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NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956
I.ROLL CALL
II.ORAL COMMUNICATIONS
Members of the public are invited to address the Commission on any subject not on the agenda. A reasonable time
restriction may be imposed at the discretion of the Chair. State law generally precludes the UAC from discussing or
acting upon any topic initially presented during oral communication.
III.APPROVAL OF THE MINUTES
Approval of the Minutes of the Utilities Advisory Commission Meeting held on May 1, 2019
IV.AGENDA REVIEW AND REVISIONS
V.REPORTS FROM COMMISSIONER MEETINGS/EVENTS
VI.GENERAL MANAGER OF UTILITIES REPORT
VII.COMMISSIONER COMMENTS
VIII.UNFINISHED BUSINESS - None
IX.NEW BUSINESS
1.Election of Officers Action
2.Discussion of Electric Vehicle and Building Decarbonization Sustainability/Climate Discussion
Action Plan Implementation Plans
3.Discussion of Electric Supply Carbon Accounting Methodology and RPS Discussion
Compliance Strategy
4.Discussion of Natural Gas Leakage from the City of Palo Alto’s Gas Distribution System Discussion
5.Discussion and Update on Fiber and AMI Planning Discussion
6.Discussion and Status of Water Leak Bill Credits Discussion
7.Selection of Potential Topic(s) for Discussion at Future UAC Meeting Action
NEXT SCHEDULED MEETING: August 7, 2019
ADDITIONAL INFORMATION - The materials below are provided for informational purposes, not for action or discussion
during UAC Meetings (Govt. Code Section 54954.2(a)(2)).
Informational Reports 12-Month Rolling Calendar Public Letter(s) to the UAC
UTILITIES ADVISORY COMMISSION – REGULAR MEETING
WEDNESDAY, JUNE 5, 2019 – 7:00 P.M.
COUNCIL CHAMBERS
Palo Alto City Hall – 250 Hamilton Avenue
Revised
Chairman: Michael Danaher Vice Chair: Vacant Commissioners: Lisa Forssell, Donald Jackson, A.C. Johnston, Gregory Scharff, Lauren Segal and Loren Smith Council Liaison: Tom DuBois
Utilities Advisory Commission Minutes Approved on: Page 1 of 11
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF MAY 1, 2019 SPECIAL MEETING
CALL TO ORDER
Chair Danaher called the meeting of the Utilities Advisory Commission (UAC) to order at 5:00 p.m.
Present: Chair Danaher, Vice Chair Schwartz, Commissioners Forssell, Johnston, and Segal
Absent: Commissioner Trumbull
ORAL COMMUNICATIONS
Tom Kabat, Carbon Free Silicon Valley, shared the history of the gas utility in Palo Alto and historical fuel
switching from town gas to natural gas. He emphasized that the Gas Utility could help the City meet City and
State climate goal by evolving from delivering heat by chemical delivery to delivering thermal services directly
through measures like district heating; and whether it could pivot once again to become a heating utility
rather than a gas utility.
APPROVAL OF THE MINUTES
Chair Danaher noted Commissioner Ballantine had resigned from the Commission prior to the April meeting.
Vice Chair Schwartz requested the second paragraph on page 7 state "Commissioner Segal believed the
Council should decide whether anybody pays for the additional costs." In the next paragraph, "Vice Chair
Schwartz appears to be less inclined to allow a choice" should be deleted. The following sentence should be
"Vice Chair Schwartz clarified that while it is important to listen to community concerns, it would be a better
choice to find eight to ten households that are willing to host pad-mounted equipment."
Commissioner Johnston moved to approve the minutes of the April 9, 2019 meeting as amended.
Commissioner Segal seconded the motion. The motion carried 5-0 with Chair Danaher, Vice Chair Schwartz,
and Commissioners Forssell, Johnston, and Segal voting yes, and Commissioner Trumbull absent.
AGENDA REVIEW AND REVISIONS
None.
REPORTS FROM COMMISSIONER MEETINGS/EVENTS
Commissioner Segal reported she attended the Recycled Water Strategic Plan public meeting. The meeting
laid out the current possible options for recycled water use, both potable and non-potable. She encouraged
everyone to review the informative slides. There are many opportunities, economics, and timelines for use
of recycled water, both potable and non-potable and within the City and beyond the City.
Catherine Elvert, Communications Manager, reported the slides would be shared with the Commission. The
slides are valuable information to share with the community.
DRAFT
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Commissioner Johnston advised that he attended a presentation by Stanford Professor Richard Luthy, who
spoke about recycling treated water and stormwater runoff. Commissioners may be interested in hearing
about options people are trying.
Vice Chair Schwartz indicated she attended the Energy Thought Leadership Summit. She was pleased that
utilities are talking about customer engagement and implementing people-first programs. After hearing
discussions about data privacy and data governance in relation to automated metering infrastructure (AMI),
she suggested City of Palo Alto Utilities (CPAU) should understand data privacy and governance in order to
ensure legacy systems are aligned. The Department of Energy (DOE) has produced a document that shows
the benefits of AMI exceed the original business cases. Vice Chair Schwartz also attended the Low Income
Energy Issues Forum, where she presented information regarding low-income community solar. Community
solar projects become part of microgrids and other applications around sustainability and community buy-in
that may be issues for Palo Alto. When combined with other things, local solar can be valuable at the local
level.
GENERAL MANAGER OF UTILITIES REPORT
Jonathan Abendschein, Assistant Director of Resource Management, delivered the General Manager’s
Report.
Recycled Water Strategic Plan Public Meeting - Utilities, Public Works, and Valley Water hosted a public
meeting yesterday to request input on possible projects the City could explore for expanding use of recycled
water from the Regional Water Quality Control Plant. The information presented was similar to the material
provided to the UAC in October 2018 and to City Council at a December 2018 study session. The discussion
included options for both non-potable and potable uses of recycled water. The City should be able to follow
up with interested stakeholders after reviewing public feedback.
Utilities Rates Adjustments – Staff has been developing a communication strategy and public outreach
materials for the utilities rate changes proposed to take effect on July 1, 2019. You will see some of the key
messages that will be incorporated into our outreach in the draft document before you tonight. This will be
further refined for public circulation. In an effort to provide clear and transparent information to all affected
stakeholders, we will communicate through a variety of outreach channels including web, utility bill inserts,
social media, digital and print announcements. All water and wastewater customers will receive a printed
letter in the mail within the next one to two weeks with details on those rates, per our notification
requirements through Proposition 218.
Update on Crossbore Program – The City’s Crossbore Verification Program investigates privately-owned and
City-owned sewer lines to ensure that there are no natural gas lines accidentally crossbored through them.
Utilities video-inspects sanitary sewer laterals and makes repairs free of charge to customers if a crossbore
is found. Phase 1 of the program was completed in 2013. At that time, we identified 26 gas crossbores which
were subsequently repaired, and verified that more than 7,000 other parcels were clear of a potential
crossbore. Phase 2 of the program will include a 2-year contract to inspect remaining sewer laterals at various
locations that have been determined to be a higher priority for inspection. The City received four bids from
qualified contractors for the phase 2 contract. A bid submitted by AIMS Companies came in 45% lower than
our staff’s initial engineering estimate. Since this leaves available funding in our budget, we recommend
taking this opportunity to increase the number of sewer laterals inspected in this phase of the program from
1,200 to 2,500 locations. The Council approval date is scheduled for June 24. The total not-to-exceed contract
amount is about $1.7 million.
Media Coverage of Palo Alto’s Energy Resources – A local reporter for the Palo Alto Weekly has recently
been publishing blog posts about our Utilities energy resources portfolio. After speaking with
communications and resource planning staff, she is now writing a series of well-informed, educational articles
which help share with the public more about what we do for environmental sustainability. This media
Utilities Advisory Commission Minutes Approved on: Page 3 of 11
coverage provides an insightful look at how we procure energy resources, what is considered renewable
versus non-renewable energy, what is Consumer Choice Aggregation (CCA), related legislation that could
impact publicly owned utilities and CCAs, and what it means to be carbon neutral. We encourage you to take
a look at this blog titled, “A New Shade of Green,” in Palo Alto Online.
Mayor’s Green Business Award – Join us at the Mayor’s Green Business Leader Awards presentation on May
20. This award program recognizes property managers whose buildings earn an EPA Energy Star, LEED Gold
or Platinum status. This year we will be honoring 27 buildings, representing over 2 million square feet of
commercial space, which were Energy Star rated in 2018. We also have six properties that became LEED Gold
certified and one property that obtained the elite LEED Platinum status. The awards ceremony will take place
at the beginning of the May 20 City Council meeting.
COMMISSIONER COMMENTS
None.
UNFINISHED BUSINESS
None.
NEW BUSINESS
ITEM 1: DISCUSSION: Discussion of Carbon Emissions Accounting Options for the City's Electric Supply
Portfolio.
Lena Perkins, Acting Senior Resource Planner, reported the UAC has discussed the definition of carbon
neutrality many times. The Palo Alto Carbon Neutral Electric Supply Plan was established in 2013 and called
for carbon neutral supplies to match load on an annual basis. That made sense at the time because the
emissions of the grid did not vary much throughout the course of the year. It was also consistent with the
Climate Registry Protocol. The duck curve first appeared in 2013. Now, carbon emissions vary tremendously
throughout the course of the day and throughout the course of the year. Over a year, CPAU has excess power
in the summer months and power deficits in the winter months. In a 24-hour period, CPAU has power deficits
throughout the day in January and excess power during parts of the day in July. In July, CPAU has excess
power in the evening hours because CPAU dispatches its hydroelectric during peak evening hours. Currently,
the accounting methodology for calculating the portfolio’s carbon emissions is an annual basis. An average
(as opposed to marginal) hourly basis is most appropriate for a portfolio inventory. 2020 changes relate to
unbundled Renewable Energy Certificates (REC). These RECs currently show up as zero carbon on CPAU's
power content label but will show up as carbon emitting on CPAU's 2020 power content label.
In response to Commissioner Forssell's question about the California Energy Commission (CEC) reaching a
decision regarding the accounting methodology, Perkins replied the CEC has not made a decision. Over the
past year, the CEC has been consistent that carbon emissions will be associated with bucket 3 RECs. CPAU
buys bucket 3 RECs in a below-average hydroelectric year in order to green up market purchases. CPAU buys
unspecified market power because CPAU does not have sufficient energy on an annual basis. The UAC
previously expressed a preference for lowering costs, which means procuring as many bucket 3 RECs as
allowed under a minimally compliant Renewable Portfolio Standard (RPS). Each year, 10% of load would be
bucket 3 RECs, which would look dirty on the power content label under the CEC’s methodology, which would
be a communications challenge to explain.
Vice Chair Schwartz remarked that using the word “dirty” to refer to fossil-fueled generation is simplistic
when reliability and having lights and heat at night are also considerations. Perkins said that she was
attempting to use the simplest words possible and suggested the use of "carbon emitting" in place of "dirty."
In reply to Commissioner Forssell's inquiry regarding unbundled RECs and bucket 3 RECs being equivalent,
Perkins advised that they are the same. Commissioner Forssell clarified that the carbon emissions were going
to show up on the power content label only in a dry hydroelectric year. Perkins stated the previous feedback
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from the UAC was to maximize unbundled REC bucket 3 purchases in order to have the cheapest electricity
portfolio possible. Staff had not implemented that because the accounting methodology change was being
considered by the CEC. Jonathan Abendschein, Assistant Director of Resource Management, explained that
CPAU currently has about 10% more carbon-free energy than its load in an average hydroelectric year, a
surplus on an annual basis. The current definition of carbon neutrality is on an annual basis. CPAU is exceeding
its Carbon Neutral Portfolio goals in an average hydroelectric year and could sell energy while still complying
with the current policy. In a significantly below-average hydroelectric year when CPAU's renewable and
carbon-free energy drops below 100%, CPAU would buy unbundled RECs under the current policy. Staff heard
the UAC's interest in reducing costs as much as possible. If the City retained an annual accounting
methodology, CPAU could eliminate the 10% surplus and reduce renewable energy to match load, while still
reporting no carbon emissions in an average year. CPAU could also sell even more of the renewable energy
from long-term contracts, and buy unbundled RECs instead. That would be the cheapest possible portfolio
that is compliant with CPAU and State policies, but it would appear carbon-emitting under the CEC’s power
content label methodology. In reply to Commissioner Forssell's question about selling bundled RECs and
buying unbundled RECs in an average hydroelectric year in order to arbitrage the bundle/unbundled financial
opportunity, Abendschein commented that that policy option is a possibility. Perkins added that there is a
difference between what the power content label shows and RPS eligibility. She corrected an earlier
statement in that 10% of CPAU's RPS compliance would be potentially unbundled RECs or bucket 3 RECs. If
CPAU's RPS mandate is 40% in this period, then 4% of the portfolio would appear dirty.
