
and helps determine the need for an overall adjustment to rate levels. Over the course of the study period,
the City prepared several financial analyses that included a forecast of FY 2025-2026 sales, revenues and
expenses. The City has an in-depth accounting and data system that keeps track of ongoing and budgeted
or approved expenditures. EES based the forecasts on projected FY 2026 expenses and sales estimates for
the natural gas utility. For this COSA, EES maintained a cash-basis method for determining the City’s
revenue requirement based on the City’s financial forecast.
FY 2025-2026 natural gas commodity costs are included in City’s financial plan. However, these costs are
adjusted monthly to pass through actual commodity rates charged to the City by its wholesaler. Therefore,
commodity charges are not set based on the COSA; the COSA focuses narrowly on setting appropriate
distribution charges for the year.
Table 1-3 summarizes the FY 2025-2026 distribution revenue requirement totaling $41.3 million. At
current rates, there is a revenue shortfall of $3.3 million. A rate increase of 8.7% to the distribution rate
would collect the required revenue to meet distribution costs.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 4
TABLE 1-3: DISTRIBUTION REVENUE REQUIREMENT: FY 2025-2026 Revenue Requirement
Distribution O&M $9,797,408
Customer Accounts and Services $3,208,008
Administration and General $5,002,927
Debt Service & CIP from Rates $8,339,643
General Fund Transfer $9,734,580
Total Expenses $36,082,566
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Revenues Based on Rates Currently in Effect $37,957,863
Total Required Rate Revenue Increase (Decrease) 8.7%
1.2.2 Cost of Service Analysis
Cost-of-service is important for the fair allocation of the revenue requirement to the various customer
classes of service. The revenue requirement shown in Table 1-3 for the City was functionalized, classified
and allocated.
Functionalization is the attribution of each cost line-item to production (commodity), transportation,
distribution, or shared services. This COSA evaluates only Distribution costs and distribution-related
overhead.
Classification is the determination of whether the costs associated with a functionalized line item are
most appropriately allocated based on energy use (therms), demand (maximum system capacity), or
customer (simply having a service).
Allocation is the process of using the classification for each functionalized line item to assign costs to
each customer class. For example, a cost item classified as “energy use” might be allocated based on
annual therm use. This means that the line-item cost is directly correlated to the quantity of energy
used by each customer class annually. This process is described in more detail in the section titled
“Cost of Service Analysis.”
Ultimately, the COSA process requires analysis of how each customer class contributes to the expenses
incurred by the utility to provide service. Table 1-4 shows, by customer class, the revenue requirement
and revenue change needed for FY 2025-2026.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 5
TABLE 1-4: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2025-
Revenue
FY 2025-2026
Deficiency/
Revenue
G1 – Residential $16,311,063 $18,853,368 $2,542,305 15.59%
$16,565,086 $16,568,614 $3,527 0.02%
$5,081,713 $5,846,360 $764,647 15.05%
Total $37,957,863 $41,268,342 $3,310,479 8.7%
1.2.3 Rate Design Recommendations
The final step in the rate study process is to design rates for each class of service. In California, local
governments are subject to Article XIII C of the California Constitution, as amended by Proposition 26. As
a result, the City sets rates based on COSA results. The goal of rate design is to create rates that recover
costs from customers within each class according to the utility’s respective cost of providing service. The
basis for each rate design recommendation is provided in this section followed by the recommended
rates.
All rate classes are charged a monthly service charge and volumetric charge to recover distribution costs.
EES is not recommending changes to this basic rate design structure, except for a refinement in the
development of the Monthly Service Charge for G2 based on additional analysis of that class’s usage and
costs – Section 1.2.3.2, Commercial provides more details on this change.
1.2.3.1 Residential
The G1 distribution rates consist of a monthly service charge and volumetric tier rates: the Tier 1 rate
applies to usage up to the baseline quantity and the Tier 2 rate applies to all usage above the baseline.
EES recommends no change to the G1 rate structure because it effectively recovers energy and demand
or capacity costs incurred by the class.
While the tier rates do not change between seasons, the baseline quantity above which Tier 2 rates apply
does change and is higher in winter than in the summer because natural gas heat is more prevalent in the
winter and causes higher consumption.3 This ensures that those customers contributing to higher
seasonal demand are paying appropriately for their share of the demand-related cost in a tiered rate. EES
evaluated the G1 tier rates using the Average and Excess (A&E) method (discussed in more detail in
Section 3.4) and proposes a modest adjustment to the summer baseline from 20 to 23 therms per thirty-
day billing period.
3 Usage above the Tier 1 baseline quantity is charged Tier 2 rate. The current quantity is 20 therms/30-day-billing in
summer and 60 therms/30-day-billing in winter.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 6
Table 1-5 summarizes the costs to be recovered in each rate component for G1.
TABLE 1-5: G1 RATES AND COST RECOVERY
Rate Component Recovers The Following Costs:
Monthly Service Charge Customer-related costs such as customer service, billing, and overhead adders
Tier 1 Volumetric Rate Energy-related costs plus 54% of demand-related distribution unit costs*
Tier 2 Volumetric Rate Energy-related costs plus 46% of demand-related distribution unit costs*
*See calculations in Section 4.1.1. Residential (G1) Rate Design, Table 4-5.
1.2.3.2 Commercial
EES recommends no change to the volumetric charge structure for the two commercial classes (G2 and
G3). Within the commercial rate class, there are inherent size differences, in terms of physical space and
energy use, related to the types of business.
It is not appropriate to charge larger-usage businesses more through a volumetric tiered rate structure
because the larger sized customers have sufficient minimum monthly consumption to account for
variances in distribution costs on a per therm basis. For example, when comparing the minimum level of
monthly consumption to the annual consumption, all commercial classes have minimum consumption
over 59%, whereas residential minimum consumption by the same measure is only 36%. Therefore, tiered
volumetric Distribution Charges for commercial classes are not necessary, but do have a place for the
residential class. There is not a sufficient under-recovery of demand-related distribution costs from
minimum volumes to warrant a tiered rate for commercial classes.
This Study updated input, assumptions and calculations of fixed charges. The resulting changes proposed
to the Monthly Service Charge for G2 are based on a refinement of cost functionalization developed in
the study. This methodology and assumptions are detailed in Section 3. In addition to the methodology
review, EES performed additional analysis on G2 meter capacity related costs by comparing the average
consumption for various meter capacities. Fixed costs are generally higher for customers with larger
capacity service because of the larger and more expensive equipment required to provide higher volume
service.
Based on the findings of this analysis, EES determined customer-related costs for three categories defined
by meter capacity. Table 1-6 illustrates the recommended rate for the G2 class and the number of services
within each G2 subgroup. With the recommended rates, G2 customers would be charged a Monthly
Service Charge based on maximum meter capacity; customers with lower-capacity meters would pay a
lower Monthly Service Charge than those with higher capacity meters. For example, a customer with a
meter capacity of 200 standard cubic feet per hour (scfh) would pay the lowest Monthly Service Charge,
at $29.06.
For G3, the meter capacity of services is much more uniform within the rate class. Also, importantly, the
meter costs associated with G3 consumption levels are similar.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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TABLE 1-6: G2 MONTHLY SERVICE CHARGES: FY 2025-2026
CPAU Approved Maximum Meter Capacity (scfh 4
Number
of
Monthly Service
Charge
Monthly Service
Charge
1,134 $156.90 $29.06
942 $156.90 $94.94
116 $156.90 $417.62
While Table 1-6 shows the lower Monthly Service Charge for smaller G2 customers (defined as customers
with meter capacity up to 220 scfh), Table 1-7 illustrates that this same group of customers should also
receive an overall rate decrease. The column “Revenue Requirement” in Table 1-7 presents the total
revenue requirement amounts (including fixed and variable costs) that correspond to the recommended
Monthly Service Charges shown in Table 1-6 above. The recommended rates for G2 are provided in
Section 1.2.4.
TABLE 1-7: G2 REVENUES AND REVENUE REQUIREMENT: FY 2025-2026
CPAU Approved Maximum
2026 Revenues
at Current
Monthly Service
Revenue
Projected
FY 2026
Revenue
Change
$2,948,824 $1,713,540 ($1,235,283) -41.9%
Above 220 but Below 4,000 $7,685,399 $7,987,841 $302,442 3.9%
4,000 and Above $5,930,863 $6,867,232 $936,369 15.8%
Total G2 $16,565,086 $16,568,614 $3,527 0.0%
4 All meters have a manufacturer-rated capacity and an approved for engineering maximum capacity. The CPAU
approved capacity is typically slightly lower than the manufacturer maximum capacity due to connected
characteristics and other variable conditions. CPAU approved maximum meter capacities in this staff report are all
at an assumed pressure of 7 inches of water column (equivalent to 0.25 pounds per square inch).
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 8
1.2.4 Rate Change Recommendations
Table 1-8 provides a comparison of current rates and recommended rates for FY 2026, including the newly
developed G2 Monthly Service Charge by meter capacity.
TABLE 1-8: CURRENT AND RECOMMENDED RATES
Current FY 2025-2026 Percent
$16.93 $19.52 $2.59 15.3%
For Winter: first 60 therms/30-day-billing
For Summer: first 20 therms/30-day-billing
(current); first 23 therms/30-day-billing
$0.8229 $1.2274 $0.4045 49.2%
For Winter: over 60 therms/30-day-billing
For Summer: over 20 therms/30-day-billing
(current); over 23 therms/30-day-billing
$2.1043 $1.8972 -$0.2071 -9.8%
$156.90 $78.00 -$78.90 -50.3%
$1.0809 $1.2616 $0.1807 16.7%
≤
$156.90 $29.06 -$127.84 -81.5%
$1.0809 $1.2616 $0.1807 16.7%
$156.90 $94.94 -$61.96 -39.5%
$1.0809 $1.2616 $0.1807 16.7%
≥
$156.90 $417.62 $260.72 166.2%
$1.0809 $1.2616 $0.1807 16.7%
$717.89 $1,713.67 $995.78 138.7%
$1.0702 $1.1616 $0.0914 8.5%
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 9
2 Revenue Requirement Development
This section presents the development of the natural gas revenue requirement in the COSA study. Simply
stated, a revenue requirement analysis compares the overall revenues of the utility to its expenses and
determines the overall adjustment to rate levels required.
2.1 OVERVIEW OF THE CITY’S REVENUE REQUIREMENT METHODOLOGY
The City utilizes the cash basis approach for determining its revenue requirement. The revenue
requirement for the City’s natural gas utility includes the elements shown in Table 2-1.
TABLE 2-1: ELEMENTS OF A CASH BASIS REVENUE REQUIREMENT
+ Operating Expenses
Natural Gas Supply Expense
Distribution O&M Expense
Customer Accounting Expenses
Administrative and General Expense
+ Capital Improvements Funded from Rates
+ General Fund Transfer
= Total Revenue Requirement
- Transfers from Reserves
- Miscellaneous Revenue Sources
= Net Revenues Required From Rates (or Net Revenue Requirement)
In this basic analytical framework, the first step in determining the revenue requirement is to select a
period over which to review revenues and expenses. This COSA uses a future fiscal year test period to
correspond with the City’s budget year. The revenue requirement in this COSA reflects the City-provided
financial forecast (budget) for FY 2025-2026.
The next step in the analysis was to translate the City-budgeted costs into the system of accounts used by
a natural gas utility.
2.2 SUPPLY COSTS
While this Study does not include an analysis for gas supply costs, a summary of these costs is provided
here for reference. As with most natural gas utilities, a major expense associated with operating the utility
is the cost of natural gas supply. The City is projecting FY 2025-2026 gas supply costs at $25.8 million or
38 percent of the total FY 2025-2026 revenue requirement. Supply costs are charged to customers via four
pass-through rate components. The following rate components are adjusted monthly to reflect actual
costs:
1. Gas commodity: This represents the cost of buying gas in the market.
2. Gas transportation: This reflects the cost of transporting purchased gas from the delivery points
to Palo Alto.
3. Cap and Trade compliance: This covers the cost of mandated participation in the State’s cap and
trade program.
4. Carbon offset charge: This accounts for the cost of buying offsets needed to comply with the City’s
Carbon Neutral Gas Portfolio Program.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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While the cost of natural gas supply is included in the COSA, it is treated as a separate category as the cost
of natural gas supply is collected through separate rate components. A description of these separate rates
is provided in Section 4.2.
2.3 DISTRIBUTION COSTS
Total FY 2025-2026 revenue requirement for distribution is projected to be $41.3 million. Distribution
operating expenses include the following (other expenses are discussed in Sections 2.4 through 2.7):
Physical system costs of $9.8 million. These costs include the operations and maintenance of
distribution system infrastructure such as distribution mains, regulators and meters.
Customer service-related costs of $3.2 million. These costs include meter reading, billing, key account
representatives and general customer service.
Administrative and general costs of $5.0 million. These costs include functions like accounting,
purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well
as Utilities Department administrative overhead, insurance, rent, and transfers to city non-enterprise
funds for items such as utility building improvements and to other enterprise funds for items such as
the gas utility’s share of Geographic Information System project costs.
The customer service category includes $0.5 million in expenses for energy efficiency, conservation
(demand side management), and low-income assistance programs. These expenses are incurred by the
gas enterprise as part of a program established by the City pursuant to California Public Utilities Code
Section 898. By virtue of this program, gas customers are exempted from a state surcharge that would
otherwise be collected on utility bills pursuant to Public Utilities Code Section 890. The City’s energy
efficiency and demand-side management programs reduce customer gas demand, and are designed to
reduce the need for capital expenditures that would otherwise be needed to expand the capacity of the
gas distribution system.
