HomeMy WebLinkAboutStaff Report 10255
City of Palo Alto (ID # 10255)
Finance Committee Staff Report
Report Type: Action Items Meeting Date: 5/15/2019
City of Palo Alto Page 1
Council Priority: Fiscal Sustainability
Summary Title: FY 2020 Gas Financial Plan and Rates
Title: Utilities Advisory Commission Recommendation that the City Council
Adopt: 1) a Resolution Approving the Fiscal Year 2020 Gas Utility Financial
Plan; and 2) a Resolution Increasing Gas Rates by 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)
From: City Manager
Lead De partment: Utilities
RECOMMENDATION
Staff requests that the Finance Committee recommend that the City Council:
1. Adopt a resolution (Attachment A) approving the fiscal year (FY) 2020 Gas Utility
Financial Plan (Attachment B) and reserve transfers; and
2. Adopt a resolution (Attachment C) increasing gas rates by 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) (Attachment D).
EXECUTIVE SUMMARY
The FY 2020 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for
FY 2020 through FY 2024. Gas utility costs are made up of supply -related costs (35 percent of
costs) and distribution-related costs (65 percent of costs). Supply-related costs (and customer
rates) vary monthly with the gas markets, but customer rates for gas distribution are evaluated
annually and set by Council action like other utility rates. Gas rates related to distribution costs
were last increased by 6 percent on July 1, 2018. The proposed FY 2020 Gas Utility Financial
Plan includes an 8 percent increase in distribution rates on July 1, 2019. Because distribution
accounts for only 65 percent of the average customer’s bill, this is projected to increase system
rate revenues (and billings) by approximately 5 percent overall. Further distribution increases of
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5 percent to 12 percent are projected over the following four years (with a 4 percent to 8
percent increase in overall gas rates).
In addition, the plan proposes transfers to the Operations Reserve of $6.3 million from the Rate
Stabilization Reserve, and up to $6 million to the CIP Reserve from the Operations Reserve, to
ensure that there are appropriate financial reserves for contingencies. The Rate Stabilization
Reserve is projected to be at zero balance by the end of FY 2020.
In their analysis and development of the 2019 Natural Gas Cost of Service and Rates Study, staff
and the consultants have identified a realignment in cost allocations required for the gas
customer rate classes. While the distribution rate increase across all customer classes is
proposed to be 8 percent, the residential (G1) class will see a larger increase of 13.25 percent,
while the commercial classes (G2 and G3) will see between a 2.87 and 5.07 percent increase,
respectively, as detailed below. These correspond to an overall rate increase (including supply)
of8.1 percent for residential and of 3.0 and 1.5 percent for the two commercial classes These
cost shifts between customer classes are a result of in creased fixed costs, declining customer
usage and shifts to how customers use the gas system .
Figure 1 below shows the primary drivers for the proposed rate change: first, Capital
Improvement (CIP) cost are increasing, followed by increases in Operations expenses, and
finally, a portion of the increase can also be attributed to an anticipated decrease in usage,
which is consistent with long term trends. These increases will be discussed in greater depth
below:
Figure 1: Allocation of Distribution Rate increase
Supply-related costs (the cost of the natural gas itself, gas transmission, and gas environmental
charges) are the most volatile component of the Gas Utility’s expenses, and recent gas market
spikes and proposed transmission rate hikes have led staff to project supply cost increases of
around 4 percent annually for the forecast horizon. Market prices, however, are monitored
from month to month and automatically incorporated into monthly supply ra te adjustments.
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Therefore, it is not possible to exactly predict what supply rates will be during the planning
horizon. However, if staff’s forecast held, it would result in a 1 percent to 2 percent increase to
customer bills. Where overall rate increases (supply plus distribution) are referenced in this
report, the figures do not attempt to predict or include any supply rate increase that will occur
as a result of the monthly supply rate adjustments.
BACKGROUND
Every year staff presents the Utilities Advisory Commission and Finance Committee with
Financial Plans for its Electric, Water, Gas, and Wastewater Collection Utilities and recommends
any rate adjustments required to maintain their financial health. These Financial Plans include a
comprehensive overview of the utility’s operations, both retrospective and prospective, and are
intended to be a reference for UAC and Council members as they review the budget and staff’s
rate recommendations. Each Financial Plan also contains a set of Reserves Management
Practices describing the reserves for each utility and the management practices for those
reserves.
The City’s gas is purchased from a variety of marketers who source gas from throughout the
Western United States. The City then pays Pacific Gas and Elect ric (PG&E) to transmit that gas
across its gas transmission system to Palo Alto, and the gas is then delivered to customers
through the system of gas mains and services that make up the City’s gas distribution system.
The Gas Utility’s costs can be divided into two main categories: gas supply costs (which includes
the cost of the gas itself, the cost of transmitting the gas to Palo Alto, and environmental costs 1)
and the costs of running the business and operating the distribution system. As noted above,
gas supply costs vary with the market, and the costs are passed through to customers through a
gas supply rate component that varies monthly.
The UAC reviewed preliminary financial forecasts at its February 6, 2019 meeting and final
forecasts at its May 1, 2019 meeting. The Finance Committee reviewed preliminary gas
forecasts at its April 2, 2019 meeting. At that meeting, a Committee member requested an
overview of the gas hedging program and that it is available in Attachment E.
1 This is primarily the cost of complying with the State’s Cap and Trade system and procuring offsets under the
City’s Carbon Neutral Gas program.
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DISCUSSION
Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure
adequate revenue to fund operations and to document that the City’s rates do not exceed the
level permitted under California Constitution (Proposition 26). The assessment includes making
long-term projections of market conditions, of costs associated with the physical condition of
infrastructure, and of other factors that could affect utility costs. Rates are then proposed that
will be adequate to recover projected costs.
Proposed Actions for FY 2020
The FY 2020 Gas Utility Financial Plan includes the following proposed actions:
1. Amend gas rate schedules (see Attachment D) to increase distribution rates by
approximately 8 percent (a 5 percent increase on overall rates).
2. Transfer up to $6.3 million from the Rate Stabilization Reserve (RSR) to the Operations
Reserve, and up to $6 million from the Operations Reserve to the CIP Reserve.
The reserve transfers will enable staff to both maintain sufficient funds in the Gas Operations
Reserve while providing funds for CIP projects which will be occurring every other year, as
discussed below. These proposed actions are described in more detail in the FY 2020 Gas
Financial Plan (Attachment B).
Proposed Gas Rates and Cost of Service Update
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s proposed rates are based on the methodology from the draft
April 2019 Natural Gas Cost of Service and Rates Study, the final version to be presented to
Council in June. The methodology used was similar to the prior study performed in April 2012
by Utility Financial Solutions2, utilizing the average and excess method for allocating costs, and
updated to reflect current infrastructure asset values, annual utility costs, and some changes in
consumption patterns between customer classes seen in the post drought era. Because the
majority of gas costs are fixed, the consultant recommended (and staff accepted) shifting a
share of costs currently included in the volumetric (per therm) rate over to the base (per
account per month) rates. This increase in base rates by 22 percent (for G1), 26.6 percent (for
G2) and 72.6 percent (for G3), while creating savings in the volumetric rates. The study was
performed in conformance with the scope previously discussed with the Utilities Advisory
Commission in October 2016, and the Council in November 20163.
The COSA estimates a net distribution revenue requirement of $24,098,000 for FY 2020. It
further estimates that the existing rates would generate $22,313,072 in distribution revenues
for FY 2020. An 8 percent increase in distribution rates is necessary to recover this deficiency.
2 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
3 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
City of Palo Alto Page 5
Figure 2: Cost of Service Summary
Figure 2 above outlines how these revenue requirements and distribution charges are allocated
amongst the three gas customer classes.
The updated COSA allocates $10,111,795 of the net distribution revenue requirement to the
Residential (G1) customer class. This is 42 percent of the total net distribution revenue
requirement; a similar percentage to that found in the 2012 COSA. Under the current rate
structure, however, G1 customers would provide only about 40 percent of overall distribution
rate revenue. This is because energy consumption per G1 customer has decreased by roughly
10 percent since the 2012 COSA, while fixed costs allocated to the customer class have not
decreased at the same rate. Resetting G1 distribution revenues to comprise 42 percent of
system-wide distribution revenues requires that G1 distribution revenues be increased by 13.25
percent.
For Small Commercial (G2) customers, per customer usage has also decreased by roughly 10
percent, but because of the higher usage of G2 customers their fixed costs are a smalle r share
of total costs, and the increase in the per -unit cost for the class is smaller than for the
Residential class. The Large Commercial (G3) group has seen a growth in the relative number of
customers from the prior study, has both the highest use per customer and the highest load
factor, resulting in a lower average cost than the G1 and G2 groups.
The growth in the costs has also had an impact to the cost of service by class. Compared to the
2012 COSA, costs related to Customer Service, Accounts and Sales have increased by about 30
percent, compared with 36 percent for O&M and under 30 percent for other cost components.
An increase in Customer Service related costs shifts more costs to the residential class because
it has a higher number of customers. It also leads to higher customer charges for all three of
the classes.
Staff proposes to adjust gas rates as shown in Table 1 and Table 2 below, effective July 1, 2019.
These changes are projected to increase the system average gas rate (total of supply and
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distribution) by roughly 5 percent and residential rates by 8 percent. These rate changes are
included in the proposed amended rate schedules in Attachment D.
Table 1: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/18)
Proposed for
FY 2020
($) (%)
G-1 (Residential) $10.94 $13.35 $2.41 22.0%
G-2 (Small Commercial) 82.92 104.95 22.03 26.6%
G-3 (Large Commercial) 400.08 690.45 290.37 72.6%
G-10 (CNG) 56.11 70.98 14.87 26.5%
Table 2: Current and Proposed Gas Distribution Charges
Change
Current (as of
7/1/18)
Proposed
for FY 2020
($) (%)
G-1 (Residential)
Tier 1 Rates $0.4239 $0.4835 $0.0596 14.1%
Tier 2 Rates 0.9948 1.0426 0.0478 4.8%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.6183 0.6102 (0.0081) (1.3%)
G-3 (Large Commercial)
Uniform Rate 0.6098 0.6056 (0.0420) (0.7%)
Bill Impact of Proposed Rate Changes
Table 3 shows the impact of the proposed July 1, 2019 rate changes on various levels of
residential bills. The average increase for the residential class is roughly 8 percent based on last
year’s commodity prices, but some customers may see slightly higher or lower increases due to
slight changes in the composition of the utility’s costs, as well as prevailing market prices in the
months displayed.
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Table 3: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using December 2018 commodity prices)
30 $ 48.38 $ 52.58 $ 4.20 8.7%
54 (median) 78.33 83.96 5.63 7.2%
80 122.19 129.14 6.94 5.7%
150 249.51 259.80 10.29 4.1%
Summer (Using July 2018 commodity prices)
10 $ 20.04 $ 23.05 $ 3.01 15.0%
18 (median) 27.32 30.81 3.48 12.7%
30 43.96 48.04 4.08 9.3%
45 66.17 70.97 4.80 7.2%
Table 4 shows the impact of the proposed July 1, 2019 rate changes on various representative
commercial customer bills.