Perkins continued the presentation, stating if CPAU continues with annual accounting, a change from the CEC
would cause CPAU's portfolio to appear dirtier. Average emissions are calculated as total emissions of the
grid divided by total energy generation. Marginal emissions are the emissions intensity of the last unit called
upon to deliver the last unit of electricity. Marginal emissions are useful for thinking about an individual
action, especially load shifting. When reviewing the carbon emissions of the entire portfolio on an inventory
basis, marginal emissions would not be appropriate.
Vice Chair Schwartz remarked that changing the methodology would demonstrate leadership in the industry.
From a positioning standpoint, she proposed Commissioners look at this as measuring true decarbonization
and to define decarbonization as a process. Commissioners should emphasize that the process is ongoing. In
answer to Vice Chair Schwartz's query regarding staff's ability to use marginal emissions to analyze the effect
of everybody in Palo Alto switching to heat pump space and water heating, Perkins indicated the analysis was
possible because staff had a new reporting tool for energy efficiency into which staff has incorporated
electrification measures. Staff is using marginal emissions for that tool.
Chair Danaher commented that the goal is to be as accurate as possible regarding the carbon load. Hourly
accounting appears to be much more accurate than annual accounting. CPAU is an average user, and average
emissions makes more sense than marginal emissions. Marginal overstates things. He asked Commissioners
to nod if they agreed with that comment. He noted that all the Commissioners were nodding. Commissioners
agree that average is the right methodology rather than marginal. Perkins remarked that CPAU's
methodology could be more accurate, but noted the portfolio would still appear to be emitting carbon under
the CEC regulations. Vice Chair Schwartz indicated CPAU's leadership is part of what caused the dilemma in
the first place. CPAU owes it to everybody to be leaders and to be more accurate.
Commissioner Forssell felt it would be useful to consider the goal of communications when discussing
communication challenges. The communications challenge has a lot of complexity. She had heard two
Mayors refer to CPAU as 100% renewable. Perkins noted that it was unnecessary to have every customer
receive only carbon-free electricity at all hours, treating Palo Alto as an island. In fact, it could be argued that
a bucket 3 REC outside of California could be more impactful than buying a California REC to ensure Palo Alto
customers received only carbon-free electricity at all hours. For example, an unbundled or bucket 3 REC could
help make a coal plant less economical relative to wind and offset more carbon, even though it's cheaper
than an in-state REC.
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In response to Chair Danaher's inquiry regarding the CEC's rationale to exclude unbundled RECs, Perkins
reported there was concern about customer confusion and accurately representing that the power is not
100% carbon free even if it appears 100% renewable on the power content label.
Vice Chair Schwartz stated Palo Alto and the Community Choice Aggregators (CCA) are relying on PG&E and
other entities to provide the electrons at night. In order to tackle this problem as a society, society needs to
know what it's dealing with.
Chair Danaher understood CPAU could buy offsets for times when CPAU did not have clean energy. The
question is does it matter whether the offsets come from Wyoming or California. He favored using unbundled
RECs rather than offsets.
In reply to Commissioner Johnston's query regarding RECs acceptable to the CEC, Perkins advised that bucket
1 RECs will continue to appear as carbon neutral. Bucket 1 RECs are projects connected to the California
Independent System Operator (CAISO) and scheduled and bid into the CAISO. When those projects show up,
they back down natural gas generators. Bucket 2 RECs are strips of power imports to the CAISO. They may or
may not have carbon associated with them. Bucket 1 RECs cost about $22 per MWh, bucket 2 RECs cost
around $9 per MWh, and bucket 3 RECs cost approximately $1.50 per MWh. Offsets are separate and cost
about the same as bucket 2 RECs.
In answer to Vice Chair Schwartz's question about REC purchases covering a geothermal baseload supply,
Perkins indicated that gets into portfolio rebalancing. In portfolio rebalancing, CPAU could buy baseload
renewables or other higher cost renewables. Rebalancing to perfectly match renewable generation to load
would be the most expensive option. CPAU could also look at solar with storage, which staff is evaluating.
Supply funds could pay for a baseload renewable resource or solar with storage resource, but CPAU would
have to eliminate some existing contracts to do that. It would be substantially more expensive than using in-
state RECs or out-of-state RECs.
In response to Vice Chair Schwartz's inquiry regarding whether CPAU sold RECs with their surplus energy or
the surplus energy only, Perkins indicated CPAU holds the RECs and sells the energy in the market.
Abendschein noted that the discussion of carbon accounting has three phases. The current discussion is
informational or educational explaining what it would meant to have hourly accounting as a standard. The
next discussion with the UAC would be about the most cost-effective rebalanced portfolio possible under the
new policies. The most complementary and cost-effective way to achieve these low-carbon objectives will be
the third discussion. Perkins added that committing to an hourly accounting would narrow CPAU's options to
some extent and increase the amount of either RECs or additional renewable generation needed to match
load on an hourly basis.
In reply to Vice Chair Schwartz's query regarding the Council's preference for low-cost or carbon-free power,
Councilmember DuBois reported the Council will likely express both positions based on Council Members'
level of understanding. The communications challenge is almost a separate issue that should be discussed.
Abendschein clarified that discussions will be phased so that the Council understands the accounting
methodology and its impacts.
Commissioner Johnston commented that knowing the cost impacts will be important because there is a
tension between being cost effective and carbon free. Abendschein advised that staff has run some initial
models about costs but is not ready to share those with the UAC yet. He noted staff did not intend to make
portfolio decisions based on hourly accounting until the UAC and Council had a full understanding of the costs
of adopting an hourly accounting methodology.
Perkins noted the marginal price of electricity is correlated with the carbon due to the Cap and Trade system.
The last unit to come online in California sets the price for the five-minute interval. Because the price of
carbon is included in that price of generation and by dispatching hydroelectric for the maximum value, CPAU
Utilities Advisory Commission Minutes Approved on: Page 6 of 11
dispatches the hydroelectric to displace the most carbon. CPAU does that deliberately to maximize the value
of hydroelectric resources. By generating the most revenue from those hydroelectric resources, CPAU is also
displacing the most carbon. In the CAISO, which embeds a cost of carbon, CPAU hydroelectric resources
displace a lot of carbon in the worst hours of carbon intensity of the grid. In following the marginal price
signal, the price of carbon is actually increasing over time in the price signal. Following the price will be more
closely aligned with following the carbon over time as the price of carbon elevates.
Commissioner Forssell favored thinking of CPAU's emissions in the context of the western interconnect or at
least the CAISO rather than trying to think of Palo Alto as an island. She expressed interest in studies showing
CPAU how CPAU could displace more carbon using out of state RECs. There could be an opportunity not to
make a hard tradeoff. Displacing more carbon at a much lower price is worth learning about. In answer to
Commissioner Forssell's question regarding the 6 a.m. peaklet and 8:00 a.m. peaklet on the Calaveras for the
typical January day, Perkins suggested the peaklets could result from following the price signal because there
are morning and evening peaks. The graph is probably generated using actual dispatches for a month
averaged on a 24-hour basis so she wouldn't read too much into the 7:00 a.m. dip. Abendschein advised that
staff will provide additional information.
Commissioner Johnston stated being able to explain what CPAU receives when buying an unbundled REC and
the ecological value of that would be very important if the decision is to continue buying unbundled RECs.
Chair Danaher commented that if CPAU has to report both, CPAU should state the methodology is to measure
on an hourly basis and to buy RECs.
Vice Chair Schwartz suggested the issues can be communicated simply without necessarily having everybody
in town become an expert on bundled versus unbundled RECs. Communications can be both accurate and
accessible. Perkins explained that staff wants to understand the UAC's and Council's preferences for being
carbon free every hour of every day or carbon free on the power content label.
Commissioner Segal viewed communications as having two pieces, carbon emissions of the portfolio and
impacting behaviors.
ACTION: None
ITEM 2: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend 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).
Eric Keniston, Senior Resource Planner, reported staff will present the gas cost of service adjustment (COSA)
study when it is complete. Constructions costs have been escalating. Generally, natural gas market prices are
trending up. Transmission costs continue to increase. The cost of environmental programs continues to
increase. Operations and maintenance (O&M) costs are increasing by 3%-4% per year. Salaries and benefits
are increasing by 13%-24%. However, the total utility bill remains lower than utility bills for neighboring cities.
Staff recommends an 8% rate increase for residential customers and a 2%-3% increase for commercial
customers. About 65% of costs relate to distribution. About half of that relates to maintenance of the pipes
in the ground. About 14% of costs relate to capital investment. Gas supply costs are pass-through costs. The
rate increase is a distribution rate increase. The 8% rate increase on distribution will translate to about a 5%
overall utility rate change. Of the distribution rate increase, about 4.6% relates to Capital Improvement
Program (CIP) expense increases, about 3% relates to O&M expenses, and a little bit is due to load loss. Gas
supply cost drivers are generally volatile and follow market prices, rising PG&E gas transmission rates, and
rising Cap and Trade costs. The Carbon Neutral Gas Plan is saving a little bit of money from initial projections.
Operations and capital cost drivers are a regular rate of main replacement, increasing underground
Utilities Advisory Commission Minutes Approved on: Page 7 of 11
construction cost, temporary funding for the gas crossbore program, and increasing health, retirement and
associated overhead costs.
In response to Vice Chair Schwartz's inquiring regarding difficulty recruiting staff for the Gas Utility, Dave
Yuan, Strategic Business Manager, indicated recruiting for management positions is difficult, but overall
recruiting for the Gas Utility is not as difficult as for the Electric Utility.
Keniston continued the presentation, stating generally residential gas bills are lower in the winter and higher
in some of the summer months. The overall annual bill is lower than PG&E's bill. Commercial gas bills for
customers at the lower end of the spectrum compare favorably to PG&E's bills, but bills for customers at the
higher end of the spectrum are higher than PG&E's bills.
In reply to Commissioner Johnston's inquiry regarding the reason for bills being higher than PG&E bills in the
summer, Keniston explained that Palo Alto has a monthly customer charge that PG&E does not have. Yuan
added that the fixed meter charge is approximately $13 per month, which is approximately 65% of the
summer charge.
Keniston further stated most commercial customers will see a bill increase.
In answer to Vice Chair Schwartz's question regarding the potential effect on customer responses of
expressing a rate increase as dollars versus percentages, Catherine Elvert, Communications Manager,
reported the Assistant Director of Customer Support Services vehemently believes a dollar amount is the best
way to communicate a rate increase. Keniston added that many utilities report dollar amounts only.
Keniston concluded the presentation by relaying goals of aligning rates with costs, using reserves to smooth
rate increases, and replenishing and maintaining reserve health over the forecast horizon.
In response to Commissioner Johnston's inquiry regarding residential customers bearing the brunt of the rate
increase, Keniston explained that the current COSA study and the 2012 COSA study both recommended the
Gas Utility collect 42% of distribution costs from residential customers. Because residential customers are
more spread out, they represent a higher share of distribution costs than their load. In answer to
Commissioner Johnston's question about flexibility in the COSA study, Jonathan Abendschein, Assistant
Director of Resource Management, reported staff has really no flexibility to deviate from the COSA study.
Commissioner Johnston noted more of the monthly expense has shifted to a service charge rather than the
volumetric charge. Keniston advised that growth in costs since the 2012 study can be attributed to the
customer charge. Costs increase, but the number of customers does not; therefore, the charge per customer
grows. Vice Chair Schwartz remarked that this has an implication for residential electrification. More fixed
costs will be pushed onto a smaller number of customers who can't pay as much.
In answer to Commissioner Forssell's query regarding the Carbon Neutral Gas Plan saving money, Keniston
clarified that the gas pre-pay option is saving money, not the Carbon Neutral Gas Plan. Approximately half of
gas environmental costs are attributable to the Carbon Neutral Gas Plan. Yuan reported the actual carbon
offset for fiscal year 2018 was $1.3 million.
ACTION: Commissioner Forssell moved to recommend that the City Council adopt a Resolution approving the
Fiscal Year 2020 Gas Utility Financial Plan and 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). Commissioner Johnston seconded the
motion. The motion carried 5-0 with Chair Danaher, Vice Chair Schwartz, and Commissioners Forssell,
Johnston, and Segal voting yes and Commissioner Trumbull absent.