2.4 DEBT SERVICE AND RATE-FUNDED CAPITAL IMPROVEMENT PROGRAM (CIP)
The City must cover its capital improvement projects (CIP) through either debt or cash from rates or
through external sources such as grants or loans. For FY 2025-2026 the City has debt service payments of
$0.8 million for past borrowings to fund CIP, specifically the 2011 Series A Utility Revenue Refunding
Bonds. This bond issuance was to refinance the $18 million principal remaining on the Utility Revenue
Bonds, 2002 Series A issued for the Gas and Water Utilities to finance various improvements to the
distribution systems. The majority of CIP is funded from rate revenues. For FY 2026, the budgeted CIP is
$7.5 million. This amount is in effect, partially offset by contributions made by new customers in the form
of connection fees. The $0.7 million in connection fees is included in other revenues, which is further
discussed below. Total FY 2025-2026 debt service and rate-funded CIP is $8.3 million before customer
contributions.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 11
2.5 GENERAL FUND TRANSFER
The City calculates the equity transfer from its natural gas utility based on a methodology approved by
voters in November 2022.5 The General Fund Transfer is estimated to be $9.7 million in FY 2025-2026.
2.6 MISCELLANEOUS/OTHER REVENUES
The City receives additional operating and non-operating revenues and contributions. These come in the
form of interest revenues, connection fees and other miscellaneous service revenues. Interest revenues
are interest earned on the utility’s reserves. Connection fees are contributions paid by customers to cover
the cost of new facilities built on their behalf. For FY 2025-2026, the projection for these revenues and
contributions is $0.7 million.6 These miscellaneous/other revenues are separate from fixed and volumetric
charges for natural gas service and are therefore considered an offset to the total revenue required from
retail rates.
2.7 TRANSFERS TO/FROM RESERVES
In its FY 2025-2026 natural gas financial forecast, the City is anticipating that $5.9 million of rate revenues
will need to be added to the reserves in FY 2025-2026 to restore both the operating and CIP reserves. The
operating reserve balance is adjusted to meet future debt service requirements as projected from the
City’s financial plan. Additionally, the City plans to make contributions to the CIP reserve fund to balance
year-to-year fluctuations in CIP expenditures. The use of the reserve fund allows the City to have more
stable and gradual rate increases over time.
2.8 SUMMARY OF REVENUE REQUIREMENT
The City’s Distribution revenue requirement for the FY 2025-2026 test period is summarized in Table 2-2.
A rate increase of 8.7% is required to meet projected FY 2025-2026 costs.
5 In November 2022, voters approved Measure L, amending the Municipal Code, Section 2.28.185, “Natural Gas
Utility Transfer” states: “Each fiscal year the City Council may transfer from the natural gas utility to the general fund
an amount equal to 18% of the gross revenues of the gas utility received during the fiscal year two fiscal years before
the fiscal year of the transfer. At its discretion, the City Council may decide to transfer a lesser amount. The projected
cost of the transfer shall be included in the City’s retail natural gas rates as part of the cost of providing gas service.”
6 Misc. Revenues also includes customer discounts and uncollectible bills. These items reduce the amount of funds
needed to be collected from retail gas rate revenues because they are recovered from non-rate revenues including
interest income from investments. Therefore, the total Misc. Revenues is the total non-rate revenue net of these
expenses.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 12
TABLE 2-2: SUMMARY OF NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT: FY 2025-2026 Revenue Requirement
Distribution O&M $9,797,408
Total Expenses $36,082,566
Other Revenues -$689,111
Total Revenue Required from Rates (Revenue Requirement) $41,268,342
Revenues Based on Rates Currently in Effect $37,957,863
Additional Rate Revenue Needed without Gas Supply $3,310,479
Total Required Rate Revenue Increase (Decrease) 8.7%
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 13
3 Cost of Service Analysis
The objective of the cost-of-service analysis (COSA) is to allocate the costs in the revenue requirement to
each customer class of service to determine the cost to serve those customers. An essential principle of
cost allocation is the concept of cost-causation. Cost-causation evaluates which customer or group of
customers causes the utility to incur certain costs by linking system facility investments and the operating
costs to serve certain facilities to the way customers use those facilities and services. This section of the
report discusses the general approach used to allocate the City’s costs and presents a summary of the
results.
3.1 COSA DEFINITION AND GENERAL PRINCIPLES
A COSA study allocates the costs of providing utility service to the various customer classes served by the
utility based upon the cost-causal relationship associated with specific expense items. This approach is
taken to develop a fair and equitable designation of costs to each class of service. The COSA allocates joint
and common costs among the various classes using factors appropriate to each type of expense. The COSA
is the second step in a traditional three-step process for developing natural gas service rates, after
development of the revenue requirement but before designing rates.
This COSA study is an embedded cost analysis. Embedded costs generally reflect the actual costs incurred
by the utility and closely track the costs kept in its accounting records.
There are three basic steps to follow in developing a COSA, namely: functionalization; classification;
allocation.
Functionalization separates costs into major categories that reflect the different services provided to
customers and the types of assets used to provide those services. The primary functional categories for
the City’s natural gas utility are supply and distribution.
Classification determines the portion of each cost that is related to specific cost-causal factors, or
“classifiers.” These classifiers might be demand-related (related to the class of service’s peak energy usage
over a given period), energy-related (related to the total energy used by the class of service over a given
period), or customer-related (costs incurred as a result of receiving service, regardless of the energy use
or peak demand). Natural gas supply or commodity costs are related to the amount of natural gas
purchased and are therefore considered energy-related. The distribution system is designed to extend
service to all customers attached to the system and to meet both the peak day demand and the annual
energy requirement of each customer, meaning that costs are both demand-related and energy-related.
Some operational costs, such as billing, are generally customer-related. Costs can also be classified based
on system revenues or directly assigned to a customer or group of customers if appropriate.
Allocation of costs to specific classes of service happens after those costs have been classified. Allocation
factors are chosen to allocate the costs assigned to each classification, and the share of costs allocated to
each class of service are based on the class’s contribution to the specific allocation factor selected. For
example, certain distribution costs might be classified as partially demand-related and partially energy-
related. The demand-related costs could be allocated to the classes of service using each class’s
contribution to the annual system peak day demand (the highest day for the system as a whole at any
time during the year), while the energy-related costs would be allocated to classes based on their annual
energy usage. In this example, the allocation factors are 1) each class of service’s contribution to the
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 14
annual system peak day demand, and 2) the annual energy usage of each class of service. An analysis of
customer requirements and usage characteristics is completed to develop allocation factors reflecting
each of the classifiers employed within the COSA.
3.2 CITY NATURAL GAS DISTRIBUTION COSA METHODOLOGY
3.2.1 Functionalization
As mentioned previously, this rate study addresses only the distribution portion of the City’s gas utility.
As such, all costs included in the revenue requirement have already been functionalized as Distribution.
Distribution services include all services required to transport the natural gas commodity from the point
of interconnection across the City’s distribution system to end-users at their meters.
3.2.2 Classification and Allocation of Costs
The classification and allocation factors used for each component of the rate base and revenue
requirement are shown in Table 3-1 and Table 3-2 and are discussed in more detail below. (Rate base for
the City’s natural gas utility consists of investment of physical assets. It includes general plant and
distribution plant investment and is net of accumulated depreciation. EES typically relies on an audited
fiscal year for rate base amounts, whereas revenue requirement is a forecasted future year.)
Descriptions of each factor are included in Table 3-3. In general, this COSA employs the same methodology
used in the 2020 COSA but with a few changes to allocation factors based on updated cost-causation
themes.
Distribution costs are classified into the following components: demand, energy, customer, and direct
assignments. The demand component reflects the portion of costs driven by peak demand for natural gas.
The energy component is related to costs incurred to provide the annual amount of gas to customers or
groups of customers. The customer component covers the facility and operating costs that vary with the
number of customers, such as meters and billing. Directly assigned costs are costs that can be attributed
to just one or more rate classes. The following are the specific classifiers used for the City’s distribution
function:
Demand. Demand-related costs are those that vary with the peak demand or the maximum rates
of natural gas supply to classes of service. Customer and system demands for this analysis are
measured in peak day therms. Demand costs are generally related to the size of facilities needed
to meet a customer’s maximum daily demand. Generally, the rate base is allocated based on the
Average & Excess method which involves a demand component (see Section 3.3). The allocated
rate base is then used to allocate certain revenue requirement expenses.
Energy. Energy-related costs are those that vary with the total amount of natural gas consumed
by customer class. Usage measured in therms is used in this portion of the analysis. Energy costs
are the costs of consumption over a specified period of time, such as a month or year. Reserve
contributions are an example of a cost item that is allocated to customer classes based on therms
used. This ensures that each customer contributes to the reserve fund based on their use of the
system.
Customer. Customer-related costs are those that vary with the number of customers. Customer
costs are weighted to account for differences in the cost of providing services to those customers.
For example, the service line and metering associated with serving a large commercial customer
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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is more costly and requires substantially more work and material than that for a small residential
customer. Customer service expenses are typically allocated to customers based on some
measure of number of customers or weighted customer service factors based on the amount of
time and complexity to provide service to different types of customers.
Direct Assignment. Some costs are directly assigned to specific classes of service. For example,
costs associated with specific account representatives to large commercial customers are
allocated directly to the G3 rate class. In exchange, G3 does not share in other customer service
costs incurred by the other classes.
The methodology for classification and allocation of the City’s rate base is summarized in Table 3-1. All
line items in this table are functionalized as Distribution.
Note that the rate base does not reflect the annual expenses associated with running the utility but
instead reflects the capital investments made by the utility for the physical assets in the distribution
system. The purpose of looking at the rate base in the COSA is to set the cost causation associated with
the physical assets, which are then used to guide the allocation of the annual expenses. Working capital
is traditionally added to cover the cash on hand needed to run the utility. An estimate of 1/8th of operating
costs is typically used to reflect the lag time between revenue collections and accounts payable.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 16
TABLE 3-1: DISTRIBUTION RATE BASE
Asset Description
Asset Value
FY 2021-2022 7
and Allocation
Equip-Meters
$12,334,716 Weighted by Meters and
Total Distribution Plant $155,578,873
General Plant
$1,910,425 Plant
$2,911,310 Plant
Total General Plant $4,821,735
Total Gross Plant in Service $160,400,608
Less: Accumulated Depreciation
Total Accumulated Depreciation $53,646,292
Total Net Plant
Working Capital: 1/8 Operating Costs
$2,251,043
OMWOP Operation & Maintenance
Expense
TOTAL RATE BASE
Constructions Working in Progress
(CWIP)
Total CWIP
TOTAL RATE BASE plus CWIP
Next, the methodology for classification and allocation for the City’s Natural Gas Distribution revenue
requirement can be found in Table 3-2. More detail on the classification and allocation factor codes used
in the classification and allocation process can be found in Table 3-3.
7 Fiscal year ending June 30, 2022 was the audited asset values available for the study period.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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TABLE 3-2: DISTRIBUTION REVENUE REQUIREMENT
FY 2025-2026
Classification
and Allocation
Engineering Support 768,861 RBD Distribution Rate Base
Operations & Maintenance 9,028,547 RBD Distribution Rate Base
9,797,408
Admin - Customer & Marketing $227,967 CUSTW Number of Services
Weighted for
Weighted for
Weighted for
Weighted for
Total Customer Service, Accounts &
Sales
Administrative & General
Administrative & General Salaries 8
Allocated Charges 9
Rents
Transfers to Non-Enterprise Funds
Transfers to Enterprise Funds
8 Administrative and General Salaries includes salaries and benefits for staff assigned directly to Gas Utility
Administration.
9 Allocated charges are general costs incurred on behalf of all of the City’s utilities (water, wastewater, fiber, electric
and gas) that are individually determined and allocated to each business line, as well as salaries and benefits
allocated based on Capital Improvement Project cost centers.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 18
FY 2025-2026
Classification
and Allocation
$5,002,927
$18,008,343
Interest on Long-Term Debt $23,348 NETPLT Net Plant
Principal on Long-Term Debt $778,250 NETPLT Net Plant
System Improvement $7,538,046 NETPLT Net Plant
$8,339,643
General Fund Transfer $9,734,580 REV Current Rate Revenues
Reserves Contribution $5,874,887 therm Annual Energy (therms)
$41,957,453
Customer Discounts 10 -$318,105 NETPLT Net Plant
Connection Fees $700,000 NETPLT Net Plant
Misc. Revenue and other
contributions (Other) -$449,823
$625,693
Total Other Revenues
REVENUE REQUIREMENT for COST
ALLOCATION $41,268,342
Table 3-3 shows how each factor code classifies then allocates the costs to classes of service. The Average
& Excess (AE) allocator is described in greater detail below the table.
10 This includes uncollectible accounts for bad debt, low-income rate assistance discounts, and pre-1970s retired
employee discounts on utility bills at a primary residence. The low-income rate assistance discounts and pre-1970s
retired employee discounts on utility bills at a primary residence are funded through non-rate revenues including
interest income from investments.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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TABLE 3-3: NATURAL GAS DISTRIBUTION REVENUE REQUIREMENT
Factor Code Factor Name Classification Allocation Basis
AE Average and Excess 100% Demand An allocation of demand costs that
calculates the difference between the peak
demand and average demand – A more
detailed explanation of the Average and
Excess allocation framework is later in the
Accounting/Metering w/o G3 accounting and metering but excluding G3
Rate Base 50% Energy
8% Customer
based on the net book value of all shared
services assets and other capital assets
Gas Supply and A&G) 42% Energy Gas Supply and A&G expenses
Rate Base 50% Energy based on the book value of all general plant
(w/o General Plant & 50% Energy value of all capital assets (initial cost)
50% Energy
8% Customer
value of all capital assets (initial cost less
accumulated depreciation) assigned to
Purchased Gas Supply) 42% Energy the cost of Purchased Gas Supply
3.3 AVERAGE & EXCESS (A&E)
The Average and Excess method (A&E method) compares the baseline capacity and energy used (the
“average,” or “baseline”) against the maximum capacity and energy used on a seasonal basis (the
“excess”). This captures the level of system capacity required to serve the customer during peak times as
opposed to average times. The previous COSA study functionalized and classified distribution system costs
as 100% demand related, and then used each customer’s share of non-coincident peak demand to allocate
those distribution costs across customer classes.
As part of this study, EES revised the A&E method calculations because it recognizes that part of the
system is built to serve the customer/energy use and part of the system was built to serve the demand
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 20
component whereas the previous method primarily attributed system sizing entirely to demand. The
revised A&E method classifies distribution system costs to demand and energy. Then costs are allocated
to customer classes based on an estimate of average demand and maximum (excess) demand for each
class. This current A&E method provides the basis for calculating fixed and variable unit costs. It also
equitably determines residential Tier 1 and Tier 2 rates (described later).