Table 4: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using December 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 804 822 2.2%
5,000 7,295 7,276 (0.3%)
10,000 14,506 14,447 (0.4%)
50,000 72,092 72,172 0.1%
FY 2020 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years
Table shows the projected rate adjustments over the next five years and their impact on the
annual median residential gas bill.
Table 5: Projected Rate Adjustments, FY 2020 to FY 2024
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Gas Utility 8% 8% 8% 6% 4%
Estimated Bill Impact ($/mo)* $4.38 $3.72 $4.02 $3.25 $2.30
* estimated impact on median residential gas bill, which is currently $42.12 for CY 2018.
One of the main drivers for the increase in the Gas Utility’s short term costs (and therefore
rates) over the next several years are increases in capital improvement costs to maintain a safe
and reliable system. In FY 2014, FY 2015 and FY 2017, costs for the gas utility were unusually
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low as new main replacements were not planned. The gas, water and wastewater utilities
generally try to perform a main replacement annually in each utility, but in the gas utility
beginning new projects was not feasible in those years. In FY 2014 and FY 2015, this was due to
the fact that staff was completing a prior major gas main replacement project, the largest in
utility history, which completed replacement of all ABS gas mains in Palo Alto. Then, FY 201 7
included replacements of gas mains on University Avenue, a project that has evolved into the
Upgrade Downtown project involving a coordinated replacement of several different types of
infrastructure to avoid multiple disruptions to the business district. This has be en a multi-year
planning effort that did not allow for design of other new projects. This allowed the Gas Utility
to temporarily keep rates lower than they would typically have been needed to be to fund
future operations and capital replacement. These future capital replacement costs will be
higher, as well. As the emphasis on infrastructure improvement has taken hold both regionally
and nationally, contractor bids for new projects have risen greatly from where they were during
the last recession.
This current financial plan works to address these challenges in a way that will allow City of Palo
Alto Utilities (CPAU) to meet its gas main replacement (GMR) needs. The next focus of the
GMR program will be the replacement of all Polyvinyl Chloride (PVC) mai ns with Polyethylene
(PE) mains. CPAU installed PVC pipes from the early 1970s to mid-1980s. Some of the City’s PVC
pipe is approaching 50 years of service, and according to industry data, PVC pipes have a much
higher leakage rate than PE mains after 20 years of service due to potential disbondment of
fittings and joints. This financial plan includes approximately $11 million every other year for
main replacement construction instead of $6.5 million annually, starting in FY 2021. This shift
to larger main replacement construction projects every other year will slightly lengthen the
amount of time needed to replace all PVC pipes in the system but will attract more contractors
and better pricing to bid on the larger projects. Additionally, this main replacement project
schedule for gas will be staggered with water and wastewater (water and wastewater
construction every even year and gas construction every odd year), which will ease scheduling
difficulties for inspection coverage due to shared inspection staff across water, wastewater,
gas, and large development services projects. This arrangement is likely to be a short-term
solution (3-5 years) until project capacity can be increased and upward pressure on utility rates
has eased.
Because of this staggered CIP approach, and from a budgeting standpoint, there will be a
pattern of revenues being higher than cost one year and lower the next. To avoid a ‘sawtooth’
pattern in reserves because of this, the funds which would otherwise have gone to pay for CIP
expenditures in the even year will be placed in the CIP reserve, to be used in the following year
when the CIP expense occurs. Therefore, staff is requesting a $6 million transfer from the
Operations Reserve to the CIP reserve in FY 2020.
Over the longer term, gas commodity costs are the most variable factor in customer gas bills,
being subject to market forces, and are currently projected to grow by about 4 percent per
year. Increases to Operations costs are projected to be 3 to 4 percent annually, although there
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is a near term increase in cost to pay for phase two of a cross-bore safety verification program.
During trenchless installation, a natural gas pipeline can cros s through a segment of lateral via
boring. The project will be to video inspect, determine and repair any unintended conflicts
between natural gas service pipelines and sanitary sewer laterals. Phase two of this program is
estimated to require $1 million per year for the next three years.
Figures 1 below illustrates the projected long run changes in the Gas Utility’s costs. Cost
increases over the FY 2016 to FY 2024 time period are mainly from Commodity costs, followed
by Operations and Capital.
Figure 1: FY 2016, FY 2019 and FY 2024 costs
* Note that FY 2024 Capital Investment cost is displayed as an average of two years’
cost, as FY 2023 has an $11 million main replacement project while FY 2024 does not.
Gas usage was trending downward over the last several years, most likely due to relatively
warm winter heating seasons, as well as lower hot water usage during the drought, but a cooler
winter and the end of drought restrictions has brought increased usage. Gas usage has nearly
recovered to levels seen back in 2013, but as with water, it is difficult to determine whether or
when long run usage will resume the declining trend seen over the last few decades.
Changes from Preliminary Financial Forecast
After presenting the preliminary financial forecast to the UAC on February 6, 2019, staff
updated its CIP plan as described above, based upon both projected system needs and current
staffing capacity. The impact on rates was that the preliminary projection of a 15 percent
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distribution rate increase for FY 2020 (10 percent overall bill impact) was reduced to 8 percent
(5 percent overall bill impact).
Gas Bill Comparison with Surrounding Cities
Table 6 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2018 (to illustrate a summer month bill) and
February 2019 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for calendar year 2018 was $469.94, about 14 percent lower than the annual bill for a
PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 6: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2019)
30 39.55 46.31 -14.6%
(Median) 54 62,43 83.49 -25.2%
80 100.93 139.13 -27.5%
150 207.64 288.94 -28.1%
Summer
(July 2018)
10 $ 20.04 12.48 63.4%
(Median) 18 27.32 24.56 13.8%
30 43.96 46.26 -3.6%
45 66.17 73.38 -8.3%
Table 7 shows the monthly gas bills for commercial customers for various usage levels for rates
in effect as of February 2019. Bills for CPAU customers at the usage levels shown are around 3
percent lower to 12 percent higher for commercial customers than for PG&E customers. This is
a substantial improvement over the calendar year 2013 bill comparison, when commercial gas
bills for CPAU customers were 27 percent to 44 percent higher than for PG&E customers. This is
primarily attributable to PG&E’s increased distribution rates as the commodity rates for CPAU
and PG&E are very similar, both being based on spot market gas prices.
Table 7: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2018)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 657 681 -3%
5,000 5,823 6,257 -1%
10,000 11,563 11,139 4%
50,000 57,374 51,414 12%
City of Palo Alto Page 11
Commission Review
The UAC reviewed this proposal at its May 1, 2019 meeting. Staff presented the UAC with the
updated proposal showing an 8% distribution increase (a 5% overall impact), a slight reduction
from the initial 9% projection in the p reliminary projections. Commissioners commented that
the impacts were larger for smaller users, being as the increases were larger for customer
charges. Staff responded that efforts were ongoing to try and keep costs from rising, but that
the size of the changes, while large on a percentage basis, were not large on a dollar basis.
The UAC recommended and unanimously approved staff’s proposal. The excerpted draft
minutes from the UAC’s May 1, 2019 meeting can be found on the City’s website, located here.
Timeline
If the Finance Committee supports the proposed rate adjustments, t he City Council will
consider adopting the Financial Plan and rate amendments as part of the FY 2020 budget
review and adoption process. If Council approves the proposed rate changes, they will become
effective July 1, 2019.
RESOURCE IMPACT
Normal year sales revenues for the Gas Utility are projected to increase by roughly 4 percent
($1.2 million) as a result of the proposed rate increases, not including fluctuations in
commodity revenue/cost. The FY 2020 Budget is being developed concurrent with these rates
and, depending on the final rates, adjustments to the budget may be necessary at a later time.
See the attached FY 2020 Gas Financial Plan for a more comprehensive overview of projected
cost and revenue changes for the next five years.
POLICY IMPLICATIONS
The proposed gas rate adjustments are consistent with Council -adopted Reserve Management
Practices that are part of the Financial Plan, and were developed using a cost of service study
and methodology consistent with industry-accepted cost of service principles.
ENVIRONMENTAL REVIEW
The Finance Committee’s review and recommendation to Council on the FY 2020 Gas Financial
Plan and rate adjustments does not meet the California Environmental Quality Act’s definition
of a project, pursuant to Public Resources Code Section 21065, thus no environmental review is
required.
Attachments:
• Attachment A: Draft RESO FY 2020 Gas Financial Plan Adoption
• Attachment B: FY 2020 Gas Financial Plan
• Attachment C: Resolution Amending Gas Rate Schedules G1, G2, G3 and G10 for FY 2020
• Attachment E: Info Item Regarding Hedging
Attachment A
* NOT YET APPROVED *
Resolution No. _________
Resolution of the Council of the City of Palo Alto Approving the
FY 2020 Gas Utility Financial Plan
R E C I T A L S
A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of
its utilities with the goal of ensuring adequate revenue to fund operations. This includes
making long-term projections of market conditions, the physical condition of the system, and
other factors that could affect utility costs, and setting rates adequate to recover these costs. It
does this with the goal of providing safe, reliable, and sustainable utility services at competitive
rates. The City adopts Financial Plans to summarize these projections.
B. The City uses reserves to protect against contingencies and to manage other
aspects of its operations, and regularly assesses the adequacy of these reserves and the
management practices governing their operation. The status of utility reserves and their
management practices are included in Reserves Management Practices attached to and made
part of the Financial Plans.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby adopts the FY 2020 Gas Utility Financial Plan.
SECTION 2. The Council hereby approves the transfer of up to $300,000 Thousand
from the Rate Stabilization Reserve to the Operations Reserve, and up to $6 Million from the
Rate Stabilization Reserve to the CIP Reserve, as described in the FY 2020 Gas Utility Financial
Plan approved via this resolution.