Commissioner Johnston hoped Staff would look for ways to ameliorate the burden on residential customers
and low-volume customers. Keniston reiterated that staff cannot change the COSA study. Staff ensures the
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methodology is consistent across COSA studies. Abendschein added that staff will look for cost-control
measures and other ways to contain rate increases.
Commissioner Segal remarked that customers are punished for focusing on conservation because their bills
increase as conservation increases. Methods to reward conservation would be great.
Vice Chair Schwartz suggested the rate assistance program could be renamed as an income-qualified program
to remove the stigma of an assistance program.
ITEM 3: ACTION: Staff Recommendation that the Utilities Advisory Commission Recommend that the City
Council Adopt the Proposed Operating and Capital Budgets for the Utilities Department for Fiscal Year 2020.
Anna Vuong, Senior Business Analyst, reported key performance indicators include a 12% reduction in sewer
overflows; 75 miles of sewer lines cleaned and flushed; 65 wood utility poles replaced; 92% compliance for
backflow devices; an average outage duration of 70 minutes per customer; achieved gas efficiency savings;
surpassed the State goal of achieving 50% of RPS savings by 2030; repair of 90 gas leaks; and total residential
bill average 12% lower than neighboring cities' bills. Overall, the customer satisfaction rating is 86%. The fiscal
year (FY) 2020 Proposed Budget totals $317 million, 46% of which is commodity purchases.
In response to Chair Danaher's inquiry regarding debt service, Vuong indicated CPAU has debt service for
bond repayment. Dave Yuan, Strategic Business Manager, added the Central Valley project.
Vuong continued the presentation, stating salaries and benefits are increasing approximately 12% due to
recently approved contracts with Service Employees International Union (SEIU) and Utilities Management
and Professional Association of Palo Alto (UMPAPA) and proactive pension funding. Commodity costs have
increased approximately 6%. Ongoing costs reflect the reclassification of the Assistant City Manager/Utilities
General Manager position to the Utilities General Manager position, the Power Engineer position to the
Electric Project Engineer position and reorganization of the Resource Management Division. One-time
operating costs include improvements to the Elwell Court office, the gas crossbore safety program, and a
contract for electric overhead maintenance. The FY 2020 CIP Budget totals $49.6 million or $20 million for
the electric fund, $16 million for the water fund, $3.7 million for the gas fund, $1.5 million for the fiber, and
$8 million for the wastewater fund. Initiatives for FY 2020 are gas and wastewater cost of service studies,
electric vehicle (EV) charger installations, a Recycled Water Strategic Plan, Fiber-AMI design, upgrade of the
Colorado Power Station, water main replacement project 27, transmission repair at Old Page Mill,
replacement of the Corte Madera Reservoir, replacement of sanitary sewer 28B, and extension of fiber from
Dahl to Montebello. Within the electric fund, staff proposes an 8% rate increase, revenues of $169 million,
expenses of $182 million, an operations reserve of $32 million, and a CIP budget of $20 million. Within the
fiber fund, staff proposes a Consumer Price Index (CPI) increase of 4.5% for EDF-1 rates for pre-September
2006 customers, revenues of $5.5 million, expenses of $4 million, operations reserves of $33 million, and a
CIP budget of $1.5 million.
Chair Danaher noted reserves are five to six times annual revenues. Yuan advised that reserves are growing
approximately $4 million a year, but growth will drop to $2 million a year because of plans for more CIP
projects.
In reply to Commissioner Segal's question about half the fiber employees being allocated for customer
service, Yuan explained that a portion of customer service staff is allocated to fiber because each fiber
customer is billed manually. Customer service staff includes operations and engineering staff. The
contribution for unfunded liabilities and allocated charges has been budgeted to the fiber customer service
cost center rather than distributed across all divisions.
In answer to Councilmember DuBois' query about flat fiber revenues year to year, Yuan indicated fiber has
not gained any new customers, and rates have not changed.
Utilities Advisory Commission Minutes Approved on: Page 9 of 11
Vuong further advised that within the gas fund, staff proposes a 5% rate increase, revenues $49 million,
expenses of $44 million, operations reserves of $19 million, and a CIP budget of $3.7 million.
In response to Councilmember DuBois' inquiry regarding gas reserves not increasing, Yuan clarified that the
revenues should be $39 million rather than $49 million.
Vuong continued the presentation, stating within the wastewater fund, staff proposes a 7% rate increase,
revenues of $23 million, expenses of $27 million, and operations reserves of $4 million.
In reply to Vice Chair Schwartz's query about increasing reserves, Jonathan Abendschein, Assistant Director
of Resource Management, reported the figures are retrospective while plans are prospective. Some reserve
funds are increasing. Commissioner Johnston remarked that the budget shows expenses exceeding revenues
in all funds except fiber. Yuan explained that staff used reserve funds to reduce the rate increases.
In answer to Commissioner Forssell's question about pension and OPEB reserves, Abendschein indicated the
reserves represent the unfunded pension and other benefit liability for retirees. Pension issues for Utilities
are different from issues for the General Fund because Utilities salaries are a much lower percentage of
overall costs.
Vuong further stated within the water fund, staff proposes a rate increase of 1%, revenues of $50 million,
expenses of $59 million, operations reserves of $34 million, and a CIP budget of $16 million.
Commissioner Forssell commented that slide 9 and page 81 show different electric fund operations reserves.
Yuan clarified that one is composed of operations and hydroelectric. With hydroelectric, operations reserves
fall within the guideline range.
Vuong further reported since January the number of vacant positions has decreased from 44 to 31 positions.
Staff is developing recruiting strategies and attending career fairs. In addition, the new SEIU contract
increases compensation for difficult to fill positions.
In response to Commissioner Forssell's inquiry regarding the timing of the SEIU contract with the UAC
workforce discussion, Yuan advised that terms of the contract were not public knowledge at the time of the
discussion.
Vuong concluded the presentation by reporting staff is working on the My Utilities Account portal, the AMI
business plan, and Geographical Information System (GIS) and Enterprise Resource Planning (ERP) upgrades.
Staff has implemented several tasks of the Utility Strategic Plan.
Vice Chair Schwartz understood the Customer Information System (CIS) had to be upgraded before the ERP.
Yuan indicated ERP will be upgraded first because the vendor no longer supports it. The CIS upgrade has been
delayed by three to four years, and staff is looking at moving AMI forward a couple of years.
In reply to Commissioner Segal's question about retention of commercial dark fiber customers due to
anticipated changes in the market, Yuan advised that the statement refers to retaining customers as Comcast
and AT&T upgrade their networks. Staff is working on strategies to retain and attract commercial customers.
In answer to Commissioner Johnston's query regarding displacing cheap power with more expensive
renewable power, Abendschein reported the conversion from less expensive fracked gas to more expensive
renewable power concluded in 2018. One more contract will come online, but it will be offset by the
expiration of other contracts. Major drivers for the rate increase are revenues have not caught up to cost
increases, capital investment, load decreases, and transmission cost increases.
Utilities Advisory Commission Minutes Approved on: Page 10 of 11
In response to Chair Danaher's inquiry regarding electric initiatives that were subject to discretion and that
have a budget impact, Yuan indicated new initiatives are EV adoption to meet Sustainability and Climate
Action Plan (S/CAP) goals and the upgrade of the Colorado Power Station. Abendschein added that other
initiatives with a budget impact are rebalancing the electric portfolio and a number of sustainability and
efficiency measures.
In reply to Commissioner Segal's question about CIP projects planned for FY 2020 that were delayed because
of budgetary constraints, Yuan reported staff deferred underground rebuild projects.
In answer to Chair Danaher's query regarding a second transmission line, Yuan advised that a second
transmission line is not a part of the FY 2020 budget, but funds for it have been set aside in reserves.
In response to Vice Chair Schwartz's inquiry about using the existing transformer from the Colorado Station
as a spare part, Yuan stated staff decommissioned it because it was badly broken.
Abendschein reported discretionary items that are actionable on a short timeline are relatively small. Items
with larger impacts happen over a longer period of time, such as replacing aging infrastructure and
rebalancing the electric portfolio. The UAC will discuss those over the next year. Chair Danaher believed
discretionary items should be discussed during the year before they are included in the budget. Abendschein
related that staff has accelerated rates forecasting so that Assistant Directors have information to prepare
their budgets. The UAC focus on workforce had a lot of impact. The SEIU contract will have a budget impact,
but the contract is a positive and important investment.
Herb Borock commented that crossbore projects appear to be funded from the gas fund when only 1% of gas
mains are affected by crossbores. With respect to the AMI project, it would make more sense to make
decisions on the project as a whole instead of piecemeal.
In reply to Chair Danaher's inquiry about the UAC discussing rates more accurately reflecting pension
accruals, Councilmember DuBois stated the enterprise funds are covering additional contributions to
pensions. The Council is discussing pension contributions, and it may not be worth UAC discussion.
Chair Danaher noted the fiber reserve at $36 million is either too big or a source for funding fiber to the node.
In answer to Chair Danaher's queries regarding discretionary items for the gas and water funds the UAC
should have considered, Yuan indicated the crossbore program, the pace for replacing mains, and the
reservoir tank replacements. In reply to Chair Danaher's question of whether recycled water initiatives would
be in the water fund, Abendschein replied most likely.
In answer to Commissioner Segal's inquiry regarding the goal to reduce water usage by 20% by 2020, Yuan
explained the 1% is a single-year accomplishment while the 20% reduction is cumulative. Abendschein added
that the staff achieved the 20% reduction by 2020 goal a few years ago. The State is establishing a new set of
efficiency goals and regulations, which staff will review. Commissioner Segal cautioned staff to be sensitive
to the disproportionate impact to residents who pay more even though they comply with water conservation
measures, should new conservation measures be promulgated.
Vice Chair Schwartz remarked that leak detection, as a function of AMI, will eliminate unexpectedly high
water bills for customers.
Chair Danaher noted the UAC did not form a subcommittee to review the proposed budget, which should be
done annually.
In response to Councilmember DuBois' query regarding handling of the refuse and wastewater funds, Yuan
reported Public Works handles those.
Utilities Advisory Commission Minutes Approved on: Page 11 of 11
ACTION: Commissioner Johnston moved to recommend that the City Council adopt the Proposed Operating
and Capital Budgets for the Utilities department for Fiscal Year 2020. Vice Chair Schwartz seconded the
motion. The motion carried 5-0 with Chair Danaher, Vice Chair Schwartz, and Commissioners Forssell,
Johnston, and Segal voting yes and Commissioner Trumbull absent.
ITEM 4: DISCUSSION: Update and Discussion of Fiber and AMI Planning.
Dave Yuan, Strategic Business Manager, reported a Council update is scheduled for June. Staff is expanding
the scope of work for the Request for Proposal (RFP) for cross-utility integration.
ACTION: None
In response to Mr. Borock's comments, Chair Danaher advised that the UAC reviewed AMI comprehensively
in 2018. Vice Chair Schwartz added that utilities have implemented AMI with backend systems installed first
and with meters installed first. Installing the backend system first can provide benefits from day one, but
replacing aging equipment has benefits.
Commissioners and Councilmember DuBois requested agenda items for the DOE document regarding AMI
benefits; a joint meeting with the Council; revising the strategy for promoting solar energy; expanding the
Carbon Neutral Gas Plan to account for methane leakage; an update regarding revisions to regulations for
undergrounding districts; Regional Water Quality Control Plant vulnerability to sea level rise; a presentation
from Professor Luthy regarding storm water recycling; and an analysis of the cost effectiveness of energy
efficiency spending programs.
NEXT SCHEDULED MEETING: June 5, 2019
Meeting adjourned at 7:44 p.m.
Respectfully Submitted
Tabatha Boatwright
City of Palo Alto Utilities
Utilities Advisory Commission Minutes Approved on: Page 1 of 12
UTILITIES ADVISORY COMMISSION MEETING
MINUTES OF JUNE 5, 2019 REGULAR MEETING
CALL TO ORDER
Chair Danaher called the meeting of the Utilities Advisory Commission (UAC) to order at 7:00 p.m.
Present: Chair Danaher, Commissioners Forssell, Jackson, Johnston, Scharff, Segal, and Smith
Absent:
ORAL COMMUNICATIONS
None.
APPROVAL OF THE MINUTES
Commissioner Johnston moved to approve the minutes of the May 1, 2019 meeting as presented.