Based on monthly sales by customer class, the A&E method used in this Study makes the following
assumptions:
1. Average demand represents the investment needed to serve the average customer in each class;
2. Excess use is the additional investment needed to serve customers with demands that vary by season.
Those customers with higher excess use require a larger investment in the system compared with
customers whose usage remains close to the minimum use year-round.11
The current A&E method assumes that the marginal costs of the distribution system do not decrease as
capacity increases. The method also provides cost allocation across customer classes consistent with the
average use of each class while still maintaining a cost obligation for classes where excess use varies
significantly from average use.
3.3.1 Average & Excess Calculation
The A&E method classifies (splits) distribution costs between energy and demand components. This
classification recognizes that a portion of the distribution system is engineered to serve a customer with
minimal use (energy). In addition, another portion of the distribution system investment is needed to
meet customer maximum use (demand). In order to apportion the system between minimum use
characteristics and maximum demand characteristics, we approximate this share of the system using the
classification split as described below.
Table 3-4 demonstrates the classification using a minimum average use and excess use method (the A&E
method). Minimum average use is defined as annual use calculated assuming customer use is equal to the
lowest monthly use year-round (this lowest therms/month/customer occurs in October for residential
and November for commercial). As noted above, the minimum average use is used to approximate the
share of distribution system needed to serve a customer within each class at their minimum level of
consumption. Using this method, the relevant costs are then split between the share of the minimum
average use (energy-related in row d) and share of excess demand (demand-related in row e).
11 A good example of this type of customer is an individually metered multi-family unit. These customers have low
average use and the services needed for each unit are lower in cost (shared) compared with services needed to serve
a single family home (not shared).
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 21
TABLE 3-4: AVERAGE & EXCESS CLASSIFICATION
Formula Total
Annual Sales, Therms a 25,779,489
Minimum Average Use, Therms b 13,936,088
Excess Use, Therms c 11,843,401
Energy-Related d = b ÷ a 54%
Demand-Related e = c ÷ a 46%
Once classified as energy and demand costs, distribution system costs are allocated to customer classes.
For the energy-related costs, the cost allocation is based on the customer class’ average use of the system.
Average use is appropriate since it reflects annual usage characteristics while the minimum would reflect
only the low season usage (summer). For demand-related, the cost allocation is based on customer class’
share of maximum use. The result is that all customers using the system will pay for their share of fixed
distribution costs based on their usage level, and customers with higher variation in use (demand) will
also pay their fair share of demand-related system costs. The recommended rate design within each class
determines how these costs are recovered.
3.4 CUSTOMER CLASSES OF SERVICE
Customer classes of service refer to the arrangement of customers into groups that reflect common usage
characteristics or facility requirements.12 The classes of service used within this Study were as follows:
Residential (G1); Small Commercial (G2); and Large Commercial (G3). The City also serves one Compressed
Natural Gas (CNG) customer whose costs are paid by the City’s Public Works department; the costs and
revenues for this City-owned service are part of the overall revenue requirement. These rates should
continue to increase at system average rates as they have been over recent periods because the nature
of service has not changed. Thus, it is reasonable that the CNG customer’s cost of service has increased
at the same rate as the distribution expenses overall.
3.5 COST OF SERVICE RESULTS
Given the key assumptions and updates discussed above, the COSA was completed. Tables 3-5 and 3-6
provide a summary of the Rate Base and Revenue Requirement amounts allocated to the various
customer classes.13 These schedules are calculated by multiplying the applicable classification and
allocation factors to each cost in the rate base and revenue requirement.
12 Breakpoints between or within rate classes are sometimes referred to as segmentation in rate making.
13 The rate base and revenue requirement tabs of the COSA model also show the rate base and revenue requirement
allocated to each class of service.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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TABLE 3-5: DISTRIBUTION RATE BASE ALLOCATION RESULTS: FY 2025-2026
Asset Description Total
G1
G2 Small
G3 Large
$12,334,716 $9,135,516 $2,878,448 $320,752
$59,109,371 $24,674,393 $25,111,143 $9,323,835
$2,729,148 $1,139,245 $1,159,411 $430,492
$976,067 $407,446 $414,658 $153,963
$77,559,779 $32,376,261 $32,949,339 $12,234,179
$2,869,793 $1,197,956 $1,219,160 $452,677
$155,578,873 $68,930,816 $63,732,158 $22,915,899
$1,910,425 $846,434 $782,597 $281,395
$2,911,310 $1,289,886 $1,192,604 $428,820
$4,821,735 $2,136,319 $1,975,201 $710,215
$160,400,608 $71,067,135 $65,707,359 $23,626,113
$49,833,503 $22,079,245 $20,414,062 $7,340,197
$3,812,789 $1,689,295 $1,561,891 $561,602
$53,646,292 $23,768,540 $21,975,953 $7,901,799
$106,754,316 $47,298,595 $43,731,406 $15,724,314
$2,251,043 $1,131,981 $820,532 $298,530
TOTAL RATE BASE
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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TABLE 3-6: DISTRIBUTION REVENUE REQUIREMENT ALLOCATION RESULTS: FY 2025-2026
Plant Description FY 2026 Total G1 Residential
G2 Small
G3 Large
Engineering Support 768,861 340,652 314,960 113,249
Operations & Maintenance 9,028,547 4,000,190 3,698,502 1,329,855
Total Distribution 9,797,408 4,340,842 4,013,463 1,443,104
Customer Service, Accounts, & Sales
Admin - Customer & Marketing $227,967 $179,500 $41,741 $6,727
$465,537 $176,296 $207,781 $81,460
Total Customer Service $3,208,008 $2,199,184 $727,166 $281,658
$1,451,715 $730,023 $529,167 $192,525
Transfers to Non-Enterprise Funds
Total Costs with A&G
Interest and Debt Service Expense
$23,348 $10,344 $9,564 $3,439
$778,250 $344,812 $318,806 $114,632
Total Debt Service /CIP Expense
General Fund Transfer
Reserves Contribution
Revenue Requirement Before Other
Revenues $41,957,453 $19,158,686 $16,850,905 $5,947,862
Customer Discounts -$318,105 -$140,940 -$130,310 -$46,855
Connection Fees $700,000 $310,142 $286,752 $103,106
-$449,823 -$199,299 -$184,268 -$66,256
$131,346 $58,194 $53,805 $19,347
$625,693 $277,220 $256,312 $92,161
Total Other Revenues
NET REVENUE REQUIREMENT
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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Table 3-7 provides a summary of the COSA results with the recommended revenue changes. These results
are the basis for the recommended distribution charges provided in the next section.
TABLE 3-7: DISTRIBUTION COSA RESULTS: FY 2025-2026
Projected FY 2026 Revenues
Revenue
2026
Change
$16,311,063 $18,853,368 $2,542,305 15.59%
G2 – Small Commercial $16,565,086 $16,568,614 $3,527 0.02%
G3 – Large Commercial $5,081,713 $5,846,360 $764,647 15.05%
Total $37,957,863 $41,268,342 $3,310,479 8.7%
Residential and Large Commercial classes require higher rate increases compared to the G2 class. EES
compared this study with the previous analysis (FY 2019-2020) and found the following significant drivers
for these results:
1. Overall, the FY 2025-2026 Distribution revenue requirement is 171% of the FY 2019-2020 revenue
requirement. The increase is due to multiple years of significant inflationary pressures and
planned fund contributions.
2. The allocation of the General Fund Transfer was updated from Net Plant to Revenue. As a result,
G1 is being allocated a larger share of the General Fund Transfer. Despite the adverse impact on
G1 rates, this update better aligns the expense item with cost since the General Fund Transfer is
calculated based on gross revenues.
3. The Rate Base Allocation of Distribution assets was updated to reflect updated Average & Excess
calculations. This change moved some asset value from G2 to G1 due to the greater variability in
seasonal use by G1 customers. This allocation flows through to expense items allocated based on
the same version of rate base, and it results in a larger share of expenses being allocated to G1
compared to the 2020 study and less cost being allocated to G2.
4. Customer allocators such as meters and services, and weighed customers, were updated to reflect
current meter cost and billing cost information. These updates resulted in larger shares of
expenses allocated to G1 and G3.
5. Average use for G1 and G3 are lower in FY 2025-2026 compared with FY 2019-2020. When
average use is lower, fixed costs are spread across a smaller number of therms impacting the
overall rate adjustment needed.
In addition, all rate change aspects in this report are for distribution charges only and do not include
changes to supply. When considering overall rate impacts, it is important to note that most of these rate
changes are forecasted to be less than a 10% impact when considering combined commodity and
distribution charges.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 25
4 Rate Design
The final step in the rate study process is to design rates for each class of service or customer class. In
California, local governments are subject to Article XIII C of the California Constitution, amended by
Proposition 26 (2010). As a result, the City has set rates to match the COSA results for each customer class.
It is important to note that the results of the revenue requirement and COSA study are based on
forecasted load data estimates and usage pattern assumptions. Actual load and usage patterns may differ
from forecast. For this Study, rates are developed based on the forecast loads and observed historical
usage patterns for each customer class.
The rates for the Residential and Commercial customers are designed to reflect the differences in costs
among the various customer classes. The costs per customer class differ based on the seasonal shape of
consumption (referred to as energy use) as well as the daily peak demand for each customer class.
Differences in energy use by season and the level of peak demand have an impact on the utility’s need for
distribution facilities and the costs to operate and maintain those facilities.
4.1 RECOMMENDED RATE DESIGN: DISTRIBUTION
This section of the report reviews the present rate structures for the City and provides a comparison with
the recommended rates based on this cost of service study. Table 4-1 summarizes the current rate design
for each rate schedule and recommended rate design updates. As mentioned previously, the
recommended rate design is the same as the current rate design with the exception of some updates and
refinement as described below.
TABLE 4-1: NATURAL GAS DISTRIBUTION RATE DESIGN RECOMMENDATION OVERVIEW
Rate Schedule Current Rate Design Recommended Rate Design
Residential G1 Fixed Monthly Charge
Seasonal Tiered Rate with
Inclining Blocks
•
service unit costs
• Calculate tiered rates based on A&E cost allocation
•
Small Commercial G2
•
service
• Implement three separate fixed monthly charges
Large Commercial G3
•
service unit costs
Table 1-8 in Section 1.2.3, Rate Recommendations, summarizes the current and FY 2025-2026
recommended rates for each class. The rate recommendations and bill impacts by rate class are provided
below.
4.1.1 Residential (G1)
The G1 distribution rates consist of a monthly service charge and volumetric tier rates: The Tier 1 rate
applies to usage up to the baseline quantity and the Tier 2 rate applies to all usage above the baseline.
While the tier rates do not change between seasons, the baseline quantity varies by season, and is higher
in winter than in the summer because natural gas heat is more prevalent in the winter. This ensures that
those customers contributing to higher seasonal demand are paying appropriately for their share of the
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demand-related cost.
EES evaluated the current G1 Tier breakpoints using sales data for several test periods, based on the
current rate design. EES confirmed that the winter baseline of 60 therms/30-day-billing still reflects of the
winter average at 60 therms/30-day-billing: EES recommends continuing to set the winter baseline to 60
therms/30-day-billing. However, the data, more than not, suggest that the summer baseline should be
increased from 20 to 23 therms/30-day-billing. Table 4-2 below shows the current baseline and average
consumption values supporting EES recommendation.
TABLE 4-2: BASELINE CALCULATIONS ASSESSMENT
Tier 1 Baseline Assessment Therms/30-day-billing
Summer Winter
Current Baseline 20 60
Average Consumption
FY 2022 Actual 22 60
FY 2023 Actual 24 70
FY 2024 Actual 21 53
Gas Forecast FY 2026 24 56
Average of 3 Historical Years and 1 Forecast Year 23 60
Summer Winter
Recommended Baseline 23 60
Further, considering the costs that should be collected in Tier 1 vs. Tier 2 rates, EES used the same Average
and Excess calculations applied to distribution rate base or plant to determine the amount the current
rate design should collect at each rate. The excess calculation compares the difference between the
minimum and maximum use to produce the excess portion of average and excess. Using the excess
calculations, EES can determine how much Tier 1 baseline consumption is above minimum use and assign
that portion of excess demand costs to the Tier 1 rate. The result includes 54% of demand costs in the Tier
1 rate and the remainder of demand costs assigned to the Tier 2 rate.
Table 4-3 summarizes the costs to be recovered in each rate component for G1.
TABLE 4-3: G1 RATES AND COST RECOVERY
Rate Component Recovers The Following Costs:
Monthly Service Charge Customer-related costs such as customer service, billing, and overhead adders
Tier 1 Volumetric Rate Energy-related costs plus 54% of demand-related distribution unit costs
Tier 2 Volumetric Rate Energy-related costs plus 46% of demand-related distribution unit costs
This result indicates that the rate design, if appropriately balanced as proposed, collects distribution
system costs between the tiers based on how those costs are classified and allocated in the COSA and the
seasonal Tier 1 baseline quantities.
The recommended volumetric rates for Residential are based on the volume of therms in each tier and
the relative share of demand-related distribution costs. Based on the baseline usage, or Tier 1 allocation,
54% of G1 consumption is within the Tier 1 (6.9 million therms). This volume is compared with the
minimum average use volume of 3.6 million therms. Minimum Average Use is the average volume of
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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therms across all Residential customers per day multiplied by the number of days in a year (Table 4-4).
TABLE 4-4: G1 MINIMUM AVERAGE USE
Minimum Average Use/30-Day-Billing 14 therms
Annual Minimum Average Use 14 therms × 12 30-day-billings x 21,255 meters = 3.6
million therms
The current average Tier 1 volume on an annual basis is equal to 26 therm/30-day-billing which is
significantly higher than the minimum of 14 therms/30-day-billing calculated for minimum use. Therefore,
the Tier 1 volume also exceeds the annual minimum average use, and EES determined that a share of
demand-related costs should be allocated to the Tier 1 rate.