SECTION 3. The Council finds that the adoption of this resolution does not meet the
California Environmental Quality Act’s (CEQA) definition of a project under Public Resources
Code Section 21065 and 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.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
Attachment A
* NOT YET APPROVED *
___________________________ ___________________________
City Clerk Mayor
APPROVED AS TO FORM: APPROVED:
___________________________ ___________________________
Assistant City Attorney City Manager
___________________________
Director of Utilities
___________________________
Director of Administrative Services
FY 20 20 GAS
UTILITY
FINANCIAL PLAN
FY 20 20 TO FY 202 4
GAS UTILITY FINANCIAL PLAN
M a r c h 2 0 1 9 2 | P a g e
GAS UTILITY FINANCIA L PLAN
FY 20 20 TO FY 202 4
TABLE OF CONTENTS
Section 1: Definitions and Abbreviations................................................................................ 4
Section 2: Executive Summary and Recommendations ........................................................... 5
Section 2A: Overview of Financial Position .................................................................................. 5
Section 2B: Summary of Proposed Actions .................................................................................. 6
Section 3: Detail of FY 2019 Rate and Reserve Proposals ........................................................ 6
Section 3A: Rate Design ............................................................................................................... 6
Section 3B: Current and Proposed Rates ..................................................................................... 8
Section 3C: Bill impact of Proposed Rate Changes ...................................................................... 9
Section 3D: Proposed Reserve Transfers ................................................................................... 10
Section 4: Utility Overview .................................................................................................. 11
Section 4A: Gas Utility History ................................................................................................... 11
Section 4B: Customer Base ........................................................................................................ 12
Section 4C: Distribution System ................................................................................................. 13
Section 4D: Cost Structure and Revenue Sources ...................................................................... 14
Section 4E: Reserves Structure ................................................................................................... 14
Section 4F: Competitiveness ...................................................................................................... 15
Section 4G: Gas Supply Rates .................................................................................................... 16
Section 5: Utility Financial Projections ................................................................................. 17
Section 5A: Load Forecast .......................................................................................................... 17
Section 5A: FY 2014 to FY 2018 Cost and Revenue Trends ........................................................ 18
Section 5B: FY 2018 Results ....................................................................................................... 19
Section 5C: FY 2019 Projections ................................................................................................. 20
Section 5D: FY 2020-FY 2024 Projections .................................................................................. 20
Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 21
GAS UTILITY FINANCIAL PLAN
M a r c h 2 0 1 9 3 | P a g e
Section 5F: Long-Term Outlook ................................................................................................. 23
Section 6: Details and Assumptions ..................................................................................... 24
Section 6A: Gas Purchase Costs ................................................................................................. 24
Section 6B: Operations .............................................................................................................. 25
Section 6C: Capital Improvement Program (CIP) ....................................................................... 26
Section 6D: Debt Service ............................................................................................................ 28
Section 6E: Equity Transfer ........................................................................................................ 30
Section 6F: Revenues ................................................................................................................. 30
Section 6G: Communications Plan ............................................................................................. 31
Appendices ......................................................................................................................... 33
Appendix A: Gas Financial Forecast Detail ................................................................................ 34
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 35
Appendix C: Gas Utility Reserves Management Practices ......................................................... 37
Appendix D: Description of Gas Utility Cost Categories ............................................................ 41
Appendix E: Gas Utility Communications Samples .................................................................... 42
GAS UTILITY FINANCIAL PLAN
M a r c h 2 0 1 9 4 | P a g e
SECTION 1: DEFINITIONS AND ABBR EVIATIONS
ABS: Acrylonitirile butydene styrene, a plastic gas main material
AMI: Advanced Metering Infrastructure
CARB: California Air Resources Board
CIP: Capital Improvement Program
CNG: Compressed Natural Gas
CPAU: City of Palo Alto Utilities Department
CPUC: California Public Utilities Commission
Cross-bore: A cross-bore exists when one utility line has been drilled or “bored” through a
portion of another line. Gas cross-bores can occur in sewer lines as a result of “horizontal
boring” construction practices.
Distribution: transportation of gas to customers.
GMR Program: Gas Main Replacement Program
Local Transportation: transportation of gas to Palo Alto across PG&E’s distribution system from
PG&E City Gate.
Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where
the northern end of PG&E’s Redwood Transmission Pipeline is located.
MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms.
Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers
are typically measured in MMBtu.
O&M: Operations and Maintenance
PE or HDPE: Polyethylene, a gas main material (more specifically, High-Density Polyethylene)
PG&E: Pacific Gas and Electric
PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas
delivered to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s
Redwood Transmission Pipeline) is said to have been delivered at PG&E Citygate.
PVC: Polyvinyl chloride, a plastic gas main material
Summer: April 1 to October 31
Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000
British thermal units. Therms measure the heating value of the gas, rather than its volume .
Transmission: transportation of gas between major gas delivery hubs via a gas transmission
pipeline, such as PG&E’s Redwood pipeline.
UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU
issues.
Winter: November 1 to March 31
GAS UTILITY FINANCIAL PLAN
M a r c h 2 0 1 9 5 | P a g e
SECTION 2: EXECUTIVE SUMMARY AND RECOMMEND ATIONS
This document presents a Financial Plan for the City’s Gas Utility for the next five years. This
Financial Plan provides revenues to cover the costs of operating the utility safely over that time
while adequately investing for the future. It also addresses the financial risks facing the utility
over the short term and long term, and includes measures to mitigate and manage those risks.
SECTION 2 A : OVERVIEW OF F INANCIAL P OSITION
This financial plan projects non-commodity costs to increase from FY 2019 through FY 2024 at
about 3.6% per year on average. In the short term, some of these cost increases are related to
the cross-bore inspection program, but capital improvement program (CIP) costs have also
increased as the economy has improved. The national and regional focus on infrastructure
improvement has created more demand, and the pool of skilled construction labor has not
grown at the same pace. While CPAU generally has planned a new gas main replacement
project every year, recent larger than expected bids have required resizing and redesign of
some existing planned projects. The size, scope and complexity of the University Avenue
Business District project, which is nearing completion, resulted in no new CIP work being
budgeted for FY 2019. Staff is currently budgeting for a new, larger main replacement project
every other year. This revised main replacement schedule will allow CPAU to reasonably meet
its main replacement needs while addressing challenges in the current construction marke t and
optimizing current staffing resources. However, if it is found that PVC pipe replacement should
be replaced sooner, then the pace and size of main replacements may need to increase. Table 1
shows the Gas Utility expenses over the period of this financial plan.
Table 1: Gas Utility Expenses for FY 2018 to FY 2024 (Thousand $’s)
Expenses
($000)
FY 2018
(act.)
FY 2019
(est.) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Commodity costs 12,921 13,022 14,362 14,729 15,174 15,576 16,122
Operations 19,571 21,468 22,494 22,868 22,497 23,054 23,576
Capital Projects 7,804 5,567 2,350 13,402 2,436 13,490 2,551
TOTAL 40,297 40,057 39,206 50,999 40,108 52,120 42,249
To ensure that revenues cover projected rising costs, the financial plan includes the rate
trajectory shown in Table 2.
Table 2: Projected Gas Rate Trajectory for FY 2020 to FY 2024
Projection FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
Current Financial Plan 5% 8% 8% 6% 4%
FY 2019 Financial Plan 8% 7% 7% 4% 4%
FY 2018 Financial Plan 6% 6% 5% 3% 3%
The Gas Utility has Rate Stabilization Reserves in both the Supply and Distribution funds, which
can be used to smooth rate increases over several years. This Financial Plan projects that these
reserves will be exhausted by the end of FY 2020. The Gas Utility also has a CIP Reserve to help
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offset spikes in CIP spending which do not merit separate bond financing. Going forward, this
reserve will be used to offset the annual fluctuations in main replacement costs. Table 3 shows
the projected reserve transfers over the forecast period.
Table 3: Transfers To/(From) Reserves for FY 2019 to FY 2024 ($000)
Reserve FY 2019 FY 2020 FY 2021 to FY 2024
Rate Stabilization (17) (6,363) -
CIP - 6,000 (720)
Operations 17 363 720
SECTION 2 B : SUMMARY OF PROPOSE D ACTIONS
Staff proposes the following actions for the Gas Utility in FY 2019:
1. Transfer any remaining funds in the Supply Rate Stabilization Reserve to the Operations
Reserve (currently estimated at $17,000).
Staff proposes the following actions for the Gas Utility in FY 2020:
2. Increase distribution rates by 8% (a 5% overall increase) for FY 2020, primarily reflecting
increases to capital expenditures and also increased operations costs. See Section 3B:
Current and Proposed Rates for more details.
3. Propose a transfer of up to $6.363 million from the Distribution Rate Stabilization
Reserve to the Operations Reserve, to keep the ending balance of the Operations
Reserve above the adopted guideline level and below the maximum guideline level.
4. Amend the Gas Utility Reserves Management Practices to clarify the purpose, funding
of, and transfers to and from the CIP Reserve.
SECTION 3: DETAIL OF FY 201 9 RATE AND RESERVE PRO POSALS
SECTION 3 A : RATE DESIGN
The Gas Utility’s rates are evaluated and implemented in compliance with cost of service
requirements. The Gas Utility’s proposed rates are based on the methodology from the March
2019 Natural Gas Cost of Service and Rates Study, included here as Attachment E. The
methodology used was similar to the prior study performed in April 2012 by Utility Financial
Solutions1, and updated to reflect current costs as well as changes in consumption patterns
between customer classes. The study was performed in conformance with the scope previously
discussed with the Utilities Advisory Commission in October 2016, and the Council in November
20162.
For the Residential (G1) customers, energy consumption per customer has decreased by
roughly 10 percent when compared to the 2012 COSA. This means that the fixed costs
1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
2 Staff Report 7416 11/14/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54576
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associated with the Residential class are spread among a smaller amount of therms consumed,
increasing the per unit cost for the class. For Small Commercial (G2 ) customers, per customer
usage has also decreased by roughly 10 percent, but as both the use per customer and load
factor are higher than for the Residential class, Small Commercial customers have a lower
average cost than for the Residential class. The Large Commercial (G3) group has seen a growth
in the relative number of customers from the prior study, and while per customer usage has
dropped by nearly 40%, this class still has both the highest use per customer and the highest
load factor, resulting in a lower average cost than the G1 and G2 groups.
The growth in the costs has also had an impact to the cost of service by class. Compared to the
2012 COSA, costs related to Customer Service, Accounts and Sales have increased by 78%
compared to an increase of 36% for O&M and under 30% for other cost components. This
shifts more costs to the residential class because it has a higher number of customers. It also
leads to higher customer charges for all three of the classes.
After reviewing current and proposed operating costs, changes to the utilities infrastructure
mix, and developing patterns of usage between Palo Alto’s customers (with commercial
consumption declining at a greater rate relative to residential consumption), it was determined
that residential customers would require about a 5% increase to achieve cost of service (COSA)
parity between classes, while small and large commercial customers would require
corresponding decreases, as outlined in Table 4 below:
Table 4: Cost of Service (COSA) results by Customer Class
After these class shifts were determined, the 8% distribution rate increase was applied to rates,
as outlined in Section 3B: Current and Proposed Rates. As much of the distribution cost relates
to relatively constant and recurring operations costs within the system, which occur or are
required regardless of how much gas flows through the system, or are related to pipeline
replacements which serve to benefit all customers better safety and reliability, it is reasonable
to allocate more of the cost and relative increases within monthly service charges and less to
volume related sales.
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SECTION 3 B : CURRENT AND PROPOS ED RATES
On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly
to match changes in gas market prices.3 In addition, CPAU increased monthly service charges to
recover the cost of providing gas service to customers. In January 2015, the Council adopted a
new rate component to collect the costs of purchasing allowances for the purpose of
compliance with the State’s cap-and-trade program.4 This component changes depending on
the cost of allowances and gas demand. In October 2016, the Council adopted a resolution
changing the Local Transportation rate (which had been collapsed into the Distribution rate in
2015 to streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to
Wholesale/Resale Customers (G-WSL) charge to Palo Alto.5 This went into effect November 1,
2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a
carbon neutral gas portfolio by FY 2018.6 The plan is for costs associated with the plan to be a
passed through directly to customers as well, although the rate impact is not to exceed $0.10
per therm. Three years’ worth of volumetric rate history can be found on Palo Alto’s website.7
CPAU has four rate schedules: one for separately metered residential customers (G-1), one for
small commercial and master-metered multi-family residential customers (G-2), one for
customers using over 250,000 therms per year (G-3) and a specific schedule for the Compressed
Natural Gas station (G-10). All customers pay a monthly service charge, which represents meter
reading, billing, and other customer service costs, as well as a portion of operations and
maintenance cost. All customers are also charged for each therm of gas used. Separately
metered residential customers are charged on a tiered basis, differentiated by season. During
the winter months, the first 2 therms per day (60 therms for a 30 day billing period) are charged
a base price per CCF, and all additional units charged a higher price per therm . During the
summer months, the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing
period. Commercial customers pay a uniform price for each therm used.