Commissioner Segal seconded the motion. The motion carried 4-0 with Chair Danaher, and Commissioners
Forssell, Johnston, and Segal voting yes, Commissioners Jackson, Scharff and Smith abstaining.
AGENDA REVIEW AND REVISIONS
None.
REPORTS FROM COMMISSIONER MEETINGS/EVENTS
None.
GENERAL MANAGER OF UTILITIES REPORT
Dean Batchelor, Utilities Director, delivered the General Manager’s Report.
PG&E Public Safety Power Shutoff Program – Pacific Gas and Electric (PG&E) is distributing letters to utility
customers throughout the Bay Area about the company’s Public Safety Power Shutoff Program. Considering
the growing threat of extreme weather and intensity of wildfires over the past few years, the company plans
to shut off major power lines in the event of extreme fire conditions. While PG&E does not serve electricity
to Palo Alto customers, we are coordinating with the company to understand the potential impacts to our
local distribution system, as we intake electricity to the City from PG&E’s transmission system. There is the
potential that a PG&E power shutoff could result in a local outage in parts of Palo Alto. The City is convening
an internal working group to ensure that we are coordinated in our actions and have a clear communication
plan for our outreach to the community. We will keep the UAC apprised of PG&E and City plans as more
information becomes available.
Residential workshops since last UAC meeting:
• “Is an Electric Vehicle Right for You?” City of Palo Alto Utilities (CPAU) sponsored this EV workshop
in partnership with Stanford Health Improvement Program (HIP) on May 28 at Mitchell Park. Topics
covered included the difference between all-electric and plug-in hybrid EVs, EV charging (home, work
and public space), range anxiety misconceptions, battery longevity, buying versus leasing, and the
FINAL
Utilities Advisory Commission Minutes Approved on: Page 2 of 12
environmental, economic, and personal benefits of EV adoption. There were approximately 100
attendees, and a number of EVs were available for viewing before and after the presentations.
• “Irrigation Equipment Upgrades and Landscape Water Use Efficiency” was held on May 11. Attendees
learned about irrigation equipment upgrades that can help improve the water efficiency of their
landscape irrigation system.
• “Maintaining Native Gardens and Leak Detection” was held on June 1. Attendees learned how to
create a beautiful, low water use and low maintenance landscape with native plants. The presenter
discussed design concepts, best practices, and how to set goals and a budget in this informative
lecture class. Attendees were also taught about how to find out if you have a leak in your system.
This class was also videotaped with the intent of putting it on our website.
The next Facilities Managers Meeting will be held on Thursday June 6 at VMWare. This meeting with our
largest utility customers will include presentations on the VMWare Microgrid Project, Decarbonization,
Distributed Energy Resources, EV chargers installation options, and utility rate changes. Facility Managers
Meeting are typically held twice a year.
As a note from last month’s General Manager’s report, the Mayor’s Green Business Leader Awards were to
be presented at the May 20 City Council Meeting but was moved to a yet to be determined date.
New Program Update – The EV Solutions and Technical Assistance program will be using Low Carbon Fuel
Standard (LCFS) funds to offer full end to end consulting and project management services to various
commercial customers to install EV Chargers – with emphasis on low income MF, regular Multi-Unit Dwellings
and non-profits. With the assistance of our contractor ClearResult, we expect this program will accelerate
the installation of EV charging infrastructure at these harder to reach customer groups. The goal is for this
program to help us towards the City’s sustainability goals and to streamline processes for all departments
involved.
COMMISSIONER COMMENTS
None.
UNFINISHED BUSINESS
None.
NEW BUSINESS
ITEM 1: ACTION: Election of Officers.
ACTION: Commissioner Johnston moved to approve Commissioner Danaher as Chair and Commissioner
Forssell as Vice Chair. Commissioner Segal seconded the motion. The motion carried 7-0 with Commissioners
Danaher, Forssell, Jackson, Johnston, Scharff, Segal, and Smith voting yes
ITEM 2: DISCUSSION: Discussion of Electric Vehicle and Building Decarbonization Sustainability/Climate
Action Plan Implementation Plans.
Jonathan Abendschein, Assistant Director of Resource Management, reported over the next year the UAC
will discuss the Sustainability and Climate Action Plan (S/CAP) update. The presentation will focus on
Citywide efforts concerning building decarbonization and electric vehicles. Later in the summer, staff will
present information about customer programs.
David Coale remarked that the cost of an electric vehicle (EV) can be less than the cost of a cell phone if a
purchaser selects the right lease option. The Ride and Drive program has been key to increasing EV adoption.
However, the City's minimum parking requirements prevent EV charging infrastructure from being installed.
The UAC should address parking requirements and charging infrastructure with the City Manager and the
Council. The REACH Code has to require all new buildings and small businesses be all electric. Installing
Utilities Advisory Commission Minutes Approved on: Page 3 of 12
natural gas in residential construction will result in stranded assets. The City needs to begin paying the price
to decommission the natural gas system.
Bret Andersen commented that investment in EV infrastructure supports single-occupancy vehicles (SOV) as
a mode of travel. The mobility strategy is designed to reduce SOV as a mode. The City can reduce its
investment in EV charging if it promotes mobility and the reduction of SOV travel. In order to reach the
reduction goal for natural gas usage, every resident will have to adopt electric appliances. The City has to
make adoption of electric appliances easy. Carbon Free Palo Alto has a proposal, Be Smart, which self-
finances electric appliances on the bill. Billing systems appear to be the major issue, but there are work-
arounds.
Tom Kabat suggested the City move quickly to require all-electric new construction in order to avoid the high
cost of retrofits.
Hillary Rupert, consultant, advised that the City of Palo Alto developed the first Climate Protection Plan in
2007 and adopted the S/CAP in 2016. As of 2017, the City of Palo Alto has reduced its greenhouse gas (GHG)
emissions by an estimated 43% from the 1990 baseline. The Sustainability Implementation Plan (SIP) consists
of four action areas: energy, water, mobility, and electric vehicles.
Christine Tam, Senior Resource Planner, indicated the S/CAP contains many assumptions about actions
needed to reach the goal of an 80% reduction in GHG emissions by 2030. EV adoption and building
electrification account for more than 98% of the assumed GHG reduction needed to meet the 80 by '30 goal.
To meet the goals, 90% of residents' vehicles and 50% of commuters' vehicles will need to be electric. With
respect to building electrification, the primary sources of GHG emissions are water heaters, space heaters,
and stoves/ovens.
Rupert continued the presentation, stating staff across the organization is making a tremendous effort to
implement the EV SIP. The first action is to publicize streamlined permitting and CPAU-funded transformer
upgrades. These are policy reviews and procedure streamlining. The second action is to consider EV
readiness and charger installation in existing buildings. Because of the challenges with retrofitting buildings,
staff is providing education and reviewing incentives. The third action is to evaluate programs to expand EV
charger deployment on private property. Twenty-eight applications have been submitted for LCFS funding
to install EV chargers in low-income multiunit dwellings and nonprofits. At the end of the first quarter of
2019, seven sites have received rebates.
In response to Chair Danaher's question regarding the length of time required to process an application,
Rupert reported the application process can take 6-12 months to complete.
In answer to Vice Chair Forssell's request for an explanation of parking requirements and minimum parking,
Rupert referred Commissioners to the City website because parking requirements are complex and involve
State mandates.
In reply to Commissioner Segal's inquiry regarding a City requirement for new construction to allocate
sufficient space for EV parking, Tam indicated currently Palo Alto has probably the most rigorous
requirements for EV-ready parking spaces for multifamily and commercial buildings.
In answer to Commissioner Scharff's query regarding the loss of parking spaces due to installation of an EV
charging space, Dean Batchelor, Utilities Director, explained the loss of a parking space occurs because a full-
time parking space is converted to an EV charging space with a 3-4 hour time limit. As a charging space, the
parking space is not available to non-EVs. Commissioner Scharff requested clarification of the regulations for
conversion of a parking space to an EV charging space when a building is over-parked. Abendschein disclosed
that a single EV charging space has to be striped as an ADA space so that regular and accessible vehicles can
utilize the space. Converting a normal-sized parking space to an ADA space when a building is minimally
Utilities Advisory Commission Minutes Approved on: Page 4 of 12
parked causes the loss of one parking space, which results in the building not being in compliance with
parking regulations. An over-parked property can install an EV charging space because the building can lose
a parking space and still be in compliance with parking requirements. Some multifamily buildings have
installed chargers. The Planning and Building Departments are addressing this issue. Rupert added that the
issue has been presented to the Planning and Transportation Commission, who is also reviewing the issue.
In response to Councilmember DuBois' question regarding an EV parking in an ADA space, Abendschein
clarified that there are dedicated ADA spaces and EV spaces. The EV space has to be ADA accessible, which
means a larger than usual space and the loss of a parking space.
In reply to Commissioner Smith's queries regarding a breakdown of the type of buildings that have applied
for an EV charging space and a way to fast track applications for existing buildings, Rupert advised that she
did not have a breakdown of applications by building type. Developing a fast track for applications will require
interdepartmental collaboration.
Rupert further reported the fourth action is building public and private infrastructure. By 2020, Palo Alto
residents are anticipated to own 4,000-6,000 EVs. Building public infrastructure is important to support the
goals for EV adoption. Staff has some infrastructure projects in the pipeline, such as additional Level 2
chargers and installation of 26 ports or an additional 13 chargers in City garages. Staff is also talking with
Tesla about super chargers and with Electrify America regarding DC fast chargers. With respect to a conflict
between the EV policy and the mobility policy, the goal is to reduce the number of cars. If driving is the only
option for people, staff prefers they drive an EV. The fifth action is to expand EV deployment in the City fleet.
Staff has reviewed a five-year replacement strategy and identified 17 vehicles that could be replaced with
EVs. The sixth action is to support regional EV group-buy programs, which have been moderately successful.
This action does not have a high priority. The seventh action is engaging community members and building
public awareness of EV options. The City partners with Acterra to sponsor ride-and-drive events. The FAQ
pages on the CPAU website have been updated to provide EV information. The eighth action is to seek ways
to collaborate with other electrification efforts. The goal of the EV infographic is to tell the EV story in an
easy and fun way so that folks can engage with it. There was an estimated 4,000 EVs in Palo Alto at the end
of 2018, and 29% of new car sales in Palo Alto are EVs.
In answer to Chair Danaher's query regarding the 4,000 EVs including hybrid vehicles, Rupert believed the
4,000 EVs do not include hybrids.
Rupert further stated Palo Alto has 2.5 times more EVs in 2018 than in 2014. Challenges for staff are
determining the right metrics for GHG reductions, technology outpacing City policies and regulations, and
competing priorities.
Tam continued the presentation, stating within the Energy SIP framework, staff looks at energy efficiency
and building electrification as the key areas. The City has adopted ten-year energy efficiency targets, and
staff will continue to pursue cost-effective energy efficiency programs and mandates. A variety of tools is
available to facilitate the electrification process in residences. Staff is reviewing whether to exceed State
requirements in the next Building Code cycle in order to obtain additional energy efficiency savings and
building electrification beyond 2020. . Staff is developing voluntary programs and technical assistance
programs that can result in additional energy savings and electrification beyond 2020. Construction of a
replacement facility for the sludge incinerator is complete. As a transitional measure, the City has purchased
carbon offsets to match natural gas emissions from the City's consumption of natural gas. The City has a
variety of tools, from education and outreach to customers to pilot programs, to facilitate the adoption of
electrification. The current Building Code encourages all-electric new construction. Staff will explore
mandating clean technologies and the needs of the low-income community and hard-to-reach customers.
Staff is aware of the barriers customers face. Staff needs to work with neighbors in the Bay Area to drive
market and supply chain transformation. Staff launched a heat pump water heater rebate pilot program
three years ago but has not seen a lot of uptake. Consequently, staff is attempting to collaborate with
Utilities Advisory Commission Minutes Approved on: Page 5 of 12
communities in the Bay Area to discount the cost of heat pump water heaters. Staff is working closely with
Development Services to push for mandates and incentives in the Code to encourage efficiency and
electrification. On Earth Day, staff launched an induction cooktop loaner program. The multifamily gas
furnace to heat pump retrofit pilot program is funded by grants from the Bay Area Air Quality Management
District. Staff is currently searching for multifamily buildings, primarily low-income housing, to convert gas
furnaces to heat pumps. A survey of residents found about 25% are familiar with a heat pump water heater.