The share of demand-related costs to be collected in the Tier 1 rate is calculated by taking the share of
Tier 1 consumption in excess of the Minimum Average Use, as shown in Table 4-5.14
TABLE 4-5: G1 TIER 1 DEMAND-RELATED COSTS
Formula Total
Annual G-1 Sales, Therms A 9,762,524
Minimum Average Use, Therms B 3,558,936
Tier 1 Use, Therms as proposed C 6,935,563
Tier 1 Use Exceeding Minimum Average Use, Therms d = c - b 3,376,628
Excess Use (Demand-Related), Therms f = a - b
Share of Demand-Related Costs in Tier 1 Baseline g = d÷ f
This methodology helps to align the tiered rates more closely to the cost of service for each block of service
volume. If the Tier 1 baseline seasonal quantities are adjusted in the future, this analysis should be
updated to reflect the new quantities.
Table 4-6 shows the bill impacts for average customer use in summer and winter.
14 It is necessary to evaluate the minimum average use and compare those quantities to the Tier 1 quantities. If the
Tier 1 quantity were equal to the minimum use, 100% of demand-related distribution costs should be collected
through the Tier 2 rate. However, because the baseline Tier 1 quantity is approximately equal to average seasonal
use, that average use includes some component of demand cost. Therefore, a portion of demand-related costs
should be collected from the Tier 1 rate.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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TABLE 4-6: G1 BILL IMPACTS AT AVERAGE CUSTOMER USE, DISTRIBUTION ONLY
At Current Recommended Therms/30-
$43.83 $51.09 $7.26 16.6% 22.0
$92.54 $107.75 $15.21 16.4% 61.1
Table 4-7 shows the impacts for a range of customer bills under various low, median and high usage levels.
TABLE 4-7: G1 BILL IMPACTS AT VARIOUS USAGE LEVELS, DISTRIBUTION ONLY
Season
Usage At
Current FY 25 Rates
At
Recommended Bill Impact
$/Month
Bill Impact
$33.75 $40.38 $6.64 19.7%
$45.52 $54.99 $9.47 20.8%
$79.70 $86.50 $6.80 8.5%
$124.15 $127.84 $3.69 3.0%
$68.69 $83.41 $14.73 21.4%
$104.92 $128.14 $23.22 22.1%
$180.07 $203.03 $22.96 12.8%
$390.54 $399.00 $8.47 2.2%
$70.27 $85.47 $15.20 21.6%
4.1.2 Small Commercial and Residential Master-Metered (G2)
The current G2 distribution rate design is composed of a fixed monthly service charge and a volumetric
charge. As described in Section 1.2, Rate Study Overview, EES performed a detailed analysis of G2 usage
and costs and recommends a refinement in the development of the Monthly Service Charge for G2.
Figures 4-1 and 4-2 show examples of usage and cost characteristic analysis.
The fixed monthly service charge for a given rate schedule (customer class) is set to recover the customer-
related costs allocated to that schedule. Weighted meter cost is a major factor used to allocate customer-
related fixed costs to various rate schedules. This COSA uses updated meter costs that reflect latest
available data on meter cost and associated capacity of installed meters.
G2 is different from G1 and G3 in that its approximately 2,100 services have a much wider range of usage,
as well as meter types and capacities. EES examined G2 meter types and corresponding average usage
data to determine whether and how it can inform the development of G2 monthly service charge to better
reflect customer-related fixed costs.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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Figure 4-1 shows how G2 meter capacity and associated average consumption. Size correlates to usage;
as expected, larger meters have larger average usage.15 Larger meters require larger service lines
(connecting the meter to the distribution system) and generally impose greater demand on the system.
FIGURE 4-1: AVERAGE MONTHLY USAGE BY METER CAPACITY
Moreover, EES observes distinct patterns and separations in average usage levels that support three G2
meter groupings based on maximum meter capacity. Figure 4-2 shows the distinct average usage levels
associated with the following three groupings by maximum meter capacity (in standard cubic feet per
hour or scfh).
1. Up to 220 scfh (≤ 220 scfh)
2. Above 220 scfh and below 4,000 scfh (> 200 scfh and < 4,000 scfh)
3. 4,000 scfh and above (≥ 4,000 scfh)
15 This is expected because meter capacity is sized to match the customer’s usage demand. City of Palo Alto, Utility
Rule and Regulation 15, Section B.6: Meter Installations, Capacity of Meters, April 2023.pdf.
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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FIGURE 4-2: G2 – AVERAGE MONTHLY USAGE BY METER CATEGORY
Thus, EES recommends implementing a Monthly Service Charge based on the G2 service’s maximum
meter capacity and calculates these charges using allocated costs that are based on each grouping’s
weighted meter costs.
The above three G2 meter ranges were chosen as a result of detailed examination of the distribution of
usage across different meter types and capacities, according to summary data in Figures 4-1 and 4-2. The
calculation for the volumetric charge applicable to all G2 usage remains unchanged. See Table 1-6, G2
Monthly Service Charges: FY 2025-2026, and Table 1-8, Current and Recommended Rates.
Table 4-8 shows the G2 bill impacts for representative accounts in each G2 subgroup. Impacts for average
use and for 50% of average use are provided.
TABLE 4-8: G2 BILL IMPACTS
At Current
FY 2024-2025
FY 2025-2026
Average
# of
$629.59 $629.72 $0.13 0.0% 437 2,193
≤ 1,134
Average Use $216.71 $98.87 -$117.84 -54.4% 55
50% of Average Use $186.81 $63.96 -$122.84 -65.8% 28
˂ 942
Average Use $679.70 $705.15 $25.45 3.7% 484
50% of Average Use $418.30 $400.05 -$18.26 -4.4% 242
≥ 116
Average Use $4,245.43 $5,189.76 $944.33 22.2% 3,783
50% of Average Use $2,201.16 $2,803.69 $602.53 27.4% 1,891
4.1.3 Large Commercial (G3)
The present G3 rate design is composed of a monthly service charge and a volumetric charge. As noted
earlier, this class generally has large capacity meters and a high consumption threshold for service. G3
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CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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rate schedule applies to commercial customers who use at least 250,000 therms per year at one site.16
This threshold, which defines the rate class, results in a group of customers with similar services, sizing
requirements and usage characteristics. Therefore, it is not necessary to develop tiered rates or fixed
charge variances within this class. No change is recommended in the overall design of these charges.
For illustrative purposes, Table 4-9 presents the G3 bill impact at 20,833 therms, which is 1/12 of the
annual threshold level for G3 service.
TABLE 4-9: G3 BILL IMPACTS
At Current FY FY 2025-2026
G3 Large Commercial $41,287.45 $44,186.73 $2,899.28 7.0%
4.2 SUPPLY CHARGES
The primary focus of the rate study was the distribution charges which vary based on budgets and
operating needs. The City also must pass through costs that vary based on external factors and market
conditions. These appear in rate schedules as Supply Charges. Supply charges include the Commodity, Cap
and Trade Compliance, Carbon Offset, and Transportation Charges. These charges are on a $/therm basis
and require frequent updates due to the variable nature of the underlying costs.
Currently, the City has a range included in the rate schedules. Table 4-10 shows the current ranges.
TABLE 4-10: SUPPLY CHARGES
Supply Charges $/therm
1. Commodity (Monthly Market Based) $0.10-$4.00
2. Cap and Trade Compliance Charges $0.00-$0.25
3. Transportation Charge $0.00-$0.30
4. Carbon Offset Charge $0.00-$0.10
EES examined both the current calculation of each charge and the basis for that calculation, as well as
whether the charge should remain a pass-through with a range or not.
EES does not recommend any changes to the Commodity charge range. For the Commodity supply charge,
Council amended the Gas Utility Long-term Plan (GULP) Objectives, Strategies and Implementation Plan
including collecting funds via a gas price mitigation adder to manage potential future short-term natural
gas price spikes above the $4.00 per therm maximum charge (Resolution 10187, August 19, 2024). The
Commodity charge range, therefore, is consistent with the Council-approved strategy.
16 Utility Rate Schedule G-3.
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
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The City’s gas utility is a covered entity under the California Air Resources Board (CARB) Cap-and-Trade
program, in this programthe City is obligated to purchase allowances to cover all greenhouse gas
emissions resulting from natural gas use within Palo Alto’s service territory. EES recommends eliminating
the ranges for the Cap and Trade Compliance charge and instead converting this charge to a pass-through
of the City’s actual costs because the City has little to no control over them, and they are largely non-
discretionary. The Cap and Trade Compliance Charge is calculated based on the Cap-and-Trade program’s
quarterly auction allowance closing prices.
Likewise, EES recommends eliminating the ranges for the Transportation Charge and passing through
these charges. The Transportation charge is the rate the City pays Pacific Gas and Electric Company (PG&E)
to transport gas from the PG&E Citygate to the City of Palo Alto distribution system. PG&E is regulated by
the California Public Utilities Commission. Palo Alto has no control over these charges and no alternatives
for transporting gas to its distribution system. The Transportation Charge is based on PG&E’s wholesale
tariff (G-WSL).17
Recently, the Transportation Charge exceeded the published range and the Council increased the upper
limit on the Transportation Charge.18 This is likely to occur for both the Transportation Charge and the
Cap and Trade Compliance Charges in the future. Because the true costs can vary outside of the ranges
provided, the ranges do not appear to provide material value to customers. If the costs vary outside the
upper limit of the range, the costs above the limit are paid for by the gas utility’s reserves unless the
Council increased the upper limit. Updating the ranges with a wider spread would also provide less
practical information to customers. Therefore, EES recommends eliminating the ranges for the Cap and
Trade Compliance and Transportation charges. Two years of historical monthly values for the
Transportation Charge and Cap and Trade Compliance Charge are posted publicly on the City’s website
for reference.19
EES does not recommend changes to the Carbon Offset Charge range. In December 7, 2020 Council
adopted Resolution 9930 amending the Carbon Neutral Gas Plan. This program is voluntary in the sense
that it is a local program approved by the City Council rather than a compliance obligation imposed by the
state or another governing body. The amended plan limited the purchase price of offsets to $19 per ton
CO2e, consistent with the original maximum 10 cents per therm rate impact; therefore, the range is
consistent with the Council-approved program.
Second, EES recommends providing more detailed information on the source costs and calculation for all
four of the supply charges. Recommended additions include language in Table 4-10.
17 https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-WSL.pdf
18 On October 7, 2024, Council adopted Resolution 10190 increasing the upper limit on the Transportation Charge
on all of the City’s gas rate schedules from $0.25 per therm to $0.30 per therm effective November 1, 2024.
19 Residential: https://www.cityofpaloalto.org/files/assets/public/v/25/utilities/rates-schedules-for-
utilities/residential-utility-rates/monthly-gas-volumetric-and-service-charges-residential-3.pdf and
Non-Residential and Residential Master-Metered:
https://www.cityofpaloalto.org/files/assets/public/v/24/utilities/business/business-rates/monthly-gas-volumetric-
and-service-charges-commercial-3.pdf
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 33
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 34
TABLE 4-10: SUPPLY LANGUAGE
Supply Charges Description
1. Commodity (Monthly Market Based) This charge is based on the monthly natural gas Bidweek Price Index for delivery at
PG&E Citygate, adjusted to account for delivery losses to the customer’s meter. The
Commodity Charge also includes adjustments to account for Council-approved
programs implemented to reduce the cost of Gas, including a municipal purchase
discount (Adopted via Resolution 9451, on September 15, 2014), and $0.055 per therm
for mitigating the impact of short-term natural gas market price spikes.
The Commodity Charge calculation formula is:
PG&E Citygate Monthly Bidweek Price ($/MMBtu)
+ Gas Supplier Adder ($/MMBtu)
– Municipal Gas Discount ($/MMBtu)
× (1+ Distribution Loss Multiplier)
+ Gas Price Spike Mitigation Charge ($/MMBtu)
÷ 10 (conversion from MMBtu to therm) (MMBtu/therm)
= Commodity Rate ($/therm)
Where :
PG&E Citygate Monthly Bidweek Price is the monthly price for PG&E Citygate as
reported in the first issue of the month of Natural Gas Intelligence’s Bidweek Survey
as published by Intelligence Press Inc.
The Gas Supplier Adder is the premium or discount applied to the Bidweek Price Index,
based on the City's actual transactions with its natural gas suppliers.
The Distribution Loss Multiplier, updated annually, is calculated by the variances of gas
supply purchases and gas retail sales for the past three fiscal years.
2. Cap and Trade Compliance Charge
with the State’s Cap and Trade Program, including the cost of acquiring compliance
instruments sufficient to cover the Gas Utility’s compliance obligations. The Cap and
Trade Compliance Charge is adjusted in response to market conditions, retail sales
volumes, and the quantity of allowances required. The calculation formula is based on
carbon allowance auction prices and allowances needed to comply with state law. One
allowance is equal to 1 metric ton (MT) of CO2.
The Cap and Trade Compliance Charge calculation formula is:
Most Recent Auction Price ($/MT CO2)
x Number of Allowances Required (%)
x (conversion from MT CO2 to therm) (MT CO2/therm)
= $/Therm
Where:
Number of Allowances Required (%) =
(Projected Emissions for Current Year - Palo Alto’s Allocated Allowances for Current
Year)
÷ Projected Emissions for Current Year
Attachment F
CITY OF PALO ALTO Natural Gas Cost of Service and Rate Study
prepared by EES CONSULTING 35
3. Transportation Charge The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto,
accounting for delivery losses to Customer Meters. The current rates are shown in
this tariff https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_SCHEDS_G-
WSL.pdf, provided by PG&E. Additionally, there is a distribution loss factor (updated
annually), which is calculated by the variances of gas supply purchases and gas retail
sales for the past three fiscal years.
The Transportation Charge calculation formula is:
PG&E G-WSL Transportation Charges ($/therm)
- Cap and Trade Cost Exemption ($/therm)
× (1+ Distribution Losses Multiplier)
= Transportation Charge ($/therm)
Where:
The Distribution Loss Multiplier, updated annually, is calculated by the variances of gas
supply purchases and gas retail sales for the past three fiscal years.
4. Carbon Offset Charge
gases produced when Gas is burned. The Carbon Offset Charge will change in response
to market conditions, sales volumes, and the quantity of offsets purchased within the
Council-approved cap of $19 per MT CO2e, calculated annually.