Table 5 shows the current monthly service charges for all rate schedules. Table 106 shows the
consumption charges related to distribution charges. As mentioned earlier, commodity charges
change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Some
recent commodity price history is discussed in Section 6A: Gas Purchase Costs.
3 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395
4 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537
5 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165
6 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882
7 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399
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Table 5: Current and Proposed Monthly Service Charges
Rate Schedule
Monthly Service Charge
($/month)
Change
Current (as of
7/1/18)
Proposed for
FY 2020
($) (%)
G-1 (Residential) $10.94 $13.35 $2.41 22.0%
G-2 (Small Commercial) 82.92 104.95 22.03 26.6%
G-3 (Large Commercial) 400.08 690.45 290.37 72.6%
G-10 (CNG) 56.11 70.98 14.87 26.5%
Table 6: Current and Proposed Gas Distribution Charges
Change
Current (as of
7/1/18)
Proposed
for FY 2020
($) (%)
G-1 (Residential)
Tier 1 Rates $0.4239 $0.4835 $0.0596 14.1%
Tier 2 Rates 0.9948 1.0426 0.0478 4.8%
G-2 (Residential Master-Metered and Small Commercial)
Uniform Rate 0.6183 0.6102 (0.0081) (1.3%)
G-3 (Large Commercial)
Uniform Rate 0.6098 0.6056 (0.0420) (0.7%)
G-10 (Compressed Natural Gas)
Uniform Rate 0.0100 0.0100 0.0000 -
SECTION 3 C : BILL IMPACT OF PRO POSED RATE CHANGES
Table 7 shows the impact of the proposed July 1, 201 9 rate changes on the median residential
bill. The average increase is roughly 8% based on prices in December 2018, but some customers
may see slightly higher or lower increases due to slight changes in the composition of the
utility’s costs, as well as prevailing market prices.
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Table 7: Impact of Proposed Gas Rate Changes on Residential Bills
Usage
(Therms/month)
Bill under
Current Rates
Bill under
Proposed Rates
Change
$/mo. %
Winter (Using December 2018 commodity prices)
30 $ 48.38 $ 52.58 $ 4.20 8.7%
54 (median) 78.33 83.96 5.63 7.2%
80 122.19 129.14 6.94 5.7%
150 249.51 259.80 10.29 4.1%
Summer (Using July 2018 commodity prices)
10 $ 20.04 $ 23.05 $ 3.01 15.0%
18 (median) 27.32 30.81 3.48 12.7%
30 43.96 48.04 4.08 9.3%
45 66.17 70.97 4.80 7.2%
Table 8 shows the impact of the proposed July 1, 2019 rate changes on various representative
commercial customer bills.
Table 8: Impact of Proposed Gas Rate Changes on Commercial Bills
(Using December 2018 commodity prices)
Usage
(Therms/month)
Bill under Current
Rates
Bill under
Proposed Rates
Change
%
500 804 822 2.2%
5,000 7,295 7,276 (0.3%)
10,000 14,506 14,447 (0.4%)
50,000 72,092 72,172 0.1%
SECTION 3D : PROPOSED RESERVE TRANSFERS
The FY 2019 Financial Plan proposed a $2 million transfer from the Rate Stabilization Reserve
into the Operations Reserve in FY 2019. Actual expenses in FY 2018 resulted in higher ending
reserve balances than initially projected. The Supply Rate Stabilization reserve is projected to
end the year at $19,000, and staff recommends that this amount be transferred to the
Operations Reserve and the Rate Stabilization reserve drawn to zero. Further gains or losses to
this fund should come from the Operations Reserve. A tentative transfer of $6.363 million from
the Distribution Rate Stabilization reserve in FY 2020 is included in the financial projections in
this Financial Plan. The intent for several years has been to utilize these funds to mitigate rate
increases and otherwise bring the Rate Stabilization reserves to zero.
In addition, there is $3.8 million in the CIP Reserve. These funds can be used to help mitigate
additional, one-time costs, but with the current plan to stagger main replacement projects
every other year, this fund can also be used to hold funds collected from rate revenues that
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should be used to fund CIP projects. In a year with no project budgeted, rate revenues will likely
exceed expenses, but conversely, in years with a main replacement project, rates are not
anticipated to cover total cost. The reasonable approach is to transfer excess funds from the
Operations Reserve to the CIP Reserve in non-main replacement years, then utilize those funds
in years with replacements. The net effect will be more evenly funded Operations Reserve and
a CIP reserve that better reflects available funds for projects. The impact of these transfers on
reserves levels can be seen in Appendix A: Gas Utility Financial Forecast Detail.
SECTION 4: UTILITY O VERVIEW
This section provides an overview of the utility and its operations. It is intended as general
background information and to help readers better understand the forecasts in Section 5:
Utility Financial Projections and Section 6: Details and Assumptions.
SECTION 4 A : GAS UTILITY HISTORY
On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo
Alto Gas Company and continue it as a municipal enterprise. At the time, the system was
comprised of 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the
gas, which was synthesized from coal at its Potrero gasification facility. Almost immediately the
City faced challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E
had filed with the Railroad Commission (the forerunner to today’s CPUC) to increase rates by
nearly 72.5%. Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924
revenues had exceeded those of the electric utility. Sales were such that the annual reports of
the time noted gas usage “appears to be greater than that of any other city in the state,
showing that gas is a very popular form of fuel in Palo Alto.” Just prior to the acquisition of the
neighboring town of Mayfield’s gas system (centered around today’s California Avenue) in
1929, the miles of main in service and customers connections had doubled .
Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely
manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to
natural gas. In 1935, a supplementary butane injection system (later retired) was purchased
from Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic
feet (MCF) with 4,849 active services.
Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU
switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles
of ABS mains had already been installed. A 1990 evaluation of the system found a steadily
increasing rate of gas leaks associated with those mains, something that other gas utilities had
also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from
7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year . This would
enable the utility to replace all of its ABS and its most vulnerable steel an d PVC mains with
polyethylene (PE) mains over the course of the following 36 years.8 As of 2015 the Gas Utility
had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic
8 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990
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protection was not effective. Current main replacement projects will target the last ~800 feet of
remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the
appropriate footage of annual PVC replacement for future CIP projects is currently being
conducted. This is an example of how local control of its Gas Utility has provided Palo Alto
residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its
main replacement rate to ensure a robust gas distribution system, PG&E was underspending on
safety-related infrastructure, according to a past audit.9
In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also
participating in major changes to the structure of the gas industry in California . Until 1988 CPAU
had a formal policy of setting its rates equal to PG &E’s rates and successfully did so with the
exception of one year in the mid-1970s. At times this led to inadequate revenue (1974 to 1981)
as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the
wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began
deregulating the natural gas industry in California, the Gas Utility began purchasing gas from
suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”10 which enabled the
Gas Utility (along with other local transportation-only customers) to obtain transmission rights
on PG&E’s Redwood transmission pipeline running from Malin, Oregon into California.
In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s
supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001.
The Council approved drawing down reserves to provide ratepayer relief and, for two years
following the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001
the Council approved a hedging practice of buying fixed price gas one to three years into the
future. After reaching a low point in October 2001, prices continued to rise, and as a result the
CPAU hedging strategy frequently resulted in a wholesale supply cost advantage compared to
PG&E until prices began to decline steeply in mid-2008. At that point the Gas Utility’s wholesale
supply costs became higher than market gas prices due to fixed price contracts entered into
prior to 2008. As a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for
several years. In 2012 Council approved a plan to formally cease the hedging strategy and
purchase all gas on the short-term (“spot”) markets. As of July 1, 2012, the commodity portion
of the gas rates changes every month based on the spot market gas price.
SECTION 4 B : CUSTOMER BASE
CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas
customers in Palo Alto. Close to 23,600 customers are connected to the natural gas system,
approximately 22,000 (93%) of which are residential and 1,600 (7%) of which are non-
residential. Residential customers consume about 11 to 13 million therms of gas per year,
roughly 45% of the gas sold, while non-residential customers consume 55% (about 14 to 16
million therms). Residential customers use gas primarily for space heating (46% of gas
consumed) and water heating (42%), with the remainder consumed for other purposes such as
9 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations , Overland Consulting,
made available through a CPUC Administrative Law Judge’s ruling on A12-11-009/I13-03-007 on 5/31/2013
10 CPUC decision 97-08-055. Since then, the Gas Accord has been amended four times, with the most recent being
Gas Accord V, application A.09-09-013
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cooking, clothes drying, and heating pools and spas.11 Non-residential customers use gas for
space and water heating (73% of gas consumed), cooking (20%), and industrial processes
(6%).12
The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s
distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving
stations are jointly operated by CPAU and PG&E. CPAU purchases gas from various natural gas
marketers, with PG&E providing only local transportation service (transportation from the
PG&E City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s
transmission pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower
priced gas at that location. CPAU does not produce or store any natural gas, and purchases gas
in the monthly and daily spot markets. The cost of the purchased gas is passed through directly
to customers through a rate adjuster that varies monthly with market (bidweek) prices. In a
similar fashion, the cost for local transportation is now tied to PG&E’s G-WSL rate schedule, and
varies when and if PG&E changes its rate schedule. The cost of purchased gas and PG&E local
transportation service usually account for roughly one third of the utility’s expenditures.
SECTION 4 C : DISTRIBUTION SYSTE M
To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas
mains (which transport the gas to various parts of the city) and close to 23,600 gas services
(which connect the gas mains to the customers’ gas lines). These mains and services, along with
their associated valves, regulators, and meters, represent the vast majority of the infrastructure
used to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure
over time, the expense of which normally accounts for around 15 to 20% on average of the
utility’s expenditures. Costs for main replacements have been going up in recent years.
In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the
system, such as monitoring the system for leaks, testing and replacing meters, monitoring the
condition of steel pipe, and building and replacing gas services for buildings being built or
redeveloped throughout the city. The utility also shares the costs of other system-wide
operational activities (such as customer service, billing, meter reading, supply planning, energy
efficiency, equipment maintenance, and street restoration) with the City’s other utilities . These
maintenance and operations expenses, as well as associated administration, debt service, rent,
and other costs, make up roughly half of the utility’s expenses.
In addition to these ongoing activities, CPAU has conducted a program to find and replace
cross-bores over the last several years. Currently, $1 million is budgeted per year for the cross-
bore program through FY 2021. However, the ongoing cross-bore investigation may require
additional funding, or extend for longer into the future, as the remaining sewer lines are more
difficult to examine than the majority of the wastewater collection system that has been
examined to date.
11 http://energyalmanac.ca.gov/naturalgas/overview.html
12 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006 . Statistics shown are
for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located.
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Figure 2: Cost Structure (FY 2018)
48%
33%
19%
Operations
Gas Purchases
Capital
Figure 1: Revenue Structure (FY 2018)
92%
8%
Sales of Gas
Other Revenue
SECTION 4 D : C OST S TRUCTURE AND R EVENUE S OURCES
As shown in Figure 1, the Gas
Utility receives about 92% of its
revenue from sales of gas and the
remainder from capacity and
connection fees, interest on
reserves, and other sources.