Customers view natural gas as a cheap and clean energy source. Currently, there is little State and Federal
funding to support building electrification. Heat pump technology for small commercial buildings and
residential homes is very good. For commercial buildings over 100,000 square feet, the technology is not
mature.
In reply to Commissioner Johnston's questions regarding encouraging more office buildings to install EV
chargers in their parking lots and barriers to additional EV adoption, Rupert explained that the City has not
promoted destination charging in the private sector or workplaces. Outreach to the private sector is an action
item, but it has low priority because of the focus on multiunit dwellings and nonprofits. Tam reported
responses to the residential survey indicate renters do not purchase EVs because they do not have a
convenient charger. Abendschein added that large commercial customers are installing chargers based on
employee demand. Staff has a meeting with facility managers regarding EV chargers.
Commissioner Scharff questioned the effect of PG&E's public safety power outages on fleet EVs. Rural
communities are concerned about electrification because of the potential for electrical outages.
Commissioner Scharff indicated he had heard someone from the State speak at a conference about hydrogen
fuel cells being equal to EVs.
Chair Danaher remarked that 20,000 EVs will represent a huge part of the electricity load in the City. The EVs
should be networked so that the charging rates can be controlled. Staff needs to ensure that EV chargers are
future-proofed.
Councilmember DuBois suggested branding Palo Alto as the EV capital, challenging other cities to beat Palo
Alto's adoption rate, thinking about eliminating gas stations because of the high rate of EV adoption in Palo
Alto.
ACTION: None
ITEM 3: ACTION: Discussion of Electric Supply Carbon Accounting Methodology and RPS Compliance Strategy.
Bret Andersen believed staff needs to get the numbers right and needs to be honest about offsets and carbon
neutrality. The assumed natural gas leakage rate is 5%, which means the carbon footprint for buildings is
two to three times greater than it is believed to be. The City needs to start accounting for the cost of carbon
and using that cost in promotional and incentive programs for electrification.
Tom Kabat related that staff could incorporate the fugitive emissions CO2 equivalent into promotions for heat
pumps. Using a 20-year timeline rather than a 100-year timeline is vital.
Jim Stack, Senior Resource Planner, reported many financial implications are associated with changing the
City’s RPS compliance strategy. Month by month, CPAU has excess supply in the spring and summer from
hydroelectric and solar power and deficit supply in the winter months. On an hourly basis, CPAU has large
surpluses in July, especially in the evening hours when hydroelectric power is dispatched, and deficits in all
hours in the winter. Over the past six to seven years, the grid has changed dramatically. Oftentimes, the
carbon intensity of the grid is very low during the middle of the day due to solar generation and very dirty in
the evening hours due to natural gas generation. The current approach to carbon accounting is a simple
annual accounting method. Staff determines the load over the course of a year and the total carbon neutral
supply. If they match, staff considers the utility carbon neutral. The more accurate approach is an hour-by-
hour basis, which looks at the net surplus or deficit of resources compared to load and weights those amounts
Utilities Advisory Commission Minutes Approved on: Page 6 of 12
by the carbon intensity of the grid at that point in time. Another dimension is whether unbundled Renewable
Energy Certificates (RECs) are considered carbon neutral. Beginning in 2020, CPAU has to report in its Power
Content Label (PCL) the average emissions associated with the supply portfolio. The state will not consider
unbundled RECs to be carbon neutral. Currently, CPAU tends to have surplus resources during the spring and
summer evening hours when the grid electricity is the dirtiest. By dispatching those resources to maximize
their value, CPAU displaces a lot of carbon from the grid. For 2018, the total carbon emissions for the portfolio
was about 16,000 metric tonnes (mT).
In answer to Commissioner Segal's question about negative carbon emissions, Stack explained when CPAU
has a surplus of supplies compared to load, CPAU is putting more resources onto the grid than taking out of
the grid. Staff weights those resources by the carbon intensity of the grid at that period in time. If CPAU has
100 megawatt hours (MWh) of extra supply resources and the carbon intensity of the grid is 10 pounds per
MWh, CPAU is displacing 1,000 pounds of carbon. Lena Perkins, Acting Senior Resource Planner, added that
CPAU's resources are showing up in the dirtiest times of the grid and CPAU's load is distributed in relatively
clean times of the grid. This methodology was recently re-validated by a Stanford University study using the
same methodology and declaring the same result. Jonathan Abendschein, Assistant Director of Resources
Management, clarified that the physics of electricity require the amount consumed to equal the amount
generated. If CPAU generates extra solar power, electricity from a gas-fired plant has to be reduced. If CPAU
generates 10% more renewables over the course of a year than load, there's a chance CPAU will end up
negative. Perkins indicated it only works in the context of a broader grid.
Stack continued his presentation, stating without unbundled RECs, CPAU's portfolio would be responsible for
about 1,600 mT of CO2 using the annual approach. With an hourly approach, it's about 17,000 mT.
In reply to Commissioner Scharff's inquiry regarding marginal emissions and average emissions, Stack
suggested Commissioners think of marginal emissions as the last unit of generation that is brought online to
meet an additional unit of demand. The last unit tends to be the dirtiest unit on the grid. On an average
basis, all the renewables, which tend not to be the last unit, are lumped in. On an average basis, the average
emission factors are lower while the marginal emission factors are higher. CPAU's portfolio looks better
under the marginal emissions factors because a lot of its hydroelectric generation is dispatched in the periods
when marginal emissions factors are extremely high. In response to Commissioner Scharff's query regarding
marginal emissions factors not being the right methodology, Stack advised that CPAU is a small part of the
overall grid. If every utility in the state applied the marginal emissions factors to their entire loads, the end
result would not equal the total emissions statewide. It has to be an average basis. Abendschein added that
staff would continue to talk about marginal emissions in the context of coaching individuals to use electricity.
The average emissions methodology gradually pushes staff to do the right thing with CPAU's portfolio. With
marginal emissions, the portfolio can change quickly from good to bad such that staff does not have enough
lead time to make good portfolio decisions.
Stack further reported CPAU is currently using unbundled RECs from out-of-state generation to abate
emissions. Other methods to abate emissions are carbon offsets, carbon allowances, and bundled RECs from
instate renewable energy. Given the disparity of prices, it is reasonable to ask are unbundled RECs legitimate
if they cost so little. There is an ongoing philosophical and academic discussion on that topic. Staff thinks
unbundled RECs are legitimate instruments and have some concrete carbon-reduction value. The question,
though, is whether additionality is associated with the purchases. In other words, do they incentivize new
levels of generation to be built in out-of-state regions? On the margins, they do create some incentive. Also,
they make it cheaper for states to increase their RPS policies.
Chair Danaher noted the additionality argument also applies to bundled RECs, but that argument is faulty.
Stack indicated the state has imposed limits on the number of unbundled RECs that can be used for
compliance purposes. Abendschein added that staff is struggling with public perception. Some people do
not believe the arguments. Staff wants to get a sense of the environmental community's thoughts about a
position like this. The instinct is to look at the renewable portfolio and want to point to specific sources of
Utilities Advisory Commission Minutes Approved on: Page 7 of 12
supply coming to Palo Alto, but the arguments say look only at carbon and get the best carbon impact possible
no matter where the energy comes from. It is a logical approach but difficult to explain. If environmental
stakeholders say CPAU is greenwashing, the purchase of unbundled RECs could be problematic for public
perception. Staff needs to look into that before making any firm decision on RPS compliance.
Vice Chair Forssell wanted to understand the bill impact for customers.
Commissioner Scharff commented that he always thought CPAU should move away from RECs, but now he
is hearing that unbundled RECs may be superior. Stack reiterated that there is a lot of debate, but staff thinks
unbundled RECs are viable. Commissioner Scharff stated buying brown power and unbundled RECs to offset
the brown power would make CPAU carbon neutral. Yet, staff seemed to be saying it is not okay to use
natural gas and carbon offsets. Those seem to conflict. Chair Danaher agreed the two do conflict. Staff is
responding to the S/CAP. In fact, the UAC should be looking at the lowest cost method to reach carbon
neutral. Maybe the S/CAP targets need to be reformulated.
In answer to Commissioner Scharff's inquiry regarding the effect of selling renewables and moving toward
carbon offsets or RECs on the S/CAP, Abendschein explained that CPAU has added a lot of renewable energy
to the grid. Now, CPAU is trading between resources. For building energy use, if staff buys offsets and
considers it complete, long-term hard work will be needed to reduce natural gas use. Staff has not done that
work yet. Saving money on the electric side and using those savings to fund other sustainability efforts is
moving CPAU forward. Relying solely on carbon offsets does not affect the actions needed to reach the 80
by '30 goal. Perkins added that the RECs are only on the western interconnect. There is an imbalance market
looking to be rolled into a day-ahead energy market. The greenness of unbundled RECs versus bundled RECs
is not the right question. If they're close, Staff has to consider whether bundled RECs have 15 times the
carbon impact.
Stack continued the presentation, stating using an hourly accounting, the portfolio in 2018 had about 17,000
mT of emissions to abate. Using unbundled RECs, it would cost about $62,000. Using offsets, it would cost
about $250,000.
In reply to Commissioner Johnston's inquiry about translating that to a percentage of rates or dollars per
month, Abendschein indicated an ongoing $1.5-$1.7 million cost equals a 1% increase in rates.
Stack further reported CPAU first adopted an RPS target in 2002. SB 100 gives utilities with large amounts of
old, large hydroelectric in their portfolios an exemption to come in below the RPS requirement level. CPAU
has to achieve an RPS level that is the lesser of the regular limit and the amount of load not supplied by old,
large hydroelectric.
Commissioner Scharff noted the City lobbied strongly for that provision and achieved its inclusion in SB 100
because Palo Alto was viewed as doing the right thing for the environment.
Stack continued, stating in 2019 CPAU's RPS requirement is 31%, but the portfolio is roughly double that,
resulting in a large surplus. The current approach to comply with the RPS requirement is to exceed the RPS
requirement with all instate resources. Staff could choose lower-cost options. Staff could sell some resources
that exceed load. Because CPAU's load has been declining, CPAU has more resources overall in an average
hydroelectric year than load. Staff could sell everything that exceeds the RPS requirement.
In response to Chair Danaher's question about staff already selling excess, Stack advised that Staff could sell
the portion that exceeds load. Right now, roughly 110% of CPAU's load is in total hydroelectric plus
renewables, so staff could sell 10% or everything above the RPS requirement, which would be 30%. Under
RPS law, CPAU is allowed to satisfy 10% of the RPS requirement using unbundled out-of-state RECs. Staff
could sell some of CPAU's instate bundled resources and swap them for cheaper out-of-state unbundled
RECs. CPAU has been exceeding its RPS requirement for almost ten years. Every year that CPAU has exceeded
Utilities Advisory Commission Minutes Approved on: Page 8 of 12
the RPS requirement, staff has been saving the excess for a total of about 1.2 million RECs. Staff could sell all
of CPAU's RPS resources for the next four years and rely on the saved RECs. On the increasing cost side, staff
could sell some resources like solar that produces a lot in the summer and replace it with geothermal that
produces in a baseload pattern. Staff could try to be carbon neutral every hour of the year, but that would
involve selling a lot of solar, buying a lot of baseload renewables, and dispatching hydroelectric resources to
match load rather than to obtain the most value. Staff does not recommend that approach. Going to a
carbon neutral every hour approach would cost $6-$10 million per year. Bucket swapping would be a
$500,000 per year opportunity. Using saved RECs between now and 2030 would result in an approximate $2
million savings. Selling all supply exceeding the RPS requirement is a minimal compliance strategy. A minimal
compliance strategy would result in a $5-$7 million per year savings.
In answer to Commissioner Johnston's query about using the banked RECs instead of buying new RECs, Stack
disclosed that staff would sell Bucket 1 resources and buy market power.
In response to Commissioner Scharff's inquiry about the price of banked RECs, Stack reported the banked
RECs are worth essentially the same as a Bucket 1 REC. CPAU does not lose any value by banking RECs.
Stack continued his presentation, stating in 2020 under a minimal compliance strategy, CPAU could save
about $7 million in supply costs with an RPS level of about 21%. In terms of carbon, the current portfolio
under an hourly accounting method would result in negative 45,000 mT of CO2 emissions. If CPAU changed
to a minimal compliance approach, it would have a portfolio responsible for positive 114,000 mT of CO2
emissions. Mitigating the 114,000 mT of emissions would require purchasing Bucket 3 RECs or another
strategy. If staff purchased Bucket 3 RECs, there would be a cost of about $400,000 to mitigate those
emissions, compared to a $7.4 million savings from selling Bucket 1 RECs.