The Carbon Offset Charge calculation formula is:
Weighted Average Cost of Carbon Offset ($/MT CO2)
x (conversion from MT CO2 to therms) (MT CO2/therms)
÷ Annual Gas Sales (therms)
= Carbon Offset Charge ($/therm)
Where:
Purchase Price of Carbon Offset ≤ $19/MT CO2e
Attachment F
Date: February 7, 2025
Version: Revised Final Version
Test Period: FY: 2026
Distribution System Allocation Method: Average and Excess Method (AE)
EES Consulting, A GDS Associates Company
16701 NE 80th Street - Suite 102 - Redmond, WA 98052 - 425-889-2700 - www.eesconsulting.com
Georgia / Texas / Alabama / New Hampshire / Wisconsin / Florida / Maine / Washington / California
For questions regarding this model, please contact:
Russ Schneider, Senior Project Manager Amber Gschwend, Managing Director
russ.schneider@gdsassociates.com amber.gschwend@gdsassociates.com
406-471-8015 425-655-1042
Palo Alto Gas Utility
Cost of Service Schedules
Prepared By EES Consulting, Inc.Palo Alto Gas Utility - Average and Excess Method (AE)
Forecast Year: 2026 Total G1 Residential G2 - All
G3 Large
Commercial
Revenues - Present Rate Distribution $37,957,863 $16,311,063 $16,565,086 $5,081,713
Less Allocated Revenue Requirement Distribution $41,268,342 $18,853,368 $16,568,614 $5,846,360
Difference -$3,310,479 -$2,542,305 -$3,527 -$764,647
Revenue To Cost Ratio 92.0%86.5%100.0%86.9%
Adjusted Revenue to Cost Ratio 100.0%94.1%108.7%94.5%
Distribution Rate Increase 8.7%15.6%0.0%15.0%
SUMMARY OF PRESENT AND PROPOSED RATE REVENUE
BY CUSTOMER CLASS
Schedule 1.1
Schedule 1.1 Page 1 of 1
Prepared By EES Consulting, Inc.Palo Alto Gas Utility - Average and Excess Method (AE)
Forecast Year: 2026 Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Billing Determinants
Tier 1 Energy (therms)6,672,656
Tier 2 Energy (therms)3,089,869
Total Energy (therms)25,779,489 9,762,524 11,506,051 4,510,914 752,970 5,468,897 5,284,184
Average Monthly Services 23,477 21,255 2,193 30 1,134 942 116
Average Monthly Energy (therms)92 38 437 12,743 55 484 3,783
Functional Cost Total Cost G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Distribution
Demand (DD)$8,974,464 $4,155,398 $3,585,525 $1,233,541 $234,223 $1,756,065 $1,595,237
$/therm $0.3481 $0.4256 $0.3116 $0.2735 $0.3111 $0.3211 $0.3019
Energy (DE)$24,657,494 $9,720,461 $10,930,854 $4,006,179 $1,083,948 $5,158,322 $4,688,584
$/therm $0.9565 $0.9957 $0.9500 $0.8881 $1.4396 $0.9432 $0.8873
Customer (DC)$7,636,384 $4,977,509 $2,052,235 $606,640 $395,369 $1,073,454 $583,412
$/Customer/Month $27.11 $19.52 $78.00 $1,713.67 $29.06 $94.94 $417.62
Total Distribution $41,268,342 $18,853,368 $16,568,614 $5,846,360 $1,713,540 $7,987,841 $6,867,232
Total $/therm $1.6008 $1.9312 $1.4400 $1.2960 $2.2757 $1.4606 $1.2996
Demand + Energy $/therm $1.3046 $1.4213 $1.2616 $1.1616 $1.7506 $1.2643 $1.1892
Total Unit Costs Total Cost G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Total $/therm $2.5996 $2.9299 $2.4387 $2.2948 $3.2745 $2.4593 $2.2983
Demand + Energy $/therm $1.6431 $1.9343 $1.4887 $1.4067 $1.8349 $1.5161 $1.4110
$/Customer/Month $27.11 $19.52 $78.00 $1,713.67 $29.06 $94.94 $417.62
Current Rates
Tier 1 Energy $/therm $0.8229 $1.0809 $1.0702 $1.0809 $1.0809 $1.0809
Tier 2 Energy $/therm $2.1043
$/Customer/Month $16.93 $156.90 $717.89 $156.90 $156.90 $156.90
Total Revenue from Current Distribution Rates $16,311,063 $16,565,086 $5,081,713 $2,948,824 $7,685,399 $5,930,863
SUMMARY OF REVENUE REQUIREMENT UNIT COSTS
BY CUSTOMER CLASS
Schedule 2.1
Schedule 2.1 Page 1 of 2
Prepared By EES Consulting, Inc.Indicated Billing Determinants baseline
Tier 1 Energy (therm)6,935,563
Tier 2 Energy (therm)2,826,961
Total Energy (therms)25,779,489 9,762,524 11,506,051 4,510,914 752,970 5,468,897 5,284,184
Average Monthly Services 23,477 21,255 2,193 30 1,134 942 116
Indicated Rates -- Distribution
Tier 1 Energy $/therm $1.2274 $1.2616 $1.1616 $1.7506 $1.2643 $1.1892
Tier 2 Energy $/therm $1.8972
$/Customer/Month $19.52 $78.00 $1,713.67 $29.06 $94.94 $417.62
Total Revenue from Indicated Distribution Rates$41,268,342 $18,853,368 $16,568,614 $5,846,360 $1,713,540 $7,987,841 $6,867,232
% change in Distribution Revenues 15.6% 0.0% 15.0%-41.9%3.9%15.8%
% change in Distribution Revenues from Summary tab 15.6% 0.0% 15.0%-41.9%3.9%15.8%
Schedule 2.1 Page 2 of 2
Prepared By EES Consulting, Inc.Palo Alto Gas Utility
INPUT REVENUE REQUIREMENT
Schedule 3.1
Year Classification
2026 & Allocation
Cost, $Function Factor Classification & Allocation Method
Operation & Maintenance Expense
Rent Other Transfers $1,779,909 P therm Annual Energy (therm)
General Admin & Overhead $55,882 P therm Annual Energy (therm)
Commodity Admin & Overhead $410,622 P therm Annual Energy (therm)
Alternative Energy Programs $432,697 P therm Annual Energy (therm)
Supply Commodity $22,843,053 P therm Annual Energy (therm)
Supply Transportation $224,953 P therm Annual Energy (therm)
Total Gas Supply $25,747,117
Total Production $25,747,117
Distribution
Engineering Support $768,861 D RBD On the Basis of Distribution Rate Base
Operations & Maintenance $9,028,547 D RBD On the Basis of Distribution Rate Base
Total Distribution $9,797,408
Total Operation & Maintenance $35,544,526
Customer Service, Accounts, & Sales
Admin - Customer & Marketing $227,967 D CUSTW Customers Weighted for Accounting/Metering
Meter Reading $485,915 D CUSTM Customers Weighted for Meters and Services
Utility Billing $543,152 D CUSTW Customers Weighted for Accounting/Metering
Credit & Collections $9,850 D CUSTW Customers Weighted for Accounting/Metering
Key & Major Accounts $155,106 D DA1 Direct Assignment for Large Commercial
Customer Service $1,266,689 D CUSTW2 Customers Weighted for Accounting/Metering w/o G3
Low Income Programs $53,792 D therm Annual Energy (therm)
Efficiency - Demand Side Management $465,537 D therm Annual Energy (therm)
Total Customer Service, Accounts & Sales $3,208,008
Total O&M w/o Gas Supply & A&G $13,005,416
Administrative & General
Administrative & General Salaries $1,451,715 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G)
Allocated Charges $2,735,638 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G)
Rents $574,830 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G)
Transfers to Non-Enterprise Funds $59,411 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G)
Transfers to Enterprise Funds $181,333 SS OMAG On the Basis of O&M (w/o Gas Supply and A&G)
Total Administrative & General $5,002,927
Total O&M plus A&G $43,755,460
Interest and Debt Service Expense
Interest on Long-Term Debt $23,348 D NETPLT On the Basis of Net Plant
Principal on Long-Term Debt $778,250 D NETPLT On the Basis of Net Plant
System Improvement $7,538,046 D NETPLT On the Basis of Net Plant
Total Debt Service /CIP Expense $8,339,643
Schedule 3.1 Page 1 of 2
Prepared By EES Consulting, Inc.Palo Alto Gas Utility
INPUT REVENUE REQUIREMENT
Schedule 3.1
Year Classification
2026 & Allocation
Cost, $Function Factor Classification & Allocation Method
Operation & Maintenance Expense
General Fund Transfer $9,734,580 D REV On The Basis of Revenue
General Fund Transfer $9,734,580
Other Contributions
Supply Rate Stabilization Funding, portion to pay for supply cost $5,874,887 D therm Annual Energy (therm)
Reserves $5,874,887
Revenue Requirement Before Other Revenues $67,704,570
Revenue Req. Before Taxes and Other Revenues $67,704,570
Other Revenues
Customer Discounts -$318,105 D NETPLT On the Basis of Net Plant
Connection Fees $700,000 D NETPLT On the Basis of Net Plant
Misc. Revenue (Other)-$449,823 D NETPLT On the Basis of Net Plant
Transfer Credits $131,346 D NETPLT On the Basis of Net Plant
Income (Loss) from Equity Investments $625,693 D NETPLT On the Basis of Net Plant
Total Other Revenues $689,111
REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply $67,015,459
Schedule 3.1 Page 2 of 2
Prepared By EES Consulting, Inc.Palo Alto Gas Utility
Total PROJECTED PROJECTED
2021 FY FY FY FY FY
Expenses 2022 2023 2024 2025 2026
Operation & Maintenance Expense
Rent Other Transfers $1,119,866 $1,610,428 $1,497,489 $1,686,286 $1,676,884 $1,779,909
General Admin & Overhead $143,564 $94,776 $41,008 $46,428 $50,933 $55,882
Commodity Admin & Overhead $135,664 $215,572 $254,699 $341,219 $374,288 $410,622
Alternative Energy Programs $35,053 $229,201 $334,256 $358,209 $393,686 $432,697
Supply Commodity $12,749,972 $24,103,336 $45,926,133 $22,772,125 $23,488,300 $22,843,053
Supply Transportation $236,397 $128,324 $193,614 $193,138 $208,366 $224,953
Total Gas Supply $14,420,516 $26,381,637 $48,247,199 $25,397,406 $26,192,457 $25,747,117
Total Production $14,420,516 $26,381,637 $48,247,199 $25,397,406 $26,192,457 $25,747,117
Distribution
Engineering Support $570,710 $659,207 $515,334 $572,847 $710,430 $768,861
Operations & Maintenance $5,482,286 $5,930,678 $6,729,162 $7,629,575 $8,297,561 $9,028,547
Total Distribution $6,052,995 $6,589,885 $7,244,496 $8,202,422 $9,007,991 $9,797,408
Total Operation & Maintenance $20,473,511 $32,971,523 $55,491,694 $33,599,828 $35,200,449 $35,544,526
Customer Service, Accounts, & Sales
Admin - Customer & Marketing $161,317 $159,503 $172,850 $188,769 $207,439 $227,967
Meter Reading $338,268 $387,293 $405,687 $405,072 $443,606 $485,915
Utility Billing $351,402 $407,858 $430,968 $449,373 $494,035 $543,152
Credit & Collections $46,751 $4,091 $4,996 $8,446 $9,118 $9,850
Key & Major Accounts $116,248 $109,274 $91,876 $128,535 $141,192 $155,106
Customer Service $890,630 $968,054 $1,002,409 $1,084,631 $1,171,732 $1,266,689
Low Income Programs $12,024 $44,956 $47,739 $50,656 $53,792
Efficiency - Demand Side Management $417,254 $294,307 $309,345 $365,294 $436,300 $465,537
Total Customer Service, Accounts & Sales $2,321,869 $2,342,403 $2,463,086 $2,677,857 $2,954,078 $3,208,008
Total O&M w/o Gas Supply & A&G $8,374,864 $8,932,288 $9,707,582 $10,880,279 $11,962,069 $13,005,416
Administrative & General
Administrative & General Salaries $743,079 $1,116,047 $584,536 $624,362 $685,039 $1,451,715
Allocated Charges $1,527,854 $2,001,867 $1,897,412 $2,135,588 $2,715,918 $2,735,638
Rents $471,205 $481,000 $501,000 $526,050 $559,717 $574,830
Transfers to Non-Enterprise Funds $96,985 $115,443 $678,760 $54,929 $57,126 $59,411
Transfers to Enterprise Funds $414,965 $161,320 $171,100 $176,267 $181,333
Total Administrative & General $3,254,087 $3,875,677 $3,661,708 $3,512,028 $4,194,067 $5,002,927
Total O&M plus A&G $26,049,468 $39,189,602 $61,616,488 $39,789,714 $42,348,594 $43,755,460
Schedule 3.2
PROJECTED REVENUE REQUIREMENTS
Schedule 3.2 Page 1 of 2
Prepared By EES Consulting, Inc.Palo Alto Gas Utility
Total PROJECTED PROJECTED
2021 FY FY FY FY FY
Expenses 2022 2023 2024 2025 2026
Operation & Maintenance Expense
Schedule 3.2
PROJECTED REVENUE REQUIREMENTS
Interest and Debt Service Expense
Interest on Long-Term Debt $134,622 $108,488 $87,643 $66,144 $45,953 $23,348
Principal on Long-Term Debt $665,500 $693,000 $715,000 $734,250 $753,500 $778,250
System Improvement $9,282,688 $4,674,169 $10,216,894 $7,224,553 $3,682,185 $7,538,046
Total Debt Service /CIP Expense $10,082,810 $5,475,657 $11,019,537 $8,024,947 $4,481,638 $8,339,643
General Fund Transfer $6,847,000 $7,240,000 $6,683,000 $8,215,000 $10,917,195 $9,734,580
General Fund Transfer $6,847,000 $7,240,000 $6,683,000 $8,215,000 $10,917,195 $9,734,580
Other Contributions
Supply Rate Stabilization Funding, portion to pay for supply cost -$85,599 -$89,019 -$218,124 $10,407,418 $1,884,104 $5,874,887
Reserves -$85,599 -$89,019 -$218,124 $10,407,418 $1,884,104 $5,874,887
Revenue Requirement Before Other Revenues $42,893,678 $51,816,240 $79,100,901 $66,437,079 $59,631,530 $67,704,570
Revenue Req. Before Taxes and Other Revenues $42,893,678 $51,816,240 $79,100,901 $66,437,079 $59,631,530 $67,704,570
Other Revenues
Discounts/Uncollectables -$306,740 -$690,468 -$403,008 $625,296 $348,562 -$318,105
Connection Fees $840,231 $475,239 $413,841 $343,776 $700,000 $700,000
Misc. Revenue (Other)-$18,802 -$259,987 -$80,772 -$429,895 -$283,078 -$449,823
Reimbursements $160,332 $110,184 $110,738 $108,550 $119,405 $131,346
Income (Loss) from Equity Investments $479,407 $426,815 $502,344 $701,607 $610,432 $625,693
Total Other Revenues $1,154,428 $61,782 $543,144 $1,349,335 $1,495,321 $689,111
REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply $41,739,250 $51,754,458 $78,557,757 $65,087,745 $58,136,209 $67,015,459
Schedule 3.2 Page 2 of 2
Prepared By EES Consulting, Inc.