Appendix A: Gas Utility Financial
Forecast Detail shows more detail
on the utility’s cost and revenue
structures.
As shown in Figure 2, in FY 2018,
gas purchase costs accounted for
roughly one third of the Gas
Utility’s costs. This percentage
can vary widely from year to year,
as this cost is based upon market
purchases, and now also includes
costs related to cap and trade.
Operational costs in FY 2018
represented roughly half of
expenses and capital investment
was responsible for the remaining
19%. CIP is normally about 20% of
expenses, but this may be lower
in times when spending for new
projects is deferred, as happened in FY 2017.
SECTION 4 E : RESERVES STRUCTURE
CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. The
summary below describes each of these briefly. See Appendix C: Gas Utility Reserves
Management Practices for more detailed definitions and guidelines for reserve management:
• Reserve for Commitments: A reserve equal to the utility’s outstanding contract
liabilities for the current fiscal year. Most City funds, including the General Fund, have a
Commitments Reserve.
• Reserve for Re-appropriations: A reserve for funds dedicated to projects re-
appropriated by the City Council, nearly all of which are capital projects. Most City
funds, including the General Fund, have a Re-appropriations Reserve.
• Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to
accumulate funds for future expenditure on CIP projects. This CIP can also act as a
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contingency reserve for the CIP. This type of reserve is used in other utility funds
(Electric, Water, and Wastewater Collection) as well.
• Rate Stabilization Reserve: This reserve is intended to be empty unless one or more
large rate increases are anticipated in the forecast period. In that case, funds can be
accumulated to spread the impact of those future rate increases across multiple years.
This type of reserve is used in other utility funds (Electric, Water, and Wastewater
Collection) as well.
• Operations Reserve: This is the primary contingency reserve for the Gas Utility, and is
used to manage yearly variances from budget for operational gas costs. This type of
reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as
well.
• Unassigned Reserve: This reserve is for any funds not assigned to the other reserves
and is normally empty.
SECTION 4 F : COMPETITIVENESS
Table 9 presents winter and summer residential bills for Palo Alto and PG&E at several usage
levels for commodity rates in effect as of July 2018 (to illustrate a summer month bill) and
February 2019 (to illustrate a winter month bill). The annual gas bill for the median residential
customer for fiscal year 2018 was $469.94, about 14% lower than the annual bill for a PG&E
customer with the same consumption. PG&E’s distribution rates for gas have increased
substantially to collect for needed system improvements for pipeline safety and maintenance.
The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which
includes the surrounding communities.
Table 9: Residential Monthly Natural Gas Bill Comparison ($/month)
Season
Usage
(therms) Palo Alto PG&E Zone X
%
Difference
Winter
(February 2019)
30 39.55 46.31 -14.6%
(Median) 54 62,43 83.49 -25.2%
80 100.93 139.13 -27.5%
150 207.64 288.94 -28.1%
Summer
(July 2018)
10 20.38 12.48 63.4%
(Median) 18 27.94 24.56 13.8%
30 44.59 46.26 -3.6%
45 67.32 73.38 -8.3%
Table 1010 shows the monthly gas bills for commercial customers for various usage levels for
rates in effect as of February 2019. Bills for CPAU customers at the usage levels shown can vary
between 3% lower to 12% higher for commercial customers than for PG&E customers. This is a
substantial improvement over the calendar year 2013 bill comparison, when commercial gas
bills for CPAU customers were 27% to 44% higher than for PG&E customers. This is primarily
attributable to PG&E’s higher distribution rates as the commodity rates for CPAU and PG&E are
very similar, both being based on spot market gas prices.
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Table 10: Commercial Monthly Average Gas Bill Comparison
(for Rates in Effect February 2019)
Usage (therms/mo)
Gas Bill ($/month) %
Difference Palo Alto PG&E
500 657 681 -3%
5,000 5,823 6,257 -1%
10,000 11,563 11,139 4%
50,000 57,374 51,414 12%
SECTION 4 G : GAS SUPPLY RATES
Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies
with a strategy to buy gas on the short-term, or “spot” markets and pass the commodity cost to
customers on a monthly basis. Figure 3 shows the actual commodity prices charged. For the
last two and a half years, prior to December 2018, commodity prices had generally fluctuated in
a fairly narrow band, with prices averaging around $0.32/therm. However, in December 2018, a
variety of factors combined that led to a one time market spike: Regional temperatures were
cooler than normal, but in addition, gas supplies stored in underground facilities were lower
than normal, as well as constrained due to problems with the Aliso Canyon facility in southern
California. Also, there were pipeline constraints at both the northern and southern borders.
While there was not an actual constriction on supply, the confluence of all these factors drove
up the bidweek prices for all California delivery points. Once it was seen that these factors were
not causing gas supply shortages, prices returned to levels more commonly seen.
Figure 3: Gas Commodity Rates from July 2012 through February 2019
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SECTION 5 : UTILITY F INANCIAL PROJECTIONS
SECTION 5 A : LOAD F O RECAST
Gas usage in Palo Alto is volatile, varying with both economic and weather conditions . As shown
in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year . Usage
dropped dramatically in the 1976/1977 drought when customers saved significant amounts of
(hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage
was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas
prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly
200%. From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer
investments in energy efficiency.
In 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to
tumble to historic lows. In FY 2017 and FY 2018, as the drought has eased, gas usage increased
again, but has appeared to have stabilized.
Figure 4: Historic Gas Consumption
Gas consumption, as denoted by the dotted line in Figure 5, is projected to resume the long run
trend of decreasing usage over the forecast period, although changes such as replacement of
gas appliances with electric appliances or customer behavior may result in lower long run
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usage. As with prior drought/gas usage declines in the past, it is likely that consumption will not
come back to pre-conservation levels. It is too early to tell, however, where a new ‘normal’
level of consumption will be.
Figure 5: Forecast Gas Consumption
SECTION 5 A : FY 201 4 TO FY 201 8 COST AND REVENUE TR ENDS
Figure 6 and Appendix A: Gas Utility Financial Forecast Detail show how costs have changed
during the last five years as well as how staff project costs to change over the next decade.
The annual expenses for the gas utility generally decreased between 2014 and 2017. Lower gas
sales in conjunction with the drought, as well as lower gas market prices in FY 2015 and FY 2016
(as shown in Figure 3 above) resulted in lower overall commodity expenses. FY 2014, FY 2015
and FY 2017 were notable due to the fact that no new funding was added for main replacement
projects. In FY 2014 and FY 2015, this was due to the fact that staff was completing a prior
major gas main replacement project, the largest in utility history, which completed replacement
of ABS gas mains in Palo Alto. The FY 2018 project included replacements of gas mains on
University Avenue, a project that has evolved into the Upgrade Downtown project involving a
coordinated replacement of several different types of infrastructure to avoid multiple
disruptions to the business district. This has been a multi-year planning effort that did not allow
for design of other new projects. This allowed the Gas Utility to temporarily keep rates lower
than they will need to be to fund future operations and capital replacement .
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Revenues have generally matched expenses in most years and were higher than expenses in FY
2017. The absence of new budget funding for main replacement projects for several years, as
well as the availability of relatively large reserves, forestalled the need for rate increases until
now.
As shown in Figure 6, the last adjustment to gas distribution rates was in July 2018 when CPAU
increased rates by 4%. In FY 2012, commodity rates were changed to a market-based, monthly
pass-through cost—and commodity rates (and usage) fell, so revenues (and gas supply costs)
actually declined in FY 2013 after the rate increase. Figure 6 assumes no change in gas supply
costs over the forecast period to illustrate the impact of proposed distribution rate changes on
the overall customer bill. In reality, gas supply costs are uncertain and are passed through to
customers as they change month to month.
Figure 6: Gas Utility Expenses, Revenues, and Rate Changes:
Actual Costs through FY 2018 and Projections through FY 2024
SECTION 5 B : FY 201 8 RESULTS
Sources of funds for FY 2018 were lower than projections by $214,000, but operational
expenses came in well below the expected budget. Total FY 2018 expenses were $40.3 million
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compared to projections of $42.2 million in the FY 2019 Financial Plan. Table 11 summarizes the
variances from forecast.
Table 11: FY 2018, Actual Results vs. Financial Plan Forecast ($000)
Net Cost/(Benefit) Type of change
Purchase costs lower than forecast (408) Cost savings
Operations cost savings (1,538) Cost savings
Decreased interest income and other
non-sales revenues 257
Revenue decrease
Increased sales revenues (44) Revenue increase
Net Cost / (Benefit) of Variances (1,733)
SECTION 5 C : FY 201 9 PROJECTIONS
Current projections indicate that sales revenues will be slightly higher than last year’s forecast
due to higher than expected market prices. While gas purchase costs are also projected to
increase appreciably during the forecast period, the current financial plan also anticipates
higher operations and CIP costs than projected in the prior financial plan. Table 12 summarizes
the current and projected variances from the FY 2019 Financial Plan.
Table 12: FY 2019 Projected Results vs. Current Financial Plan Forecast ($000)
Net Cost/ (Benefit) Type of change
Sales revenues higher than forecast (452) Revenue increase
Other revenues and interest higher than forecast (159) Revenue decrease
Purchase cost increase 928 Cost increase
Operations & maintenance, customer service, and
capital improvement cost increases
401 Cost increase
Net Cost / (Benefit) of Variances 717
SECTION 5 D : FY 20 20 -FY 202 4 PROJECTIONS
Figure 6 above shows staff projections that overall costs for the Gas Utility will stay relatively
flat into FY 2020. This is largely in part due to a modified CIP schedule starting in FY 2020. For FY
2020 through 2024, staff anticipates annual capital expenditures will fluctuate due to planning
for larger main replacement construction projects every other year instead of smaller projects
annually. This revised main replacement schedule will allow CPAU to meet its main
replacement needs while addressing challenges in the current construction market and
optimizing current staffing resources. Averaging the cost of CIP over these two year cycles,
costs are expected to increase by around 3.6% on average an nually through FY 2024. In
Operations, there is a short run addition of $1 million, starting in FY 2019, for cross-bore
inspections (this expense is projected to continue for at least three years), as well as general
inflationary increases of around 2 to 4% per year. Salaries and benefits expenses are projected
to rise at 3 to 4% per year, per the City’s Long Range Financial Plan. Construction costs continue
to increase, which resulted in increased costs in FY 2018 and FY 2019 for the University Avenue
Business District project, which is nearing completion. The next new main replacement project
after the University Avenue project will take place in FY 2021, and ongoing main replacement is
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expected to be more expensive. Gas commodity costs are the most variable component and are
currently projected to increase by around 4.4% annually. Since this is a pass-through cost to
customers, the risk of these costs being higher or lower than expected ha s a lower impact on
reserves.
As shown in Figure 7, this financial plan projects the Rate Stabilization Reserves to be depleted
by FY 2020. In addition, in years where revenues are higher than expenses due to those being
CIP planning years, funds will be moved into the CIP reserve to help counter the following
year’s higher CIP related costs.