In answer to Commissioner Scharff's question of whether the strategy would be to sell Bucket 1 RECs and
purchase Bucket 3 RECs, Stack responded correct. That is the minimal compliance or the least cost approach.
Stack further reported if staff sold all resources greater than the RPS requirement, customers would see some
unspecified market power purchases on the PCL. If staff used the minimal compliance approach, almost a
quarter of supply would be from market purchases.
In reply to Vice Chair Forssell's question about bucket swapping introducing a market power slide to the PCL,
Stack answered yes.
Stack continued the presentation, stating a $7 million net savings would result in a 4-5% rate reduction. Staff
could retain the $7 million and defer rate increases for a number of years. Staff could use the funds for
sustainability initiatives. Another factor to consider is customer perception of these options.
In reply to Commissioner Smith's inquiry of whether the graph included banked RECs in each year and
whether the graph should show zero banked RECs in 2030, Stack advised that the graph includes RECs banked
each year. The final banked RECs would be sold in 2030; therefore, 2031 would show zero banked records.
Stack further reported as existing contracts expire, CPAU has less surplus to sell. As the RPS level increases,
there is less headroom.
In response to Commissioner Smith's query about reducing electric demand to the point that banked RECs
would not be needed, Stack related that reducing demand would provide additional RECs that could be sold.
Chair Danaher noted past analyses indicated the increase in EV adoption would offset the decreases in other
consumption. The UAC did not expect a reduction in the overall load. In answer to Commissioner Smith's
question about spending the $7 million savings to increase EV infrastructure, Stack indicated that is one
possibility. Staff is forecasting a decrease in overall load because of efficiency and behind-the-meter solar
exceeding the gains from EV load.
Utilities Advisory Commission Minutes Approved on: Page 9 of 12
Commissioner Scharff commented that the decreasing load will increase rates for consumers. Perkins added
that industrial customers are leaving the service area as well. Commissioner Scharff stated industrial
customers are moving because Santa Clara's electric rates are substantially less than CPAU's electric rates.
Stack further reported staff will return with another discussion and a recommendation. Staff will seek Council
approval of a change in the carbon accounting methodology because it is part of the Carbon Neutral Plan.
The RPS compliance strategy is a significant shift, so staff wanted the Council's feedback on it as well. Staff
could begin selling some resources in 2019, but 2020 is more likely. In the next nine months, staff will also
provide the UAC with reports regarding the new 30-year Western Base Resource contract.
In reply to Commissioner Segal's inquiry regarding the impact of renewing the contract on the exemption for
the RPS level requirement, Stack indicated a new hydroelectric contact would not be exempt. Renewing an
existing contract would be exempt. In response to Commissioner Segal's question of whether the $7 million
savings could purchase sufficient storage to offset the need to purchase some RECs, Stack advised that the
savings would fund a significant storage installation that staff could use to shift generation around to reduce
carbon. Perkins added that in terms of City impacts, the savings would have the greatest impact on
transportation, whether mobility or EVs. In answer to Commissioner Segal's query about wind power in the
first slide, Stack disclosed that CPAU has one contract expiring at the end of 2021 and another in 2028. If the
Western contract is reduced or eliminated, staff might replace it with wind power.
In response to Chair Danaher's question regarding distinguishing the environmental value of Bucket 1 RECs
from Bucket 3 RECs, Perkins explained that the maximum Bucket 3 RECs staff could procure for RPS
compliance is 10%. Staff is already dealing with an artificially constrained market. Bucket 1 RECs are
increasing in price. The price for Bucket 3 RECs is flat or decreasing. Study papers indicate by optimizing over
a larger area, there is no net leakage of carbon on the WECC (Western Electricity Coordinating Council) and
the prices are lower for everyone. Abendschein added that one of the countervailing arguments concerns
additionality. The fact that there is not much of a liquid market for Bucket 1 RECs means generally the
requirement forces utilities to enter into a long-term Power Purchase Agreement, which most people agree
is instrumental in adding renewable energy to the grid. The countervailing argument applies when utilities
buy Bucket 3 RECs that may come from established projects. There's an argument to be made that Palo Alto
has done its work on additionality. If environmental groups look carefully at those arguments and are
concerned about CPAU's portfolio, staff would be in a position to make that argument.
Commissioner Scharff viewed this as a huge change in Palo Alto's direction. Saving $7 million a year over ten
years is a large number, but it does not feel right to tell people CPAU is carbon free. If big hydroelectric was
considered renewable, CPAU would tell everyone it was 100% renewable. Chair Danaher related that under
the hourly accounting methodology, CPAU is not carbon neutral during large periods of time. Commissioner
Scharff remarked that staff could buy more renewables to cover that. Vice Chair Forssell understood under
carbon-neutral hourly, CPAU would be an island and not part of the grid, which is different than using hourly
average accounting, which is still in the context of the grid. Commissioner Scharff asked if CPAU would be
carbon free under the hourly accounting method and as part of the grid.
In response to Vice Chair Forssell's request for the meaning of minimally RPS compliant, Stack explained that
under the current Council-approved definition, CPAU could be considered carbon neutral by buying Bucket 3
RECs. To the extent CPAU has market purchases that show up in the PCL, CPAU could buy additional Bucket
3 RECs and still be considered carbon neutral under the minimally compliant approach. Vice Chair Forssell
inquired whether anyone is suggesting a change in Palo Alto's established definition of carbon neutral, to
which Stack replied no. Commissioner Scharff asked if the definition would be revised to be more granular.
Chair Danaher viewed it as two problems: the amount of emissions determined by the accounting
methodology and requiring the purchase of offsets or credits, and the source of the offsets or credits.
Commissioner Scharff viewed it as CPAU striving to have 50% renewables and 50% hydroelectric. Because of
Utilities Advisory Commission Minutes Approved on: Page 10 of 12
the vagaries of the market, sometimes CPAU has to offset emissions with RECs. Commissioner Johnston
interpreted the discussion as whether to move away from the traditional strategy.
In reply to Commissioner Scharff's statement that he did not have sufficient information, Abendschein
advised that staff needs to have an internal discussion to frame recommendations for the UAC. Staff also
needs to follow up on some studies that have some promising positive support for the concepts discussed
and that staff might use to frame the arguments. In addition, Abendschein wanted to talk with environmental
stakeholders about these concepts and get their initial reactions. It might make sense to provide customers
with a carbon-neutral hourly portfolio if it is important and intuitive to the customers and if customers are
willing to pay extra.
Commissioner Smith suggested staff provide the UAC with past Council direction to frame the discussion in
the perspective of a goal. Stack reported in 2013 the objective was to rely on RECs until CPAU built some
hard resources and then in 2016 or so rely on half of supply from instate hard resources through long-term
contracts for renewables and half from hydroelectric. In reply to Commissioner Smith's inquiry regarding
additional hydroelectric supplies coming online, Stack indicated there are no new hydroelectric resources
coming online. Staff recently learned about some hydroelectric resources that are coming off contracts with
other utilities and that CPAU might pick up. In response to Commissioner Smith's concern about maintaining
50% hydroelectric if demand increases, Stack disclosed that current renewables contracts are just as low as
the hydroelectric contract.
Commissioner Jackson suggested creating a rate plan for homeowners who convert to all electric if CPAU
realized the $7 million savings. Perkins reported lowering rates by 5% is incentivizing electrification and EVs.
In response to Vice Chair Forssell's query regarding the City's internal RPS target, Stack clarified that the City's
target is currently the same as the State's target. CPAU initially had a target higher than the State's target,
but the State has caught up. Vice Chair Forssell asked if a minimal RPS requirement would be 29% renewable,
as much hydroelectric as possible, and buying either offsets or allowances or using banked RECs, to which
Stack replied that is correct for 2018 when the RPS requirement was 29%. Perkins clarified that the RPS level
is the percentage of the portfolio comprised of eligible renewables in one year. That is different from the
RPS minimum set by the State. Stack noted the RPS requirement is different from the amount achieved each
year. Vice Chair Forssell remarked that minimally compliant would be selling the excess instead of generating
60% renewable power from projects.
Chair Danaher indicated combining that with the RPS compliance complicates the issue quite a bit.
Disassociating the two issues would be helpful. Bucket 3 RECs may be a cheaper way to abate the additional
17,000 mT calculated under the more exacting standard in order to maintain carbon neutrality. He requested
staff provide for the next meeting information regarding what CPAU does with RECs now and how CPAU
accounts for the shortfall when purchasing RECs.
In answer to Commissioner Segal's inquiry regarding limitations on the contents of the PCL, Stack reported
staff cannot change anything on the PCL. Staff inserts the values, and the PCL shows the portfolio equals so
many pounds per MWh of carbon emissions over the course of the year.
Dean Batchelor, Utilities Director, advised that staff will return in August with a continued discussion but no
action for the topic.
ACTION: None
ITEM 4: DISCUSSION: Discussion of Natural Gas Leakage from the City of Palo Alto's Gas Distribution System.
David Coale commented that leakage can double the impact of GHG effects from natural gas, which would
make it about the same as burning coal. The global warming potential of methane should be 86 times CO2
Utilities Advisory Commission Minutes Approved on: Page 11 of 12
because it should be taken in the 20-year timeframe rather than the 100-year timeframe. The City accounts
for transmission losses across the entire electricity grid but only within the City for natural gas transmission.
Tom Kabat explained that a REC is a rigorously tracked attribute from a project that is hard metered and
tracked by an accounting system into accounts. An offset is a counter-factual calculation of what someone
would have done if had had not been paid not to do what he would have done. CPAU should use the 20-year
timeframe because it gives the larger effect of fugitive emissions. About 25% of current global emissions
needs to be removed from the atmosphere at a cost of more than $100 per ton. Avoiding emissions now is
worth a cost of $100 per ton.
Bret Andersen expressed concern about where the huge emission number will be reported. The City's carbon
footprint does not show fugitive emissions. Staff should call out the emission number in planning and in the
City's footprint for natural gas use.
Jonathan Abendschein, Assistant Director of Resource Management, reported the item was prompted by a
question from Vice Chair Forssell about the amount of leakage from Palo Alto's gas distribution system. Staff
does not know for sure. A 2012 study to determine whether CPAU needed to report estimated gas leakage
to the Environmental Protection Agency (EPA) calculated about 4,700 mT of carbon was being emitted due
to leakage and oxidization on CPAU's system. The calculation used many nationwide assumptions; therefore,
it is not necessarily specific to Palo Alto. The amount is a small number relative to total emissions, which are
in the range of 150,000 to 160,000 mT. A second method for calculating gas leakage is the difference between
meter readings from the four stations where CPAU takes gas from PG&E's system and the total sales CPAU
meters over the same period of time. The difference between the two is 1.5% to 3%. Metering is an imprecise
science. A 2% measuring error is the standard for a meter in the field. Not all of the 1.5% to 3% is released
into the atmosphere, but the amount released into the atmosphere is an open question and would require
further study. The City does more than the Department of Transportation (DOT) requires to repair and search
for leaks. Therefore, Abendschein assumed the actual emissions to the atmosphere are lower than many
other utilities.
Commissioner Segal supported estimating methane emissions at the 20-year level rather than the 100-year
level. Understanding the impact of upgrading the most vulnerable pipes on reducing emissions and on the
cost to reduce emissions would be interesting. Dean Batchelor, Utilities Director, advised that the oldest gas
pipes are replaced after leak surveys are conducted. Approximately 45 miles of PVC pipe remain in the City,
and they will be replaced over the next five to seven years with high-density gas pipe.
In response to Chair Danaher's question about PG&E tracking or estimating leakage from its system,
Abendschein indicated he could obtain the information as PG&E is mandated to report it to the California Air
Resources Board (CARB).
Vice Chair Forssell concurred with using a 20-year time horizon. She had raised the issue with the thought to
expand the Green Gas program to offset fugitive emissions as well. However, the electric portfolio should be
prioritized over gas emissions.
Batchelor indicated he will place gas emissions on the list of items for a future agenda and return before the
end of the year for a discussion.
In reply to Commissioner Smith's query about staff anticipating another 1% decrease over the five to seven
years it will take to replace PVC pipes, Batchelor answered yes. When the ground moves, the joints of the
PVC pipes leak gas. CPAU does not have the normal leakage rate because the pressure on the PVC pipe is
lower than other utilities use.