Allocation Date
2026 Direct Direct Direct
Total Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment
Expenses PE PDA TD TE TDA DD DE DC DDA
Operation & Maintenance Expense
Rent Other Transfers $1,779,909 $1,779,909
General Admin & Overhead $55,882 $55,882
Commodity Admin & Overhead $410,622 $410,622
Alternative Energy Programs $432,697 $432,697
Supply Commodity $22,843,053 $22,843,053
Supply Transportation $224,953 $224,953
Total Gas Supply $25,747,117 $25,747,117
Total Production $25,747,117 $25,747,117
Distribution
Engineering Support $768,861 $325,219 $382,685 $60,957
Operations & Maintenance $9,028,547 $3,818,970 $4,493,769 $715,808
Total Distribution $9,797,408 $4,144,190 $4,876,453 $776,765
Total Operation & Maintenance $35,544,526 $25,747,117 $4,144,190 $4,876,453 $776,765
Customer Service, Accounts, & Sales
Admin - Customer & Marketing $227,967 $227,967
Meter Reading $485,915 $485,915
Utility Billing $543,152 $543,152
Credit & Collections $9,850 $9,850
Key & Major Accounts $155,106 $155,106
Customer Service $1,266,689 $1,266,689
Low Income Programs $53,792 $53,792
Efficiency - Demand Side Management $465,537 $465,537
Total Customer Service, Accounts & Sales $3,208,008 $519,329 $2,533,573 $155,106
Total O&M w/o Gas Supply & A&G $13,005,416 $4,144,190 $5,395,782 $3,310,338 $155,106
Administrative & General
Administrative & General Salaries $1,451,715 $462,590 $602,298 $369,513 $17,314
Allocated Charges $2,735,638 $871,714 $1,134,982 $696,317 $32,626
Rents $574,830 $183,170 $238,489 $146,314 $6,856
Transfers to Non-Enterprise Funds $59,411 $18,931 $24,649 $15,122 $709
Transfers to Enterprise Funds $181,333 $57,782 $75,233 $46,156 $2,163
Total Administrative & General $5,002,927 $1,594,188 $2,075,651 $1,273,422 $59,666
Total O&M plus A&G $43,755,460 $25,747,117 $5,738,378 $7,471,433 $4,583,759 $214,773
Interest and Debt Service Expense
Interest on Long-Term Debt $23,348 $9,876 $11,621 $1,851
Principal on Long-Term Debt $778,250 $329,191 $387,358 $61,702
System Improvement $7,538,046 $3,188,506 $3,751,903 $597,637
Total Debt Service /CIP Expense $8,339,643 $3,527,572 $4,150,882 $661,190
General Fund Transfer $9,734,580 $7,503,283 $2,231,297
General Fund Transfer $9,734,580 $7,503,283 $2,231,297
Other Contributions
Supply Rate Stabilization Funding, portion to pay for supply cost$5,874,887 $5,874,887
Reserves $5,874,887 $5,874,887
Production Transmission Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 3.3
Schedule 3.3 Page 1 of 2
Prepared By EES Consulting, Inc.
Allocation Date
2026 Direct Direct Direct
Total Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment
Expenses PE PDA TD TE TDA DD DE DC DDA
Operation & Maintenance Expense
Production Transmission Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 3.3
Revenue Requirement Before Other Revenues $67,704,570 $25,747,117 $9,265,950 $25,000,484 $7,476,246 $214,773
Revenue Req. Before Taxes and Other Revenues $67,704,570 $25,747,117 $9,265,950 $25,000,484 $7,476,246 $214,773
Other Revenues
Customer Discounts -$318,105 -$134,555 -$158,330 -$25,220
Connection Fees $700,000 $296,092 $348,410 $55,498
Misc. Revenue (Other)-$449,823 -$190,270 -$223,890 -$35,663
Transfer Credits $131,346 $55,558 $65,375 $10,413
Income (Loss) from Equity Investments $625,693 $264,661 $311,426 $49,607
Total Other Revenues $689,111 $291,486 $342,991 $54,635
REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply$67,015,459 $25,747,117 $8,974,464 $24,657,494 $7,421,611 $214,773
REVENUE REQUIREMENT for COST ALLOCATION - Delivery $41,268,342 $8,974,464 $24,657,494 $7,421,611 $214,773
Schedule 3.3 Page 2 of 2
Prepared By EES Consulting, Inc.
Allocation Date
2026
Total
Expenses
Operation & Maintenance Expense G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Rent Other Transfers $1,779,909 $674,040 $311,450 $51,988 $377,592 $364,839
General Admin & Overhead $55,882 $21,162 $9,778 $1,632 $11,855 $11,455
Commodity Admin & Overhead $410,622 $155,500 $71,851 $11,993 $87,110 $84,168
Alternative Energy Programs $432,697 $163,860 $75,714 $12,638 $91,793 $88,693
Supply Commodity $22,843,053 $8,650,515 $3,997,094 $667,202 $4,845,958 $4,682,284
Supply Transportation $224,953 $85,188 $39,363 $6,570 $47,722 $46,110
Total Gas Supply $25,747,117 $9,750,265 $4,505,250 $752,024 $5,462,030 $5,277,548
Total Production $25,747,117 $9,750,265 $4,505,250 $752,024 $5,462,030 $5,277,548
Distribution
Engineering Support $768,861 $340,652 $113,249 $21,486 $153,082 $140,392
Operations & Maintenance $9,028,547 $4,000,190 $1,329,855 $252,308 $1,797,604 $1,648,590
Total Distribution $9,797,408 $4,340,842 $1,443,104 $273,794 $1,950,686 $1,788,982
Total Operation & Maintenance $35,544,526 $14,091,108 $5,948,353 $1,025,819 $7,412,716 $7,066,530
Customer Service, Accounts, & Sales
Admin - Customer & Marketing $227,967 $179,500 $6,727 $11,970 $23,872 $5,899
Meter Reading $485,915 $359,885 $12,636 $14,516 $65,859 $33,019
Utility Billing $543,152 $427,673 $16,027 $28,520 $56,878 $14,055
Credit & Collections $9,850 $7,756 $291 $517 $1,032 $255
Key & Major Accounts $155,106 $155,106
Customer Service $1,266,689 $1,027,704 $68,533 $136,678 $33,774
Low Income Programs $53,792 $20,371 $9,413 $1,571 $11,411 $11,026
Efficiency - Demand Side Management $465,537 $176,296 $81,460 $13,597 $98,760 $95,424
Total Customer Service, Accounts & Sales $3,208,008 $2,199,184 $281,658 $139,225 $394,490 $193,451
Total O&M w/o Gas Supply & A&G $13,005,416 $6,540,026 $1,724,762 $413,019 $2,345,175 $1,982,434
Administrative & General
Administrative & General Salaries $1,451,715 $730,023 $192,525 $46,103 $261,777 $221,287
Allocated Charges $2,735,638 $1,375,669 $362,797 $86,877 $493,298 $416,997
Rents $574,830 $289,064 $76,233 $18,255 $103,655 $87,622
Transfers to Non-Enterprise Funds $59,411 $29,876 $7,879 $1,887 $10,713 $9,056
Transfers to Enterprise Funds $181,333 $91,187 $24,048 $5,759 $32,699 $27,641
Total Administrative & General $5,002,927 $2,515,819 $663,482 $158,880 $902,143 $762,603
Total O&M plus A&G $43,755,460 $18,806,110 $6,893,493 $1,323,924 $8,709,348 $8,022,585
Interest and Debt Service Expense
Interest on Long-Term Debt $23,348 $10,344 $3,439 $652 $4,649 $4,263
REVENUE REQUIREMENT COST ALLOCATION
BY CUSTOMER
Schedule 3.4
Schedule 3.4 Page 1 of 2
Prepared By EES Consulting, Inc.
Allocation Date
2026
Total
Expenses
Operation & Maintenance Expense G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
REVENUE REQUIREMENT COST ALLOCATION
BY CUSTOMER
Schedule 3.4
Principal on Long-Term Debt $778,250 $344,812 $114,632 $21,749 $154,951 $142,107
System Improvement $7,538,046 $3,339,809 $1,110,312 $210,655 $1,500,842 $1,376,428
Total Debt Service /CIP Expense $8,339,643 $3,694,965 $1,228,383 $233,056 $1,660,442 $1,522,798
General Fund Transfer $9,734,580 $4,183,095 $1,303,244 $756,248 $1,970,979 $1,521,015
General Fund Transfer $9,734,580 $4,183,095 $1,303,244 $756,248 $1,970,979 $1,521,015
Other Contributions
Supply Rate Stabilization Funding, portion to pay for supply cost $5,874,887 $2,224,781 $1,027,992 $171,594 $1,246,307 $1,204,212
Reserves $5,874,887 $2,224,781 $1,027,992 $171,594 $1,246,307 $1,204,212
Revenue Requirement Before Other Revenues $67,704,570 $28,908,951 $10,453,112 $2,484,822 $13,587,075 $12,270,610
Revenue Req. Before Taxes and Other Revenues $67,704,570 $28,908,951 $10,453,112 $2,484,822 $13,587,075 $12,270,610
Other Revenues
Customer Discounts -$318,105 -$140,940 -$46,855 -$8,890 -$63,335 -$58,085
Connection Fees $700,000 $310,142 $103,106 $19,562 $139,372 $127,818
Misc. Revenue (Other)-$449,823 -$199,299 -$66,256 -$12,571 -$89,561 -$82,137
Transfer Credits $131,346 $58,194 $19,347 $3,671 $26,151 $23,983
Income (Loss) from Equity Investments $625,693 $277,220 $92,161 $17,485 $124,577 $114,250
Total Other Revenues $689,111 $305,318 $101,502 $19,258 $137,204 $125,830
REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply $67,015,459 $28,603,633 $10,351,610 $2,465,565 $13,449,871 $12,144,780
REVENUE REQUIREMENT for COST ALLOCATION - Delivery $41,268,342 $18,853,368 $5,846,360 $1,713,540 $7,987,841 $6,867,232
Schedule 3.4 Page 2 of 2
Prepared By EES Consulting, Inc.
Allocation Date
2026
Total
Expenses
Operation & Maintenance Expense G1 Residential
G3 Large
Commercial G2 Commercial G2 - Medium G2 - Large
Rent Other Transfers
General Admin & Overhead
Commodity Admin & Overhead
Alternative Energy Programs
Supply Commodity
Supply Transportation
Total Gas Supply
Total Production
Distribution
Engineering Support
Operations & Maintenance
Total Distribution
Total Operation & Maintenance
Customer Service, Accounts, & Sales
Admin - Customer & Marketing
Meter Reading
Utility Billing
Credit & Collections
Key & Major Accounts $155,106 $155,106
Customer Service
Low Income Programs
Efficiency - Demand Side Management
Total Customer Service, Accounts & Sales $155,106 $155,106
Total O&M w/o Gas Supply & A&G $155,106 $155,106
Administrative & General
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Schedule 3.5 Page 1 of 3
Prepared By EES Consulting, Inc.
Allocation Date
2026
Total
Expenses
Operation & Maintenance Expense G1 Residential
G3 Large
Commercial G2 Commercial G2 - Medium G2 - Large
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Administrative & General Salaries $17,314 $17,314
Allocated Charges $32,626 $32,626
Rents $6,856 $6,856
Transfers to Non-Enterprise Funds $709 $709
Transfers to Enterprise Funds $2,163 $2,163
Total Administrative & General $59,666 $59,666
Total O&M plus A&G $214,773 $214,773
Interest and Debt Service Expense
Interest on Long-Term Debt
Principal on Long-Term Debt
System Improvement
Total Debt Service /CIP Expense
General Fund Transfer
General Fund Transfer
Other Contributions
Supply Rate Stabilization Funding, portion to pay for supply cost
Reserves
Revenue Requirement Before Other Revenues $214,773 $214,773
Revenue Req. Before Taxes and Other Revenues $214,773 $214,773
Other Revenues
Customer Discounts
Connection Fees
Misc. Revenue (Other)
Schedule 3.5 Page 2 of 3
Prepared By EES Consulting, Inc.
Allocation Date
2026
Total
Expenses
Operation & Maintenance Expense G1 Residential
G3 Large
Commercial G2 Commercial G2 - Medium G2 - Large
REVENUE REQUIREMENT COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 3.5
Transfer Credits
Income (Loss) from Equity Investments
Total Other Revenues
REVENUE REQUIREMENT for COST ALLOCATION - With Gas Supply$214,773 $214,773
Schedule 3.5 Page 3 of 3
Prepared By EES Consulting, Inc.