Figure 7: Gas Utility Reserves
Actual Reserve Levels for FY 2018 and Projections through FY 2024
SECTION 5 E : RISK ASSESSMENT AND RESERVES ADEQUA CY
This financial plan projects the Gas Utility’s primary contingency reserve, the Operations
Reserve, to be within guideline levels throughout the forecast period, barring either short-run
budget savings and/or larger future increases. Figure 8 shows the Operations Reserve within
the guideline levels.
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Figure 8: Operations Reserve Adequacy
Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility.
Table 13 summarizes the risk assessment calculation for the Gas Utility through FY 2024. The
risk assessment includes the revenue shortfall that could accrue due to:
1. Lower than forecasted distribution sales revenue; and
2. An increase of 10% of planned system improvement CIP expenditures for the budget
year.
Table 13: Gas Risk Assessment ($000)
FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Total non-commodity revenue $23,518 $26,174 $29,159 $31,355 $32,773
Max. revenue variance, previous ten years 16% 16% 16% 16% 16%
Risk of revenue loss $3,771 $4,197 $4,676 $5,028 $5,255
CIP Budget $1,008 $12,019 $1,012 $12,023 $1,040
CIP Contingency @10% $101 $1,202 $101 $1,202 $104
Total Risk Assessment value $3,872 $5,399 $4,777 $6,230 $5,359
Finally, the City created the CIP Reserve at the end of FY 2015 to act as a contingency reserve
for capital improvement projects. Current guidelines state that the balance of this reserve
should fall between 12 and 24 months of budgeted CIP expense, but staff will continue to
review this reserve and the appropriateness of the current minimum and maximum guideline
levels in light of the new alternating year CIP plan. In general, the current financial plan projects
continual average growth of the CIP reserve over time.
At the end of FY 2018, the sum of the CIP Reserve and existing Commitments was $8 million, as
shown in Figure 7.
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SECTION 5 F : LONG -TERM OUTLOOK
In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity
costs. A variety of long-term trends could affect commodity costs either positively or negatively.
Continuing improvement in gas extraction technology, such as fracking, could continue to
create generous supplies of gas, but these technologies are also under greater scrutiny with
respect to their environmental impacts. On the demand side, a continued shift from coal to
natural gas for electricity generation, an expansion of export capabilities, or an increase in
manufacturing in the U.S. might drive up natural gas prices, but other factors, such as generally
more mild winters or an increased drive towards electrification, might drive gas demand lower.
It is also difficult to predict the magnitude of the additional cost impacts associated with the
State’s cap-and-trade program over the long term. In the face of this uncertainty, CPAU is able
to protect the financial position of the Gas Utility by continuing its current strategy of passing
these costs directly to its customers via month-varying rate adjustment mechanisms. The City
pursues a policy of purchasing offsets to make gas usage in Palo Alto carbon neutral. The cost is
not to exceed $0.10/therm.
Future CIP investment needs for the Gas Utility may be lower than in the past, although costs
per foot for main replacement have been increasing substantially. The Gas Utility has replaced
nearly all of its ABS gas mains and its most problematic steel and PVC mains as well . The PE pipe
being used now is expected to have at least a fifty-year lifetime, and there is growing evidence
that it may last much longer than that. This would result in lower CIP investment over the long
term. CPAU is considering performing a study in the near future to develop its future main
replacements priorities and strategy.
Long-term state or local climate goals could also have a major impact on the Gas Utility. The
Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas
(GHG) emissions to 1990 levels by 2020. In its December 2007 Climate Protection Plan, the City
set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto
achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and
industrial processes. However, to achieve the recently adopted Sustainability and Climate
Action Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s
adopted goal of an 80% reduction in emissions by 2050, extensive electrification of gas-using
appliances is necessary. If significant amounts of electrification occurred, stranded investment
and higher rates could be required as the costs of the distribution system are recovered over a
lower sales base. It is instructional that, in the recent discussion draft of its scoping plan update,
CARB says, to meet those goals, natural gas use would have to be “mostly phased out.”13 Staff
intends to begin evaluating how to manage potential impacts of these trends over the next few
years.
13 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment , California Air
Resources Board, October 2013, pg 88.
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SECTION 6 : D ETAILS AND A SSUMPTIONS
SECTION 6 A : GAS PURCHASE COSTS
The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always
cheaper than delivery at PG&E Citygate, even including the costs of transmission from Malin to
Citygate. The Gas Utility purchases gas on a month-ahead and day-ahead basis in the spot
market. The last few years have seen gas prices in a relatively narrow but low band. In FY 2019,
however, lower levels of natural gas in storage , along with colder than normal weather and
pipeline constraints on both the northern and southern borders of California has created some
short term price spikes, as shown in Figure 9.
Figure 9: Gas Market Prices at PG&E Citygate
On September 15, 2014, Council adopted Resolution #9451 authorizing the City’s participation
in a natural gas purchase from Municipal Gas Acquisition and Supply Corporation (MuniGas) for
the City’s entire retail gas load for a period of at least 10 years. The MuniGas transaction
includes a mechanism for municipal utilities to utilize their tax exempt status to achieve a
discount on the market price of gas. As of November 1, 2018, gas began flowing under this
program, reducing the City’s gas commodity cost by about $1 Million per year and saving gas
customers approximately $0.03 per therm on the commodity portion of their bills.
Gas commodity costs are expected to increase slowly but steadily over the next several years.
Figure 10 shows the projected gas prices used to generate this forecast. Projections for
transmission costs associated with transporting gas over PG&E’s Redwood transmission
pipeline (from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most
recent update to the Gas Accord.
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Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary
adder to PG&E’s local transportation rate,14 but in December 2014 PG&E applied to the CPUC to
more than double local transportation costs. The application was not settled until late 2016. As
these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed
making these costs pass-through charge, similar to the commodity charge, and this became
effective in November 2016.
Figure 10: Wholesale Gas Price Projections
SECTION 6 B : OPERATIONS
Operations costs include the Customer Service, Demand Side Management, Operations and
Maintenance (including Engineering), Resource Management, and Administration categories in
Figure 11, below. Debt service, rent, and transfers are also included in Operations costs
(excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost
Categories includes detailed descriptions of the activities associated with these cost categories.
Operations costs are generally projected to increase by 2 to 4% per year. Salary and benefits,
inflation, and other assumptions match those used in the City’s long-range financial forecast.
Operations costs for FY 2019 to FY 2021 include funding for the cross-bore program. In the
1970s CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching
when installing new gas services. This created the possibility of cross-bores, which can happen
when a gas service is bored through a sewer lateral. Though cross-bores are very rare, they can
create a dangerous situation when a contractor attempts to clear a blocked sewer line, because
if the cross-bored gas service is damaged during the line, clearing it can result in a gas leak.
14 California Public Utilities Commission Advice Letter 3430-G, effective January 1, 2014. Also see CPUC Decision
12-12-30 regarding the Pipeline Safety Enhancement Plan Adder.
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CPAU has been inspecting new gas services since 2001, and in 2011 began video inspections of
the sewer laterals at the location of horizontally-drilled gas services installed before 2001. This
inspection program has cost roughly $1 million per year since FY 2012. While a majority of
sewer laterals have been inspected, staff has come across several services which are not able to
be scoped, either due to infiltration by roots or broken/collapsed pipe segments. Staff has
included $3 million in additional funding between FY 2019 and FY 2021 for this program, but
the program will likely require additional funding in future years to complete.
Figure 11: Historical and Projected Operational Costs
SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP)
The Gas Utility’s CIP program consists of the following programs and budgets:
• The Gas Main Replacement Program, under which the Gas Utility replaces aging gas
mains ranked to have the highest threat scores within the system.
• Customer Connections, which covers the cost when the Gas Utility installs new services
or upgrades existing services at a customer’s request in response to development or
redevelopment. The Gas Utility charges a fee to these customers to cover the cost of
these projects.
• Ongoing Projects, which covers the cost of routine meter, regulator, and service
replacement, minor projects to improve reliability or increase capacity, and other
general improvements.
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• Tools and Equipment, which covers the cost of capitalized equipment, such as
directional boring, gas pipeline maintenance and emergency equipment.
• One-time Projects, which represents occasional large projects that do not fall into any
other category.
Table 14 shows the current status of these project categories and future projected spending.
Table 14: Budgeted Gas CIP Spending ($000)
The Gas Main Replacement (GMR) Program is in the final stages of completing a major
milestone with the replacement of gas mains made from Acrylonitrile-Butadiene-Styrene (ABS)
plastic. The program to replace ABS and other low-performing materials within the gas system
started in the 1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily
slowed down its FY 2014 and 2015 CIP appropriations in this category in order to finalize the
last major ABS main replacement project and to catch up on projects that had accumulated due
to staffing issues. With the replacement of all ABS mains with Polyethylene (PE) plastic near
completion, the material most at risk for failure is the remaining Polyvinyl chloride (PVC) plastic
and steel (wrapped, with cathodic protection). The next focus of the GMR program will be the
replacement of all PVC mains with PE mains. CPAU is considering updating the Gas System
Master Plan to determine which sections of pipeline to prioritize and assist in determining the
pace of main replacement (approximately three miles of main each year, or 1.5% of the
system).
The current budget for the gas main replacement program takes into account the recent rise in
construction costs. Several factors are contributing to the increase in construction costs and
include economic recovery in the Bay Area, a greater focus on infrastructure improvement by
many municipal agencies, and the higher demand for utility contractors within these fields.
CPAU has seen the replacement cost per linear foot increase by 25% to 50% over the last
couple of years. The Gas Utility posted the most recent project for competitive bid (the
Upgrade Downtown Project) and this resulted in very few contractor bids and an eventual
contract price that was much higher than estimated (staff has requested $6.7 million additional
funding in FY 2018 related to this project) . Staff is beginning to include the higher construction
cost in future project estimates in order to maximize the amount of pipe replaced, as well as
insuring the overall integrity of the gas system. Currently, CPAU plans to replace as many aging
mains as possible within its current budget. However, if this trend of higher construction cost
continues, the Gas Utility may require larger CIP budgets and as a result, an increase in rates.
Project Category
Current
Budget*
Spending,
Curr. Yr
Remain.
Budget**Committed FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
One Time Projects 42 (31) 10 - - - - - -
Gas Main Replacement 11,584 (6,714) 4,870 4,237 - 11,000 - 11,000 -
Tools And Equipment 379 (69) 311 48 120 120 100 100 103
Ongoing Projects 1,101 (52) 1,049 8 888 900 912 924 937
Customer Connections 1,344 (547) 797 71 1,342 1,383 1,424 1,467 1,511
TOTAL 14,450 (7,413) 7,037 4,364 2,350 13,402 2,436 13,491 2,551
*Includes unspent funds from previous years carried forward or reappropriated into the current fiscal year
**Equal to CIP Reserves (Reserve for Reappropriations + Reserve for Commitments).
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This financial plan addresses these challenges in a way that will allow CPAU to meet its main
replacement needs. This financial plan includes approximately $11 million every other year for
main replacement construction instead of $6.5 million annually. This shift to larger main
replacement construction projects every other year will lengthen the amount of time needed to
replace all PVC pipes in the system, but will attract more contractors to bid on the larger
projects. Additionally, this main replacement project schedule for gas will be staggered with
water and wastewater (water and wastewater construction every even year and gas
construction every odd year), which will ease scheduling difficulties for inspection coverage due
to shared inspection staff across water, wastewater, gas, and large development services
projects. However, if staff sees a greater rate of failure of existing pipe materials, CIP projects
may resume a more frequent schedule and may require additional rate funding needs.