ACTION: None
Utilities Advisory Commission Minutes Approved on: Page 12 of 12
ITEM 5: DISCUSSION: Discussion and Update on Fiber and AMI Planning.
Dean Batchelor, Utilities Director, reported staff will present a fiber update to the Council on June 24. The
update will include reissuing a Request for Proposals (RFP) and perhaps a new scope of work. In November,
the Council approved Automated Metering Infrastructure (AMI). Staff wants to build fiber to the collectors
for AMI so that the response to outages is faster. Hopefully, staff will return to the Council in October with
a contract award and start work at the first of 2020.
In reply to Commissioner Smith's query about a dig once policy, Batchelor explained that all projects for
electrical upgrades include installation of fiber conduit.
In response to Commissioner Jackson's inquiry about the UAC reviewing the RFP before it is released,
Batchelor indicated he will forward it to the UAC.
ACTION: None
ITEM 6: DISCUSSION: Discussion and Status of Water Leak Bill Credits.
Dean Batchelor, Utilities Director, reported staff added $25,000 to the budget for a total of $75,000.
Currently, credits total approximately $59,000 for 131 customers. The average rebate is about $373 for water
credits and irrigation repairs. The maximum credit allowed is $2,500, but requests for credits have not been
that high.
ACTION: None
ITEM 7: ACTION: Selection of Potential Topic(s) for Discussion at Future UAC Meeting.
Chair Danaher noted an additional discussion of RPS strategy will be scheduled for the August meeting.
In response to Commissioner Johnston's question regarding the ordinance for neighborhoods that want to
underground all utility equipment, Dean Batchelor, Utilities Director, advised that the item will be presented
to Council in June or August. He will provide an update to the UAC after the Council meeting.
ACTION: None
NEXT SCHEDULED MEETING: August 7, 2019
Meeting adjourned at 10:08 p.m.
Respectfully Submitted
Tabatha Boatwright
City of Palo Alto Utilities
Page 1 of 13
3
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: June 5, 2019
SUBJECT: Renewable Portfolio Standard Compliance Strategy and Carbon Emissions
Accounting Methodology Options for the City’s Electric Supply Portfolio
______________________________________________________________________________
REQUEST
Staff seeks UAC feedback on two separate but related issues:
(1) What procurement strategy to follow in order to comply with the state’s renewable
portfolio standard (RPS) mandate, and
(2) What accounting methodology to use in assessing the electric supply portfolio’s annual
carbon emissions.
EXECUTIVE SUMMARY
In the City’s 2018 Electric Integrated Resource Plan (EIRP), approved by Council in December
2018, Initiative #4 of the Work Plan called for staff to evaluate the carbon content of the electric
supply portfolio using hourly grid emissions intensity data, to consider the merits of buying
carbon offsets to ensure the carbon content of the cumulative hourly portfolio is zero on an
annual basis, and to reevaluate the manner in which the City communicates with customers
about the carbon content of the electric portfolio. In addition, Initiative #5 of the Work Plan
called for staff to investigate the merits of monetizing the City’s excess renewable energy
supplies in order to minimize the cost of maintaining an RPS compliant and carbon neutral
electricity supply portfolio. This report, which builds on a report presented in May 2019,
satisfies these two EIRP Work Plan Initiatives.
This report describes several different procurement strategies that the City might pursue in
order to comply with its state RPS requirements, along with the financial impact to the utility of
changing from its current RPS compliance strategy. Based on current supply projections and
market prices, staff estimates that the financial impact of switching to a minimum compliance
RPS strategy could result in approximately $5 million in annual savings over the next 12 years (or
just over 0.5 cents/kWh)—although realizing these savings would significantly impact the
carbon intensity and renewable energy content that the City would have to report to customers
on its annual Power Content Label (PCL). Other strategies could result in higher costs.
In addition, this report follows up on the aforementioned May 2019 UAC report, which
calculated the carbon content of the City’s actual 2018 electric portfolio under six different
carbon accounting methodologies, by describing the financial impact of cleaning up the
portfolio’s “residual emissions” that could result, over the next several years, if the City
switched carbon accounting methodologies or RPS compliance strategy. While switching to an
Page 2 of 13
hourly carbon accounting approach from the current annual approach would result in a slight
cost increase for the portfolio in dry years (on the order of $60,000 per year), utilizing carbon
offsets to abate the City’s residual emissions in dry years instead of unbundled RECs would have
a much more significant impact (on the order of $600,000 in a very dry year). And these
financial impacts would be far greater if the City also chooses to sell some of its excess RPS
supplies, because doing so could result in greater levels of wholesale market power purchases
and thus greater levels of residual emissions (depending on how much of our excess RPS
supplies we sell).
BACKGROUND
Over the past two years, staff has shared numerous presentations with the UAC related to the
electric supply portfolio in the course of developing and implementing the 2018 Electric
Integrated Resource Plan (EIRP). In the course of these discussions, two points have been clearly
articulated. First, the UAC would like staff to pursue a supply portfolio that minimizes total cost
to customers, while also minimizing carbon emissions—even at the expense of the portfolio’s
reported RPS level. This point was made most clearly in December 2017, when staff delivered a
report to the UAC on potential changes the City could make to its strategy for complying with
its Renewable Portfolio Standard (RPS) and Carbon Neutral Plan objectives.
And second, the UAC wants staff to communicate with the public about the supply portfolio in a
manner that is both accurate and accessible. Initial discussion on this topic occurred in June and
September 2018, when staff presented reports for the EIRP on the subject of potentially
rebalancing the City’s portfolio of long-term electric supply resources in order to better match
these electric supplies with the City’s load. A more in-depth discussion of this topic also
occurred last month, when staff presented a report laying out several different accounting
methodologies that could be used to quantify the carbon emitted by the City’s electric supplies,
and analyzing the City’s actual 2018 electric supply emissions under each methodology.
The May 2019 report also described a new accounting methodology being proposed by
California Energy Commission (CEC) staff for quantifying emissions on Power Content Labels
(PCLs) starting next year. Staff described the communications challenges that could result if the
City adopts an accounting methodology that is at odds with the methodology used on the PCLs
that are sent to customers every year. However, the UAC expressed a clear preference for
employing an accounting methodology that most accurately represents the carbon emissions of
the electric portfolio, even if it results in the reporting of two different portfolio emissions
totals in some years.
Page 3 of 13
DISCUSSION
At the May 2019 UAC meeting, staff and the UAC discussed potential changes to the City’s
carbon accounting methodology and renewable energy procurement strategy. However,
Commissioners expressed a strong desire to see estimates of the financial impact of any
changes to the City’s current approaches on these matters. The purpose of this report is to
quantify the financial effects of these potential changes—as well as their impact on the City’s
RPS level and Power Content Label.
RPS Compliance Strategies
Since the adoption of its first RPS target in 2002, the City has consistently maintained an RPS
procurement goal that exceeds the statewide RPS mandate level, as well as an actual renewable
energy procurement level that exceeds the statewide average. Figure 1 illustrates the growth in
the City’s RPS supplies over the past 15 years and how these supplies compare to the statewide
RPS requirements.
Figure 1: Palo Alto's RPS Supplies and Procurement Requirements
For calendar year (CY) 2018, as Table 1 shows, the City’s RPS level was 63.9%, whereas the
state’s RPS requirement for that year was only 29%.
Table 1: 2018 RPS Procurement and RPS Level
Retail Sales 888,033 Small Hydro 13,266
Page 4 of 13
Landfill Gas 110,139
Wind 101,801
Solar 342,650
Renewables Total 567,856 RPS Level 63.9%
In addition to exceeding statewide RPS procurement requirements, the City’s renewable supply
portfolio is also composed entirely of relatively higher value in-state resources—where the
renewable energy attribute (a Renewable Energy Certificate, or REC) is “bundled” with the
energy produced by the resource. In contrast, the state’s RPS mandate allows utilities to satisfy
a portion of their procurement requirement with lower value out-of-state resources.1
Other procurement strategies the City could opt to pursue include:
a) Minimally Compliant: Under this approach, the City would sell off all of its renewable
resources that exceed the state’s RPS requirement level. The City would also sell some
additional long-term renewable energy resources and replace those with market power
purchases paired with unbundled (Bucket 3) RECs, to the extent allowable under the
state’s RPS regulations (up to 10% of the City’s RPS requirement can be satisfied with
this type of resource, per state RPS regulations). The City would also apply its stock of
excess RPS supplies that it has built up since 2010 2 toward its RPS requirements in future
years, enabling the sale of even larger volumes of renewable resources.
b) Sell Excess Resources: As noted above, the City’s portfolio greatly exceeds the state’s RPS
requirements; in addition, under average hydrological conditions the City has an excess
of overall carbon neutral supplies. The City could choose to sell off a portion of its
renewable supplies—either the resources that exceed the City’s total load, or all of the
resources that exceed the state’s RPS requirement level (replacing the energy with
market power purchases, to the extent needed to serve load). For this analysis, staff will
focus on the latter approach.
c) Carbon Neutral Every Hour: This approach would entail the most dramatic changes to
the portfolio, and be the most expensive to pursue. In this approach, the City would sell
1 State law has established three different categories or “buckets” of renewable energy products—and sets limits
on the degree to which a utility can rely on the less preferred categories to fulfill their RPS requirements. The first
category (Bucket 1), the most preferred one, encompasses all renewable energy that is delivered into the
California grid as it is generated. The second type of renewable energy (Bucket 2) consists of renewable energy
generated out-of-state that is used by the out-of-state grid as it is generated, and then later an equal amount of
energy from a different resource is delivered into the California grid. This type of arrangement is referred to as
“firming and shaping” the resource’s output. The third category of renewable energy (Bucket 3) is the state’s least
preferred one, and also the least expensive to procure. Bucket 3 encompasses all sales of RECs without any
associated energy. In these “unbundled REC” transactions, the renewable energy is generated and consumed
(usually out-of-state) but the RECs are sold separately to a California utility.
2 This refers to the “Excess Procurement” and “Historic Carryover” provisions of the City’s Renewable Portfolio
Standard Procurement Plan, which was last updated and approved by Council in December 2018 as part of the
Electric Integrated Resource Plan (EIRP) approval process:
https://www.cityofpaloalto.org/civicax/filebank/documents/67789.
Page 5 of 13
some of its solar and/or wind resources and replace them with baseload renewable
resources. It would also alter the scheduling of its hydroelectric resources in order to
have its combined carbon neutral resources match its load in all hours—essentially
acting as though Palo Alto was an island. (Note that staff has not thoroughly examined
the technical feasibility of this approach. Particularly in drier years, it may not be
physically possible to achieve a perfect balance between load and supply in all hours of
the year.)
Although the UAC recommended against the Carbon Neutral Every Hour approach rather
strongly at the May 2019 meeting, this case can serve as a bookend, with the Minimally
Compliant approach at the opposite end of the spectrum. There are other variations on these
approaches that the City could pursue (e.g., buying Bucket 2 resources instead of or in addition
to Bucket 3 resources, selling a portion of the City’s solar or wind resources and replacing them
with baseload renewables, or not using the City’s supply of older excess RPS supplies) but these
are the three primary options that will be analyzed in addition to the status quo.
Attachment A provides year-by-year details on the City’s projected load, renewable energy
supplies, RPS level, RPS requirements, and supply of older excess (or “banked ”) RECs. It also
provides staff’s estimate of future Bucket 1 and Bucket 3 REC values3 (independent of the
physical energy that would be bought or sold in conjunction with the REC), and the resulting
total financial opportunity available to the City if it opts to pursue a Minimal RPS Compliance
strategy.
Figure 2 below displays the annual financial impact (through 2030) of each of the three
aforementioned RPS procurement strategies, relative to the status quo approach. Note that the
cost impact depicted here only reflects the sales revenue and/or purchase cost of renewable
energy supplies, and is independent of the cost of cleaning up the residual emissions that might
result from this change in RPS compliance strategy. The latter cost impact will be addressed
later in this report. Also note that for the evaluation of the Carbon Neutral Every Hour
approach, it is assumed that the City’s wind and solar resources can be sold for a fixed price of
$37.5 per MWh, and that purchasing baseload renewable supplies would cost $70 per MWh.