Palo Alto Gas Utility
INPUT RATE BASE
Schedule 4.1
Year Classification
2022 & Allocation
Cost, $ Function Factor Classification & Allocation Method
FERC Account
Distribution Plant
56670 Equip-Meters $12,334,716 D CUSTM Customers Weighted for Meters and Services
56680 Equip-Services $59,109,371 D AE Average and Excess
56710 Equip-Misc $2,729,148 D AE Average and Excess
56840 Equipment-Regulators $976,067 D AE Average and Excess
56850 Equip-Distribution Mains $77,559,779 D AE Average and Excess
56860 Equip-Measuring $2,869,793 D AE Average and Excess
Total Distribution Plant $155,578,873
Total Transmission & Distribution $155,578,873
General Plant
56400 Building-Gen Plant $1,910,425 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
56700 Equip-Gen Plant $2,911,310 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible)
Total General Plant $4,821,735
Total Plant Before General Plant & Intangible $155,578,873
Total Gross Plant in Service $160,400,608
Less: Accumulated Depreciation
Distribution Plant $49,833,503 D RBD On the Basis of Distribution Rate Base
General Plant $3,812,789 D RBGP On the Basis of General Plant Rate Base
Total Accumulated Depreciation $53,646,292
Total Net Plant $106,754,316
Working Capital
1/8 O&M $2,251,043 D OMWOP On the Basis of O&M (w/o Purch. Gas Supply)
Total Working Capital $2,251,043
TOTAL RATE BASE $109,005,358
CWIP
Distribution Plant $6,127,014 D RBD On the Basis of Distribution Rate Base
General Plant $1,902,306 SS RBGP On the Basis of General Plant Rate Base
Total CWIP $8,029,320
TOTAL RATE BASE plus CWIP $117,034,679
Schedule 4.1 Page 1 of 1
Prepared By EES Consulting, Inc.
FERC Account
56670
56680
56710
56840
56850
56860
56400
56700
Direct
Total Demand Energy Customer Assignment
Account Description Rate Base DD DE DC DDA
Distribution Plant
Equip-Meters $12,334,716 $12,334,716
Equip-Services $59,109,371 $27,155,542 $31,953,829
Equip-Misc $2,729,148 $1,253,803 $1,475,345
Equipment-Regulators $976,067 $448,417 $527,650
Equip-Distribution Mains $77,559,779 $35,631,877 $41,927,902
Equip-Measuring $2,869,793 $1,318,417 $1,551,376
Total Distribution Plant $155,578,873 $65,808,054 $77,436,103 $12,334,716
Total Transmission & Distribution $155,578,873 $65,808,054 $77,436,103 $12,334,716
General Plant
Building-Gen Plant $1,910,425 $808,088 $950,874 $151,464
Equip-Gen Plant $2,911,310 $1,231,450 $1,449,043 $230,817
Total General Plant $4,821,735 $2,039,538 $2,399,917 $382,280
Total Plant Before General Plant & Intangible $155,578,873 $65,808,054 $77,436,103 $12,334,716
Total Gross Plant in Service $160,400,608 $67,847,592 $79,836,020 $12,716,996
Less: Accumulated Depreciation
Distribution Plant $49,833,503 $21,078,993 $24,803,575 $3,950,936
General Plant $3,812,789 $1,612,765 $1,897,735 $302,288
Total Accumulated Depreciation $53,646,292 $22,691,758 $26,701,310 $4,253,224
Total Net Plant $106,754,316 $45,155,834 $53,134,709 $8,463,772
Working Capital
RATE BASE FOR COST ALLOCATION
Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 4.2
Schedule 4.2 Page 1 of 2
Prepared By EES Consulting, Inc.
FERC Account
Direct
Total Demand Energy Customer Assignment
Account Description Rate Base DD DE DC DDA
RATE BASE FOR COST ALLOCATION
Distribution
FUNCTIONALIZATION AND CLASSIFICATION
Schedule 4.2
1/8 O&M $2,251,043 $717,297 $933,929 $572,970 $26,847
Total Working Capital $2,251,043 $717,297 $933,929 $572,970 $26,847
TOTAL RATE BASE $109,005,358 $45,873,132 $54,068,638 $9,036,742 $26,847
CWIP
Distribution Plant $6,127,014 $2,591,656 $3,049,592 $485,766
General Plant $1,902,306 $804,653 $946,833 $150,820
Total CWIP $8,029,320 $3,396,309 $3,996,425 $636,586
TOTAL RATE BASE plus CWIP $117,034,679 $49,269,441 $58,065,063 $9,673,328 $26,847
Schedule 4.2 Page 2 of 2
Prepared By EES Consulting, Inc.
FERC Account
56670
56680
56710
56840
56850
56860
56400
56700
Palo Alto Gas Utility - Average and Excess Method (AE)
Account Description Total Rate Base G1 Residential G2 Commercial
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Distribution Plant
Equip-Meters $12,334,716 $9,135,516 $2,878,448 $320,752 $368,469 $1,671,799 $838,180
Equip-Services $59,109,371 $24,674,393 $25,111,143 $9,323,835 $1,642,039 $12,092,352 $11,376,752
Equip-Misc $2,729,148 $1,139,245 $1,159,411 $430,492 $75,815 $558,318 $525,278
Equipment-Regulators $976,067 $407,446 $414,658 $153,963 $27,115 $199,680 $187,863
Equip-Distribution Mains $77,559,779 $32,376,261 $32,949,339 $12,234,179 $2,154,585 $15,866,861 $14,927,893
Equip-Measuring $2,869,793 $1,197,956 $1,219,160 $452,677 $79,722 $587,090 $552,348
Total Distribution Plant $155,578,873 $68,930,816 $63,732,158 $22,915,899 $4,347,745 $30,976,100 $28,408,313
Total Transmission & Distribution $155,578,873 $68,930,816 $63,732,158 $22,915,899 $4,347,745 $30,976,100 $28,408,313
General Plant
Building-Gen Plant $1,910,425 $846,434 $782,597 $281,395 $53,388 $380,370 $348,839
Equip-Gen Plant $2,911,310 $1,289,886 $1,192,604 $428,820 $81,358 $579,648 $531,598
Total General Plant $4,821,735 $2,136,319 $1,975,201 $710,215 $134,746 $960,018 $880,437
Total Plant Before General Plant & Intangible $155,578,873 $68,930,816 $63,732,158 $22,915,899 $4,347,745 $30,976,100 $28,408,313
Total Gross Plant in Service $160,400,608 $71,067,135 $65,707,359 $23,626,113 $4,482,492 $31,936,118 $29,288,750
Less: Accumulated Depreciation
Distribution Plant $49,833,503 $22,079,245 $20,414,062 $7,340,197 $1,392,627 $9,921,961 $9,099,473
General Plant $3,812,789 $1,689,295 $1,561,891 $561,602 $106,551 $759,135 $696,206
Total Accumulated Depreciation $53,646,292 $23,768,540 $21,975,953 $7,901,799 $1,499,178 $10,681,096 $9,795,679
Total Net Plant $106,754,316 $47,298,595 $43,731,406 $15,724,314 $2,983,314 $21,255,022 $19,493,071
Working Capital
1/8 O&M $2,251,043 $1,131,981 $820,532 $298,530 $71,487 $405,915 $343,130
Total Working Capital $2,251,043 $1,131,981 $820,532 $298,530 $71,487 $405,915 $343,130
TOTAL RATE BASE $109,005,358 $48,430,576 $44,551,938 $16,022,845 $3,054,801 $21,660,936 $19,836,201
CWIP
Distribution Plant $6,127,014 $2,714,637 $2,509,903 $902,475 $171,223 $1,219,902 $1,118,777
RATE BASE COST ALLOCATION
CLASSIFICATION BY CUSTOMER
Schedule 4.3
Schedule 4.3 Page 1 of 2
Prepared By EES Consulting, Inc.
FERC Account
Palo Alto Gas Utility - Average and Excess Method (AE)
Account Description Total Rate Base G1 Residential G2 Commercial
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
RATE BASE COST ALLOCATION
CLASSIFICATION BY CUSTOMER
Schedule 4.3
General Plant $1,902,306 $842,836 $779,271 $280,199 $53,161 $378,753 $347,356
Total CWIP $8,029,320 $3,557,473 $3,289,173 $1,182,674 $224,384 $1,598,655 $1,466,134
TOTAL RATE BASE plus CWIP $117,034,679 $51,988,048 $47,841,112 $17,205,519 $3,279,185 $23,259,592 $21,302,334
Schedule 4.3 Page 2 of 2
Prepared By EES Consulting, Inc.
FERC Account
56670
56680
56710
56840
56850
56860
56400
56700
Palo Alto Gas Utility - Average and Excess Method (AE)
Account Description Total Rate Base G1 Residential G2 - All
G3 Large
Commercial
Distribution Plant
Equip-Meters
Equip-Services
Equip-Misc
Equipment-Regulators
Equip-Distribution Mains
Equip-Measuring
Total Distribution Plant
Total Transmission & Distribution
General Plant
Building-Gen Plant
Equip-Gen Plant
Total General Plant
Total Plant Before General Plant & Intangible
Total Gross Plant in Service
Less: Accumulated Depreciation
Distribution Plant
General Plant
Total Accumulated Depreciation
RATE BASE COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 4.4
Schedule 4.4 Page 1 of 2
Prepared By EES Consulting, Inc.
FERC Account
Palo Alto Gas Utility - Average and Excess Method (AE)
Account Description Total Rate Base G1 Residential G2 - All
G3 Large
Commercial
RATE BASE COST ALLOCATION
DIRECT ASSIGNMENT BY CUSTOMER
Schedule 4.4
Total Net Plant
Working Capital
1/8 O&M $26,847 $26,847
Total Working Capital $26,847 $26,847
TOTAL RATE BASE $26,847 $26,847
CWIP
Distribution Plant
General Plant
Total CWIP
TOTAL RATE BASE plus CWIP $26,847 $26,847
Schedule 4.4 Page 2 of 2
Prepared By EES Consulting, Inc.
Palo Alto Gas Utility
2025 Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Number of Customers
Jul-25 23,735 21,503 - 30 1,145 939 118
Aug-25 23,936 21,690 - 30 1,152 947 117
Sep-25 22,632 20,404 - 30 1,134 946 118
Oct-25 23,790 21,558 - 31 1,138 946 117
Nov-25 23,694 21,474 - 28 1,136 940 116
Dec-25 23,391 21,178 - 30 1,129 940 114
Jan-26 23,752 21,508 - 30 1,147 950 117
Feb-26 23,158 20,947 - 31 1,120 949 111
Mar-26 23,636 21,443 - 29 1,124 927 113
Apr-26 23,117 20,894 - 29 1,137 937 120
May-26 23,218 21,012 - 28 1,118 943 117
Jun-26 23,663 21,446 - 28 1,127 943 119
Total / Average 23,477 21,255 30 1,134 942 116
Customer Charge Revenues Rate: $/Month $16.93 $156.90 $717.89 $156.90 $156.90 $156.90
Jul-25 $731,072 $364,041 $21,537 $179,651 $147,329 $18,514
Aug-25 $736,432 $367,205 $21,537 $180,749 $148,584 $18,357
Sep-25 $711,845 $345,442 $21,537 $177,925 $148,427 $18,514
Oct-25 $732,576 $364,984 $22,255 $178,552 $148,427 $18,357
Nov-25 $727,586 $363,561 $20,101 $178,238 $147,486 $18,200
Dec-25 $722,593 $358,544 $21,537 $177,140 $147,486 $17,887
Jan-26 $733,050 $364,137 $21,537 $179,964 $149,055 $18,357
Feb-26 $718,925 $354,629 $22,255 $175,728 $148,898 $17,416
Mar-26 $723,386 $363,035 $20,819 $176,356 $145,446 $17,730
Apr-26 $718,787 $353,729 $20,819 $178,395 $147,015 $18,828
May-26 $717,560 $355,730 $20,101 $175,414 $147,957 $18,357
Jun-26 $726,641 $363,086 $20,101 $176,826 $147,957 $18,671
Total $8,700,453 $4,318,124 $254,133 $2,134,938 $1,774,068 $219,189
Forecast Therms
Jul-25 1,295,010 329,344 - 311,858 39,430 305,711 308,667
Aug-25 1,202,729 297,815 - 299,554 44,035 281,424 279,902
Sep-25 1,183,613 302,266 - 281,717 37,800 287,018 274,812
Oct-25 1,394,195 383,267 - 313,156 49,422 353,322 295,027
Nov-25 1,873,214 770,841 - 344,487 42,632 332,849 382,405
FORECAST OF REVENUES FROM CURRENT RATES
Schedule 7.1
Schedule 7.1 Page 1 of 3
Prepared By EES Consulting, Inc.
2025 Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
FORECAST OF REVENUES FROM CURRENT RATES
Schedule 7.1
Dec-25 2,856,282 1,300,253 - 399,645 81,682 561,375 513,328
Jan-26 3,583,858 1,659,415 - 492,602 93,535 701,266 637,041
Feb-26 3,163,932 1,396,643 - 449,567 92,845 641,953 582,923
Mar-26 3,103,871 1,366,526 - 444,411 88,902 619,516 584,516
Apr-26 2,609,800 927,315 - 443,470 76,982 557,552 604,479
May-26 1,960,064 614,608 - 391,055 57,905 448,156 448,340
Jun-26 1,552,922 414,232 - 339,393 47,798 378,755 372,743
Total / Average 25,779,489 9,762,524 - 4,510,914 752,970 5,468,897 5,284,184
Energy Rates
Flat Rate:Flat Rate $/Therm $1.08090 $1.07020 $1.08090 $1.08090 $1.08090
1st Block $/Therm $0.822900
2nd Block $/Therm $2.104300
3rd Block $/Therm
4th Block $/Therm
Energy Revenues
Jul-25 $1,404,271 $363,820 $333,750 $42,620 $330,443 $333,638
Aug-25 $1,290,245 $315,328 $320,583 $47,598 $304,191 $302,546
Sep-25 $1,281,178 $331,544 $301,493 $40,859 $310,238 $297,044
Oct-25 $1,568,687 $479,325 $335,140 $53,421 $381,906 $318,895
Nov-25 $2,114,273 $926,405 $368,670 $46,081 $359,776 $413,341
Dec-25 $3,200,805 $1,523,169 $427,700 $88,290 $606,791 $554,856
Jan-26 $4,280,735 $2,205,875 $527,182 $101,102 $757,999 $688,578
Feb-26 $3,631,914 $1,726,462 $481,126 $100,357 $693,887 $630,082
Mar-26 $3,480,774 $1,607,633 $475,609 $96,094 $669,635 $631,803
Apr-26 $2,968,472 $1,154,620 $474,602 $83,210 $602,658 $653,382
May-26 $2,322,725 $872,606 $418,507 $62,589 $484,412 $484,611
Jun-26 $1,713,329 $486,150 $363,219 $51,665 $409,397 $402,898
Subtotal $29,257,410 $11,992,939 $4,827,580 $813,885 $5,911,331 $5,711,674
Surcharge
Total $29,257,410 $11,992,939 $4,827,580 $813,885 $5,911,331 $5,711,674
Schedule 7.1 Page 2 of 3
Prepared By EES Consulting, Inc.