There is no new main replacement budgeted in FY 2020. However, work will continue on
ongoing main replacement projects in FY 2020 and FY 2021. This staggered schedule for gas
main replacement will allow staff to focus on current priorities such as the Upgrade Downtown
project. As the staff vacancies become filled and construction costs stabilize, staff can re -
evaluate the need to return to an annual replacement program.
Staff projects ongoing projects, tools and equipment, and customer connections to cost
approximately $2.4 million in FY 2020 and remain relatively flat through the end of the forecast
period. In practice, these projects can fluctuate dramatically depending on prices of material,
system conditions and the pace of development and redevelopment in the city. It is worth
noting that fee revenue pays for the Customer Connections program, so when costs go up fees
will be adjusted as well.
Aside from customer connections and transfers from other funds, the CIP plan for FY 2020 to FY
2024 is funded by utility rates. Appendix B: Gas Utility Capital Improvement Program (CIP)
Detail shows the details of the plan.
SECTION 6 D : DEBT SERVICE
The Gas Utility currently makes debt service payments on one bond issuance, 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 . $9.4 million of this issuance was
secured by the net revenues of the Gas Utility. Table 15 shows debt service for this bond for the
financial forecast period. Debt service on this bond will continue through 2026.
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Table 15: Gas Utility Debt Service
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
2011 Utility Revenue
Refunding Bonds, Series A
800 800 802 803 804 802
The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt
coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”15
equal to five times the annual debt service. The current financial plan complies with these
covenants throughout the forecast period, as shown in Table 16 and Table 17.
Table 16: Debt Service Coverage Ratio ($000)
FY
2019
FY
2020
FY
2021
FY
2022
FY
2023
FY
2024
Revenues 36,972 39,381 42,322 45,585 48,539 50,564
Expenses
(Excluding CIP and
Debt Service)
(26,265) (28,111) (28,851) (28,653) (29,400) (30,301)
Net Revenues 10,707 11,270 13,471 16,932 19,139 20,263
Debt Service 800 800 802 803 804 802
Coverage Ratio 1339% 1409% 1679% 2108% 2379% 2526%
Table 17: Debt Service Minimum Reserves ($000)
FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
Gas Utilitya 20,672 20,847 12,170 17,647 14,066 22,381
Debt Serviceb 800 800 802 803 804 802
Reserves Ratioc 26x 26x 15x 22x 17x 28x
a) CIP, Rate Stabilization, Operations, and Unassigned Reserves
b) Gas Utility’s share of the debt service on the 2011 bonds.
c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the
combined Electric, Gas, and Water Utility reserves and total debt service and is higher than shown here.
The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances
listed in Table 18, even though the Gas Utility is not responsible for the debt service payments .
The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities
are unable to make their debt service payments. Staff does not currently foresee this occurring.
15 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities
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Table 18: Other Issuances Secured by Gas Utility’s Revenues or Reserves
Bond Issuance Responsible Utilities Annual Debt
Service ($000)
Secured by Gas Utility’s:
Net Revenues Reserves
1995 Series A Utility
Revenue Bonds Storm Drain $680 Yes No
1999 Utility Revenue
Bonds, Series A
Wastewater Collection
Wastewater Treatment
Storm Drain
$1,207 No Yes
2009 Water Revenue
Bonds (Build America
Bonds)
Water $1,977* No Yes
*Net of Federal interest subsidy
SECTION 6 E : E QUITY T RANSFER
The City calculates the equity transfer from its Gas Utility based on a methodology adopted by
Council in 2009 that has remained unchanged since.16 Each year it is calculated according to the
2009 Council-adopted methodology, and does not require additional Council action.
SECTION 6 F : REVENUE S
The Gas Fund receives most of its revenues from sales of gas, but about 8% comes from other
sources. The largest of these comes from sales of allowances related to California’s cap-and-
trade program followed closely by service connection and capacity fees. Another revenue item
related to the cap-and-trade program is collected in customers’ bills. While the State provides
CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a
portion of those in accordance with the regulations. In order to have enough allowances to
cover customers’ natural gas emissions, CPAU must buy allowances at market, and
subsequently passes through the cost of those allowances to customers. The regulations do not
allow the revenue derived from the sale of the free allowances to offset allowance purchases,
thus the pass-through rate component.
This financial plan bases sales revenue projections on the load forecast in Section 5A: 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. Also,
changes in customer behavior, as well as changes to more efficient gas appliances, or switching
to electric appliances, will modify these forecasts. Staff continually evaluates forecasts to see
when new trends emerge.
16 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption
Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed
changes to equity transfer methodology.
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SECTION 6 G : COMMUNICATIONS PLAN
The FY 2020 Gas Utility communications strategy covers these primary areas: operations,
infrastructure, safety, efficiency, renewables, rates, and cost containment measures. The City of
Palo Alto Utilities (CPAU) communication methods include use of the Utilities website, utility bill
inserts, messaging on bills and envelopes, email newsletters, print and digital ads in local
publications, videos and participation in community outreach events. Since moving to market
pricing for commodity rates, the City of Palo Alto Utilities (CPAU) commodity rates can change
monthly. Staff post these updates to the Utilities rates webpages. Consistent with the newly
approved Utilities Strategic Plan, CPAU is instituting cost containment as an ongoing priority
that is part of our annual cycle.
In FY 2020, CPAU is proposing a 5 percent overall rate increase for the gas utility. However, we
anticipate that gas distribution rates will need to increase about 11% in FY 2020 due to a
resumption in capital improvement projects and an increase in commodity charges. Such
maintenance and operations projects are important to maintain a safe and reliable gas
distribution system. To keep customers apprised of the status and accomplishments of capital
improvement projects, the City maintains a network of project web pages. Print and digital ads,
social media and email blasts drive traffic to the website.
CPAU promotes gas use efficiency incentives year-round, but most heavily during winter
months to impact heating activities. CPAU continues to look for more ways to promote gas use
efficiency and awareness of the City’s carbon neutral natural gas utility. Programs such as the
Home Efficiency Genie and commercial energy efficiency programs help residents and
businesses better understand energy usage, activities and/or upgrades they can implement to
improve efficiency and keep utility costs low. CPAU will be launching an upgraded version of its
online utility account services portal this year, which can provide customers with direct access
and more information about utility account and consumption data.
CPAU emphasizes safety for all utility services year-round. Stepping up efforts to promote gas
safety education, staff is focusing outreach among stakeholders to increase awareness of the
need to call USA (811) before digging for anyone who may excavate in and around Palo Alto ,
such as plumbers and contractors. Staff is also focusing outreach on the importance of
contacting CPAU to check for potential sewer and gas line cross-bores prior to clearing a sewer
line. Additional outreach messaging includes keeping fats, oils and greases out of drains, and
ensuring clear access to meters. CPAU has developed a number of safety outreach materials to
distribute to customers at community outreach events, emergency preparedness fairs, school
and business meetings.
CPAU will continue to promote safety, infrastructure, operations, efficiency and rate
adjustment messages through a variety of marketing and media channels. Every year, CPAU
publishes an updated gas safety awareness brochure and mails it to all customers in Palo Alto,
as well as to emergency responders, public officials, plumbers, contractors and excavators that
may work in and around the area. Staff talk with business customers at special facilities
meetings, attend neighborhood safety and emergency preparedness fairs and offer
presentations to school and community groups. While print materials and website pages still
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feature prominently, CPAU is increasing emphasis on outreach through email newsletters,
direct mail, newspaper inserts, social media and online videos. The Gas Safety Public Awareness
Plan contains saved copies of all outreach materials and logs of activities; the Department of
Transportation typically reviews this Plan at least once per year.
GAS UTILITY FINANCIAL PLAN
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APPENDICES
Appendix A: Gas Financial Forecast Detail
Appendix B: Gas Utility Capital Improvement Program (CIP) Detail
Appendix C: Gas Utility Reserves Management Practices
Appendix D: Description of Gas Utility Cost Categories
Appendix E: Gas Utility Communications Samples
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APPENDIX A : GAS FINANCIAL FORECA ST D ETAIL
Actual Actual
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
1 RATE CHANGE (%)*0%0%0%8%0%4%5%8%8%6%4%
2 SALES IN THOUSAND THERMS 28,117 28,881 26,719 28,146 28,314 27,921 27,725 27,531 27,339 27,147 26,957
3
4 Utilities Retail Sales 34,843 29,515 28,065 34,110 34,056 33,548 35,480 37,946 40,956 43,271 44,892
5 Service Connection & Capacity Fees 654 748 961 940 1,078 1,079 1,111 1,145 1,179 1,179 1,179
6 Other Revenues & Transfers In 313 414 2,346 694 1,739 1,871 2,404 2,806 3,233 3,683 4,154
7 Interest plus Gain or Loss on Investment 706 450 730 13 26 474 386 425 217 406 339
8 Total Sources of Funds 36,517 31,127 32,102 35,758 36,899 36,972 39,381 42,322 45,585 48,539 50,564
9
10 Purchases of Utilities:
11 Supply Commodity & Cap and Trade 12,992 9,537 9,178 9,720 9,698 9,514 10,009 10,279 10,550 10,871 11,404
12 Supply Transportation 1,333 982 (1,051)2,843 3,223 3,507 4,354 4,450 4,625 4,705 4,719
13 Total Purchases 14,325 10,519 8,127 12,563 12,921 13,022 14,362 14,729 15,174 15,576 16,122
14
15 Administration (CIP + Operating)3,988 3,764 2,881 2,553 3,598 3,682 3,790 3,880 3,967 4,057 4,149
16 Customer Service 1,338 1,421 1,364 1,441 1,508 1,551 1,632 1,684 1,732 1,782 1,833
17 Demand Side Management 438 632 566 855 826 845 870 890 910 931 952
18 Engineering (Operating)352 369 426 355 351 360 373 383 393 403 413
19 Operations and Maintenance 4,119 4,403 4,153 4,321 4,620 5,747 5,988 6,157 5,318 5,462 5,611
20 Resource Management 516 556 472 566 357 441 463 477 491 505 519
21 Debt Service Payments 805 803 248 226 203 800 800 802 803 804 802
22 Rent 419 431 443 455 602 618 634 651 668 685 704
23 Transfers to General Fund 5,811 5,730 6,194 6,726 6,699 6,601 7,106 7,088 7,343 7,536 7,688
24 Other Transfers Out 606 151 303 510 808 824 840 856 872 889 906
25 Capital Improvement Programs 1,026 1,832 6,889 2,214 7,804 5,567 2,350 13,402 2,436 13,490 2,551
26 Total Uses of Funds 33,743 30,611 32,066 32,785 40,297 40,057 39,206 50,999 40,108 52,120 42,249
27
28 Into/ (Out of) Reserves 2,773 516 36 2,972 (3,397)(3,084)175 (8,677)5,477 (3,581)8,315
29
30 Reappropriations + Commitments 11,305 6,491 6,255 4,209 4,209 4,209 4,209 4,209 4,209 4,209 4,209
31 Plant Replacement 0 0 0 0 0 0 0 0 0 0 0
Debt Service Reserve 826 826 816 813 795 795 795 795 795 795 795