2025 Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
FORECAST OF REVENUES FROM CURRENT RATES
Schedule 7.1
Total Revenues - Distribution G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Jul-25 $2,135,343 $727,861 $355,287 $222,271 $477,772 $352,152
Aug-25 $2,026,677 $682,533 $342,119 $228,346 $452,775 $320,903
Sep-25 $1,993,023 $676,986 $323,030 $218,783 $458,665 $315,558
Oct-25 $2,301,263 $844,310 $357,394 $231,973 $530,333 $337,252
Nov-25 $2,841,860 $1,289,965 $388,771 $224,320 $507,262 $431,542
Dec-25 $3,923,399 $1,881,713 $449,236 $265,430 $754,277 $572,743
Jan-26 $5,013,786 $2,570,013 $548,719 $281,066 $907,054 $706,935
Feb-26 $4,350,840 $2,081,091 $503,381 $276,085 $842,785 $647,498
Mar-26 $4,204,160 $1,970,668 $496,427 $272,450 $815,081 $649,533
Apr-26 $3,687,259 $1,508,350 $495,421 $261,605 $749,674 $672,210
May-26 $3,040,284 $1,228,337 $438,608 $238,004 $632,369 $502,968
Jun-26 $2,439,970 $849,236 $383,320 $228,491 $557,353 $421,569
Subtotal $37,957,863 $16,311,063 $5,081,713 $2,948,824 $7,685,399 $5,930,863
Surcharge
Total $37,957,863 $16,311,063 $5,081,713 $2,948,824 $7,685,399 $5,930,863
Schedule 7.1 Page 3 of 3
Prepared By EES Consulting, Inc.
Forecast Rate Class Customer Count Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Jul-25 23,735 21,503 30 1,145 939 118
Aug-25 23,936 21,690 30 1,152 947 117
Sep-25 22,632 20,404 30 1,134 946 118
Oct-25 23,790 21,558 31 1,138 946 117
Nov-25 23,694 21,474 28 1,136 940 116
Dec-25 23,391 21,178 30 1,129 940 114
Jan-26 23,752 21,508 30 1,147 950 117
Feb-26 23,158 20,947 31 1,120 949 111
Mar-26 23,636 21,443 29 1,124 927 113
Apr-26 23,117 20,894 29 1,137 937 120
May-26 23,218 21,012 28 1,118 943 117
Jun-26 23,663 21,446 28 1,127 943 119
Total Average Forecast Customers 23,477 21,255 30 1,134 942 116
Schedule 8.1 Page 1 of 2
Prepared By EES Consulting, Inc.
Customer Information Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Weighting Factors for:
Customers Meters & Services 414.00$ 1,262.00$ 10,473.00$ 313.00$ 1,709.00$ 6,935.00$
Customer Billing and Collection 1.00 1.25 27.00 1.25 3.00 6.00
Customer Billing and Collection w/o G3 1.00 1.25 1.25 3.00 6.00
Weighted Number of Customers
Customers Meters & Services 11,881,010 8,799,486 - 308,954 354,916 1,610,305 807,350
Customer Billing and Collection 26,994 21,255 - 797 1,417 2,827 699
Customer Billing and Collection w/o G3 26,197 21,255 - - 1,417 2,827 699
Test Date Forecast Rate Class Sales therm Total G1 Residential G2 - All
G3 Large
Commercial G2 - Small G2 - Medium G2 - Large
Jul-25 1,295,010 329,344 311,858 39,430 305,711 308,667
Aug-25 1,202,729 297,815 299,554 44,035 281,424 279,902
Sep-25 1,183,613 302,266 281,717 37,800 287,018 274,812
Oct-25 1,394,195 383,267 313,156 49,422 353,322 295,027
Nov-25 1,873,214 770,841 344,487 42,632 332,849 382,405
Dec-25 2,856,282 1,300,253 399,645 81,682 561,375 513,328
Jan-26 3,583,858 1,659,415 492,602 93,535 701,266 637,041
Feb-26 3,163,932 1,396,643 449,567 92,845 641,953 582,923
Mar-26 3,103,871 1,366,526 444,411 88,902 619,516 584,516
Apr-26 2,609,800 927,315 443,470 76,982 557,552 604,479
May-26 1,960,064 614,608 391,055 57,905 448,156 448,340
Jun-26 1,552,922 414,232 339,393 47,798 378,755 372,743
Total Sales 25,779,489 9,762,524 4,510,914 752,970 5,468,897 5,284,184
Schedule 8.1 Page 2 of 2
Prepared By EES Consulting, Inc.
Calculation of AE Allocation Method
Total G1 Residential
G3 Large
Commercial G2 Small G2 Medium G2 Large
Annual Sales, Therms 25,779,489 9,762,524 4,510,914 752,970 5,468,897 5,284,184
Jul-25 1,741 443 419 53 411 415
Aug-25 1,790 443 446 66 419 417
Sep-25 1,591 406 379 51 386 369
Oct-25 1,936 532 435 69 491 410
Nov-25 2,518 1,036 463 57 447 514
Dec-25 3,967 1,806 555 113 780 713
Jan-26 4,817 2,230 662 126 943 856
Feb-26 4,253 1,877 604 125 863 783
Mar-26 4,311 1,898 617 123 860 812
Apr-26 3,508 1,246 596 103 749 812
May-26 2,722 854 543 80 622 623
Jun-26 2,087 557 456 64 509 501
Min therm/hr 1,591 406 379 51 386 369
Max therm/hr 4,817 2230 662 126 943 856
Share of max therms 100%46%14%3%20%18%
Min Therms 13,936,088 3,558,936 3,316,990 445,070 3,379,404 3,235,688
100%26%24%3%24%23%
Excess therms 11,843,401 6,203,589 1,193,924 307,900 2,089,494 2,048,495
100%52%10%3%18%17%
Average Use 2,937 1,111 515 86 623 602
Excess Use 4,817 2,230 662 126 943 856
Average + Excess 7,754 3,341 1,177 212 1,566 1,458
43%15%3%20%19%
Customer or Minimum Therms 54%36%74%59%62%61%
Demand 46% 64% 26% 41% 38% 39%
Tier 1 6,672,656 68%36%
Tier 2 3,089,869
Tier 1 Demand Costs 54.4%
Schedule 6.5 Page 1 of 1
April 15, 2025 www.cityofpaloalto.org
FY 2026 Gas Rate Proposal
Finance Committee
2
Residential Median Bill Projections (Bill $ and % change from prior year)
1)FY 2025 incorporates results of cost-of-service analysis
2)Gas rate in FY 2026 based on General Fund transfer of 18% of gross revenue in FY 2024; changes shown with commodity rates held constant; actual gas
commodity rates vary monthly; FY 2026 incorporates results of cost-of-service analysis
3)Stormwater fees increase by CPI index annually per approved 2017 ballot measure (2.6% in FY 2025)
4)Based on projected FY 2025 monthly residential bill of $404
3
Residential Median Bill Projections w/ Climate Credit (Bill $ and % change from prior year)
1)FY 2025 incorporates results of cost-of-service analysis
2)Gas rate in FY 2026 based on General Fund transfer of 18% of gross revenue in FY 2024; changes shown with commodity rates held constant; actual gas
commodity rates vary monthly; FY 2026 incorporates results of cost-of-service analysis
3)Stormwater fees increase by CPI index annually per approved 2017 ballot measure (2.6% in FY 2025)
4)Based on projected FY 2025 monthly residential bill of $404
Utilities Advisory
Commission
Recommends a
Climate Credit:
One-time flat $73.20
credit to residential
G-1 customers only.
The total cost is
about $1.6M from
the Cap-and-Trade
Reserve, enough to
fund whole home
electrification
incentives for about
182 homes.
4
Proposal
•5% overall average rate increase in FY 2026, assuming no change in supply costs;
individual customer rate increases vary depending on customer class and usage
•Cost of Service Analysis completed February 2025 – requires rate changes varying by
customer class to match the cost to serve
•22% ($15.20/month) bill increase for median residential customer
•-53.6% ($121.44/month) bill decrease for small residential master-metered and
business customers
Drivers
•Reserve replenishment, labor, allocated charges, cross-bore program
•Federal grant of $16.5 million expected to fund CIP work including main replacement
•Gas General Fund Transfer in FY 2026 estimated at $9.735M, (18% of FY 2024 gross
revenue)
Compared with Preliminary Rates
•Lowered overall average rate increase from 6% to 5%
•Cost of Service Analysis results incorporated, residential and large commercial
expected to see increases
Gas Rate Proposal
Note: excludes supply-related rate changes
5
FY 2026 Rate Increase Drivers
Calculation Notes:
•Rate increases based on projected FY 2026 revenues
apportioned by 4-year average of actual costs
•Rate increases apply to sales revenue; Revenue includes some
non-rate revenue.
1.5%
-5.1%
3.8%
5.2%
-6%
-4%
-2%
0%
2%
4%
6%
8%
10%
12%
Total 5.4% Rate Increase
Replenish Reserves $2.2 million
Operating Expenses $1.6 million
$1.4 million Labor -more filled positions, cost-of-living
adjustment, merit increases
$ 0.5 million Crossbore & Mandatory Programs
$ 0.3 million Allocated Charges
-$ 0.2 million Debt Service
-$ 0.3 million Transfers
General Fund Transfer $0.7 million
CIP -$2.2 million
CIP is primarily funded by the federal grant; lower
budget because FY26 is a project planning year
0%
This chart explains the rate increase drivers for the
overall average rate increase. Additional cost of
service adjustments by customer class are required.
6
Gas Cost and Revenue Projections
*FY25 Commitments and Reappropriations
reserves balances for Operations and
Capital Investment are anticipated to be
utilized in FY26 and FY27
**Revenues and Expenses excludes Cap-
and-Trade auction sales revenue, which
goes directly to the Cap-and-Trade reserve
***The grant-funded $16.5M CIP project is
anticipated to be under construction in
FY26 and FY27
6
Reserve Maximum
Reserve Target
Reserve Minimum
Risk Assessment
0
5
10
15
20
25
30
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actuals Projection
$
Mi
l
l
i
o
n
s
Fiscal Year
Reserve (Year-End)
7
Gas Operations Reserve Projections
8
Basic Cost of Service Methodology
•First establish how much revenue you need
•Then use consumption patterns to allocate costs among
customer classes according to how they incur utility costs
•CPA classes: G-1 (residential), G-2 (small commercial and multi-
family master-metered), G-3 (large commercial) and G-10 (CNG
Station)
•Costs allocators include things like therms used, number of
customers in class
•Then design rates that provide prices that allocate costs to
customers who consume in different ways.
•Examples include tiered rates, seasonal rates, fixed charges, etc.
9
Prop 26 Considerations
•Prop 26 (2010): State ballot initiative that amended the State
Constitution
•Gas and electric rates must represent the cost of service
absent voter/ratepayer approval
•Cost of service analysis is the record demonstrating that the
rates are cost-based
•Only applies to fees/charges imposed by local agencies
(including gas/electric utility rates) – investor-owned utilities
have all the latitude the CPUC will give them
10
Gas Bill Comparisons Proposed Rates FY 2026 ($/Mo.)
With UAC Recommended Climate Credit for Palo Alto Residents
Residential
Commercial and Multi-Family Master-Metered
Note:
•FY 2026 rates calculated assuming
no change to supply-related rates;
PG&E transportation rates as of
January 1, 2025
•FY 2025 rates calculated based on
actuals and projected rates
•PG&E bills are calculated using
Climate Zone X
•Palo Alto and PG&E bills include a
climate credit for residential
•G-2 bills are calculated based on
the median usages for each meter
capacity group
FY 2025
(Current)
FY 2025
(Current)
11
Communication and Outreach
Key Messages
•Reasons for rate increases and benefits to customers
•Competitive rates to other utilities and neighboring cities
•What the City is doing to keep costs down
•City programs and services to help customers keep utility bill
costs low
Outreach Strategies
•Public Meetings: UAC, Finance, City Council
•Digital Communication:website, social media,
email newsletters, City blog, videos
•Direct Mail: utility bill inserts,Proposition 218 notice,
SFPUC rates postcard
•Local Media Engagement: articles, interviews
Utility bill insert about gas safety
Installing new gas pipe for the Gas Main
Replacement Project #24B
12
Recommendation
Staff and UAC Recommendation:
The Finance Committee recommends that the City Council adopt a resolution:
1. Approving the Fiscal Year 2026 Gas Utility Financial Forecast;
2. Approving the transfer of up to $1.5 million from the Gas Utility Operations Reserve to the Distribution
Rate Stabilization Reserve at the end of FY 2025;
3. Approving the Natural Gas Cost of Service and Rate Study;
4. Transferring up to 18% of gas utility gross revenues received during FY 2024 to the General Fund in FY
2026;
5.Increasing distribution rates by 8.7% (for an estimated 5.4% increase to overall rates) for FY 2026 by
amending Rate Schedules;
a.G-1 Residential Gas Service,
b.G-2 Residential Master-Metered and Commercial Gas Service,
c.G-3 Large Commercial Gas Service, and
d.G-10 Compressed Natural Gas Service;
UAC Recommendation:
6. The Finance Committee recommends that the City Council approve the use of approximately $1.6
million of Cap-and-Trade allowance auction proceeds to provide a one-time flat credit of $73.20 to
each residential G-1 customer only in FY 2026.