32 CIP Reserve 0 1,591 3,820 3,820 3,820 3,820 9,820 600 5,100 1,100 9,100
33 Rate Stabilization 15,981 7,215 6,018 6,539 7,090 6,363 0 0 0 0 0
34 Operations Reserve 0 10,847 10,296 13,549 8,638 6,281 6,818 7,361 8,338 8,757 9,072
35 Unassigned 0 0 0 0 0 0 0 0 0 0 0
36 Total Reserves 28,112 26,970 27,205 28,930 24,551 21,466 21,641 12,964 18,441 14,860 23,175
37 (1,142)236 1,725 (4,379)(3,084)175 (8,677)5,477 (3,581)8,315
38 Short Term Risk Assessment Value 1,226 3,753 3,516 4,051 3,941 3,872 5,399 4,777 6,230 5,359
39
40 Operations Reserve Guidelines
41 Min (60 Days Commodity + O&M) 5,616 5,000 5,585 5,171 5,718 6,062 6,150 6,124 6,240 6,372
42 Target (90 Days Commodity + O&M) 8,424 7,500 8,377 7,756 8,577 9,093 9,225 9,186 9,360 9,557
43 Max (120 Days Commodity + O&M) 11,233 10,000 11,169 10,341 11,437 12,124 12,300 12,248 12,481 12,743
44
City of Palo Alto
Gas Utility
Fiscal Year
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APPENDIX B : GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
ONE TIME PROJECTS
GS-15001 Security at Receiving Stations 41,534 - - (31,134) 10,400 - - - - - -
Subtotal, One-time Projects 41,534 - - (31,134) 10,400 - - - - - -
GAS MAIN REPLACEMENT (GMR) PROGRAM
GS-11000 GMR - Project 21 100,000 - - - 100,000 - - - - - -
GS-12001 GMR - Project 22 8,633,799 800,000 - (6,651,737) 2,782,062 2,737,035 - - - - -
GS-13001 GMR - Project 23 - 550,000 - (61,950) 488,050 - - 10,000,000 - - -
GS-14003 GMR - Project 24 - - - - - - - 1,000,000 - 10,000,000 -
GS-15000 GMR - Project 25 - - - - - - - - - 1,000,000 -
GS-18000 Gas ABS/Tenite Replacement - 1,500,000 - - 1,500,000 1,500,000 - - - - -
Subtotal, Gas Main Replacement Program 8,733,799 2,850,000 - (6,713,687) 4,870,112 4,237,035 - 11,000,000 - 11,000,000 -
TOOLS AND EQUIPMENT
GS-13002 General Shop Equipment/Tools - 350,000 - (66,642) 283,358 40,613 100,000 100,000 100,000 100,000 103,000
GS-14004 Gas Distribution System Model 9,357 20,000 - (2,157) 27,200 7,200 20,000 20,000 - - -
Subtotal, Tools and Equipment 9,357 370,000 - (68,799) 310,558 47,813 120,000 120,000 100,000 100,000 103,000
Project #Project Name
Reappropriated /
Carried Forward from
Previous Years
Current Year
Funding
Budget
Amendments
Spending,
Current Year
Remaining in
CIP Reserve
Fund Commitments FY 2020 FY 2021 FY 2022 FY 2023 FY 2024
ONGOING PROJECTS
GS-11002 Gas System Improvements 7,979 246,036 - - 254,015 7,979 500,000 500,000 500,000 500,000 500,000
GS-03009 System Ext. - Unreimbursed - 421,180 - (24,814) 396,366 - - - - - -
GS-80019 Gas Meters and Regulators 48,804 376,652 - (26,972) 398,484 - 387,952 399,591 411,579 423,926 436,644
Subtotal, Ongoing Projects 56,783 1,043,868 - (51,786) 1,048,865 7,979 887,952 899,591 911,579 923,926 936,644
CUSTOMER CONNECTIONS (FEE FUNDED)
GS-80017 Gas System Extensions 40,991 1,303,315 - (547,144) 797,162 71,093 1,342,415 1,382,688 1,424,169 1,466,894 1,510,901
Subtotal, Customer Connections 40,991 1,303,315 - (547,144) 797,162 71,093 1,342,415 1,382,688 1,424,169 1,466,894 1,510,901
GRAND TOTAL 8,882,464 5,567,183 - (7,412,550) 7,037,097 4,363,920 2,350,367 13,402,279 2,435,748 13,490,820 2,550,545
Funding Sources
Connection Fees 1,017,000 - 1,047,510 1,078,935 1,111,303 1,144,642 1,178,981
Utility Rates 4,550,183 - 1,302,857 12,323,344 1,324,445 12,346,178 1,371,564
CIP-RELATED RESERVES DETAIL
6/30/2018
(Actual)
6/30/2019
(Unaudited)
Reappropriations 808,464 2,673,177
Commitments 8,074,000 4,363,920
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APPENDIX C : 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) Any funds not included in the other reserves will be cons idered Unassigned Reserves
and shall be returned to ratepayers or assigned a specific purpose as described in
Section 9 (Unassigned Reserves)
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
GAS UTILITY FINANCIAL PLAN
M a r c h 2 0 1 9 38 | P a g e
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. These guideline levels
are calculated for each fiscal year of the Financial Planning Period based on the levels of
CIP expense budgeted for that year.
Minimum Level 12 months of budgeted CIP expense
Maximum Level 24 months of budgeted CIP expense
b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and
the Reserve for Commitments when funds are added to or removed from the Reserve
for Commitments as a result of a change in contractual commitments related to CIP
projects. Any other additions to or withdrawals from the CIP reserve require Council
action.
c) Minimum Level:
i) Funds held in the Reserve for Commitments may be counted as part of the CIP
Reserve for the purpose of determining compliance with the CIP Reserve minimum
guideline level.
ii) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present
a plan to the City Council to replenish the reserve. The plan shall be delivered by the
end of the following fiscal year, and shall, at a minimum, result in the reserve
reaching its minimum level by the end of the next fiscal year. For example, if the CIP
Reserve is below its minimum level at the end of FY 2017, staff must present a plan
by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In
addition, staff may present, and the Council may adopt, an alternative plan that
takes longer than one year to replenish the reserve, or that does so in a shorter
period of time.
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
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 .
GAS UTILITY FINANCIAL PLAN
M a r c h 2 0 1 9 39 | P a g e
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.
Minimum Level 60 days of O&M and commodity expense
Target Level 90 days of O&M and commodity expense
Maximum Level 120 days of O&M and commodity expense
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.
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 Unassign ed 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.
GAS UTILITY FINANCIAL PLAN
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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 an amount
equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from
the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa. Such
transfers shall be included in the ordinance closing the budget for the fiscal year.
GAS UTILITY FINANCIAL PLAN
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APPENDIX D : DESCRIPTION OF GAS UTILITY COST CATEGORIES
This appendix describes the activities associated with the various cost categories referred to in
this Financial Plan.
Customer Service: This category includes the Gas Utility’s share of the call center, meter
reading, collections, and billing support functions. Billing support encompasses staff time
associated with bill investigations and quality control on certain aspects of the billing process. It
does not include maintenance of the billing system itself, which is included in Administration .
This category also includes CPAU’s key account representatives, who work with large
commercial customers who have more complex requirements for their gas services.
Resource Management: This category includes gas procurement, contract management, rate
setting, and tracking of legislation and regulation related to the gas industry.
Operations and Maintenance: This category includes the costs of a variety of distribution
system maintenance activities, including:
• surveying the gas system (50% of the system each year) and repairing any leaks found;
• investigating reports of damaged mains or services and perform emergency repairs;
• building and replacing gas services for new or redeveloped buildings; and
• testing and replacing meters to ensure accurate sales metering.
This category also includes a variety of functions the utility shares with other City utilities,
including:
• the Field Services team (which does field research of various customer service issues);
• the Cathodic Protection team (which monitors and maintains the systems that prevent
corrosion in metal pipes and reservoirs); and
• the General Services team (which manages and maintains equipment, paves and
restores streets after gas, water, or sewer main replacements, and provides welding
services, including certified gas line welding services)
Administration: Accounting, purchasing, legal, and other administrative functions provided by
the City’s General Fund staff, as well as shared communications services and Utilities
Department administrative overhead and billing system maintenance costs.
Demand Side Management: Includes the cost of administering gas efficiency programs and the
direct cost of rebates paid.
Engineering (Operating): The Gas Utility’s engineers focus primarily on the CIP, but a small
portion of their time is spent assisting with distribution system maintenance.
APPENDIX E : GAS UTILITY COMMUNIC ATIONS SAMPLES
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Attachment C
* NOT YET APPROVED *
Resolution No. _________
Resolution of the Council of the City of Palo Alto Increasing Gas
Rates by 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 Service)
R E C I T A L S
A. 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 utilit y services,
fees and charges.
B. On ____, 2019, 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. 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
incorporated. Utility Rate Schedule G-1, as amended, shall become effective July 1, 2019.
SECTION 2. 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, 2019.
SECTION 3. 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, 2019.
SECTION 4. 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, 2019.
SECTION 5. The City Council finds as follows:
a. Revenues derived from the gas rates approved by this resolution do not exceed the
funds required to provide gas service.
b. Revenues derived from the gas rates approved by this resolution 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.
Attachment C
* NOT YET APPROVED *
SECTION 6. 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 7. The Council finds that the adoption of this resolution 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 th e
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 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.
Attachment C
* NOT YET APPROVED *
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
Overview of Gas Utility Hedging Program
Natural gas commodity prices depend on market supply and demand balances and can be unpredictable
and volatile. Gas market price increases during the energy crisis drained approximately $8 million from
the Gas Supply Rate Stabilization Reserve and required four large rate increases in fiscal year 2001. As a
result, the City of Palo Alto initiated a rate stabilization program whereby a portion of gas needs were
purchased at fixed and capped prices over a rolling 36-month time horizon. That hedging strategy was
implemented for about 10 years until shale production shifted the supply/demand balance, market
prices decreased, and City Council became concerned that Palo Alto’s gas rates were higher than rates in
neighboring communities served by PG&E.
In 2011, Council approved a monthly pass-through market-based gas commodity rate. The revised policy
was driven by several factors:
1. Over the long term, the cost of Palo Alto’s gas portfolio will be equal to the gas market
regardless of the hedging strategy;
2. A monthly pass-through rate maintains parity with PG&E;
3. Gas bills vary dramatically by season due to usage patterns much more than they vary due to
commodity rate changes;
4. Market-based rates are more likely to reflect the state of the overall economy thus giving
customers a break during downturns;
5. The need for financial reserves is reduced; and
6. Simplifying the portfolio saves staff time.
Staff Report #21061 is the Finance Committee recommendation to Council to abandon the hedging
program and move to pass-through rates. The report includes more historical context, a robust analysis
of market price volatility, and the impact to customer bills.
The resulting revisions to the Gas Utility Long-term Plan are described in Staff Report #2552.2
1 https://www.cityofpaloalto.org/civicax/filebank/documents/42836
2 https://www.cityofpaloalto.org/civicax/filebank/documents/41656