For the analysis of this approach, staff also assumes that altering the City’s scheduling approach
for its hydro resources would carry a financial cost of $2 million per year.4
3 Although a long-term forward market does not yet exist for RECs in California, staff assumes that Bucket 1 RECs—
which currently carry a premium of $18 or $19 per MWh—will decline over the next several years, as the state’s
Community Choice Aggregators (CCAs) accelerate their long-term procurement and bring their own resources
online. Bucket 3 REC prices, meanwhile, are expected to continue to increase slowly in the coming years,
particularly after the federal Production Tax Credit (PTC) for wind projects expires.
4 This model assumes that the City sells all but 100,000 MWh per year of its solar resources, and replaces these
resources with enough baseload renewables to satisfy its total load. Hence, in the initial years, the City sells off far
more renewable energy supplies than it purchases as replacement energy—which results in a relatively smaller
supply cost impact, but a lower overall RPS level.
Page 6 of 13
Figure 2: Change in Supply Cost Due to Switching RPS Compliance Strategy (2019-2030)
Note that the upward trend in supply cost impact over time, as well as the jump in supply cost
impact for 2022, is due to the timing of existing wind and landfill gas contracts expiring during
that period (combined with a new solar contract coming online in 2023), along with the
increases in the state’s RPS requirement (which ultimately reaches 60% in 2030). As these
existing contracts expire over time and the RPS requirement rises, the City would have fewer
excess renewable supplies to sell—and also have to increase its purchases of baseload
renewables under the Carbon Neutral Every Hour approach.
Under this set of assumptions, taking a minimal compliance approach to the RPS mandate
would reduce supply costs by an average of $5.1 million per year over this 12-year period,
selling the City’s excess RPS supplies would reduce supply costs by an average of $2.9 million
per year, and trying to achieve carbon neutrality every hour of the year would increase supply
costs by an average of $8.5 million per year.
Carbon Accounting Methodologies
In the May 2019 UAC report on carbon accounting, staff presented six potential accounting
methodologies:
Page 7 of 13
1. The City’s Current Method (Method A) – Procure carbon neutral resources equal to total
load on an annual basis. In addition, unbundled RECs can be purchased in order to make
generic market energy purchases effectively carbon neutral.
2. The Proposed Power Content Label (PCL) Method (Method B) – The CEC has proposed
an accounting methodology, in order to implement Assembly Bill (AB) 1110,5 that is
similar to the City’s current method (annual summation of resource supplies and load),
except unbundled REC purchases would not be allowed to neutralize the carbon content
of generic market energy purchases.
3. Hourly Accounting Method #1 (Method C) –An hourly comparison of the City’s supplies
and load, with each hourly net energy value assigned the average hourly carbon
emissions intensity of the CAISO grid to convert it to an hourly emissions total. These
hourly emissions totals would then be summed across the hours in a year. In addition,
unbundled REC purchases would be allowed to neutralize the carbon content of generic
market energy purchases.
4. Hourly Accounting Method #2 (Method D) – This approach is the same as Hourly
Accounting Method #1, except that unbundled REC purchases would not be allowed to
neutralize the carbon content of generic market energy purchases.
5. Hourly Accounting Method #1a (Method E) – Identical to Method C, except that it uses
the grid’s marginal hourly emissions factors, instead of average.
6. Hourly Accounting Method #2a (Method F) – Identical to Method D, except that it uses
the grid’s marginal hourly emissions factors, instead of average.
For 2018, a relatively dry hydrological year where the City’s total carbon neutral supply
resources nearly matched its load (carbon neutral supplies equaled 99.6% of the City’s total
load for the year), the emissions totals calculated for the portfolio under each of the six
accounting methodologies are presented in Table 2 below.
Table 2: Annual Net CO2 Emissions and Emissions Intensity for the Electric Portfolio in 2018
under Six Accounting Methodologies, with the Purchase of 3,638 Unbundled RECs
Unbundled RECs + Market
Power = Carbon Neutral
Unbundled RECs Don’t
Neutralize Market Power CO2
Method
Net
Emissions
(mT)
Emissions
Intensity
(lb/MWh)
Method
Net
Emissions
(mT)
Emissions
Intensity
(lb/MWh)
Annual Accounting A 0 0 B 1,557 3.8
Hourly Accounting
(Average Emissions Factors) C 16,118 39.2 D 17,675 43.0
Hourly Accounting
(Marginal Emissions Factors) E (2,038) (5.1) F (526) (1.3)
5 AB 1110 (2016) requires that every load-serving entity (LSE) include an annual average carbon emissions intensity
factor associated with its electricity supplies on its Power Content Label, starting with the 2019 PCL (which will be
published in 2020). For details on the CEC’s proposed accounting methodology, see the latest draft regulations and
rulemaking documents here: https://www.energy.ca.gov/power_source_disclosure/16-OIR-05/.
Page 8 of 13
The UAC expressed a clear preference for an hourly accounting approach using average
emissions factors (Method C or Method D), but asked to see more detail on the costs of taking
such an approach. The cost of abating these “residual emissions” shown for each accounting
methodology, of course, depends on the mechanism used to abate them. The mechanisms that
the City could potentially use to abate the residual emissions, and their current approximate
costs per metric tonne of CO2 abated, include:
• Unbundled RECs ($3.50/mT CO2)
• Carbon Offsets ($14/mT CO2)
• Carbon Allowances ($18/mT CO2)
• Bundled (Bucket 1) RECs ($44/mT CO2)
• Rebalancing the Portfolio (Difficult to quantify)
Based on these current market prices, the cost of cleaning up the portfolio’s residual emissions
for 2018—under an annual accounting approach and under an hourly accounting approach
using average emissions factors—is shown in Table 3 below. (As Table 2 indicates, under the
annual accounting approach the portfolio had 1,557 mT of residual emissions to abate in 2018,
while under the hourly accounting approach it had 17,675 mT of residual emissions. Although it
should be reiterated that 2018 was a drier than average year, and in a normal year the portfolio
would not have any residual emissions under any of the accounting approaches described
above.)
Table 3: Residual Emissions Abatement Costs for 2018 with Annual or Hourly Accounting
Annual
Accounting
Hourly Accounting
(Average
Emissions Factors)
Unbundled RECs $5,500 $62,000
Carbon Offsets $21,800 $247,000
Carbon Allowances $28,000 $318,000
Bundled (Bucket 1) RECs $68,500 $778,000
Given the significant difference in CO2 abatement cost for the various mechanisms discussed
above, it is worthwhile to consider their relative environmental impacts. First off, however, it
should be noted that according to all industry accounting protocols (other than the CEC’s PCL
accounting standard), “a REC is a multi-attribute commodity that embodies all of the non-
energy benefits associated with the generation of renewable energy. A REC can be separated
from the underlying electricity and applied to other electricity use to substantiate renewable
electricity use and ownership.”6 So although it would be very difficult to determine what
generating resource reduced its output as a result of that renewable energy generator being on
6 “Renewable Energy Certificates, Carbon Offsets, and Carbon Claims: Best Practices and Frequently Asked
Questions,” Center for Resource Solutions, April 2012. Accessed May 12, 2019. https://resource-solutions.org/wp-
content/uploads/2015/08/RECsOffsetsQA.pdf.
Page 9 of 13
the grid, all RECs legally embody the avoided Scope 2 emissions associated with renewable
energy (i.e., the carbon attribute).
The obvious intent with each of these abatement tools is to have a direct impact on mitigating
carbon emissions—to provide some “additionality,” in the parlance of environmental product
markets. Carbon offsets, if they are approved by a reputable certification body (e.g., The Gold
Standard or the Climate Action Reserve), are essentially guaranteed to satisfy this additionality
test. Priced at about $1.50 per MWh (or $3.50 per mT CO2), do unbundled RECs pass the
additionality test? To answer this, one would have to know whether the expectation of this
additional (small) source of revenue directly contributed to the deployment of an individual
renewable energy project. In most cases, of course, this is very hard to know.
One way to be sure of a REC’s direct impact would be to enter into a long-term contract to
purchase RECs from a specific project that has yet to be financed or built. By getting involved in
a project early in its development cycle, you can be relatively certain of your impact on its
deployment. However, given the City’s varying need for unbundled RECs under its current
strategy, it could be difficult to find such an arrangement. Although if the City opts to follow a
Minimal Compliance RPS strategy, it could be certain that it would need at least a minimum
level of unbundled RECs every year (equal to 10% of its total RPS procurement requirement).
Combined Effects of RPS Compliance Strategy and Carbon Accounting Methodology Changes
Putting it all together, the combination of potential changes to the City’s RPS procurement
strategy and its carbon accounting methodology have wide ranging implications for the City’s
total electric supply costs, as well as for how carbon-intensive and how “green” the portfolio
would appear to customers. Table 4 below addresses the latter effects, showing how carbon-
intensive the portfolio would appear on customers’ PCLs for 2020 as well as what RPS level the
City would report for that year.
Table 4: PCL Emissions Intensities and RPS Levels in 2020 under Various RPS Compliance
Strategies (and Expected Hydro Conditions)
Minimal
Compliance
Sell Excess
Supplies
Current
Portfolio
Carbon
Neutral
Every Hour
PCL Emissions Intensity
(lb CO2/MWh) 237 104 (148) 0
RPS Level (%) 21.6% 33.0% 60.7% 44.4%
For example, if the City pursues a Minimal Compliance strategy, the portfolio would have to
report a carbon intensity of 237 lb CO2/MWh on its PCL for 2020 (which would still be well
below the statewide average intensity, which is likely to be about 500 lb CO2/MWh in 2020),
and its RPS level would fall to 21.6% (compared to 60.7% for the portfolio in its current state).7
7 Although the state RPS mandate calls for utilities to achieve a 33% RPS level in 2020, the City could rely on its
Page 10 of 13
In terms of supply cost implications, the two types of potential policy changes—in RPS
compliance strategy and carbon accounting methodology—interact with each other in
significant ways. For example, as illustrated in Figure 2 above, switching to a Minimal
Compliance RPS procurement strategy could result in supply cost savings on the order of $5
million per year. However, this approach would also result in the City selling off large quantities
of RPS resources (e.g., 373,000 MWh of sales in 2020) and making generic market power
purchases to make up the difference. These market power purchases would be assigned an
emissions intensity of 0.428 metric tonnes of CO2 per MWh (the state’s standard multiplier for
generic market power), resulting in a significant volume of residual emissions to be cleaned up.
Due to the large disparity in the prices of unbundled RECs and carbon offsets, the difference in
the cost of abating these residual emissions for these two approaches would be over $1 million
per year (for the Minimal RPS Compliance strategy in 2020).
Table 5 below presents the net supply cost impact for the portfolio in 2020 for various
combinations of RPS compliance strategy and carbon accounting methodology. (Note that for
the “Current Portfolio (Dry Year)” scenario, the supply cost impact simply reflects the cost of
abating the residual emissions that the portfolio would experience that year, not the supply cost
impact of the additional market power purchases that would be required due to the
hydrological conditions.) It should be noted that the results shown below could change quite
significantly starting in 2025, depending on how much of the City’s current Western Base
Resource contract volume it chooses to retain when the new contract term begins.
Table 5: Net Supply Cost Impact in 2020 of Changes in RPS Compliance Strategy and Carbon
Accounting Methodology (in $000)
RPS Compliance Strategy
Minimal
Compliance
Sell
Excess
Supplies
Current
Portfolio
(Expected)
Current
Portfolio
(Dry Year)
Carbon
Neutral
Every Hour
Ca
r
b
o
n
A
c
c
o
u
n
t
i
n
g
Me
t
h
o
d
o
l
o
g
y
Annual Accounting
(Unbundled RECs) $ (7,070) $ (4,720) -- $ 160 $ 1,260
Annual Accounting
(Carbon Offsets) $ (6,040) $ (4,270) -- $ 630 $ 1,260
Hourly Accounting
(Unbundled RECs) $ (7,010) $ (4,670) -- $ 220 $ 1,260
Hourly Accounting
(Carbon Offsets) $ (5,810) $ (4,050) -- $ 860 $ 1,260
“banked” or excess RECs from the 2010-2019 period to comply with this requirement while maintaining an
effective RPS level for 2020 of less than 33%.
Page 11 of 13
CONCLUSION
In previous meetings, the UAC expressed a preference for following a minimal compliance RPS
procurement strategy (December 2017) and for adopting a carbon accounting methodology
that uses hourly average emissions factors (May 2019). The analysis in this report indicates that
opting for those two approaches would yield significant supply cost savings—particularly if the
City also chooses to continue the use of unbundled RECs to abate the residual emissions
associated with the portfolio’s reliance on wholesale market power purchases. If the City were
to opt to use carbon offsets to abate these residual emissions, the cost savings from switching
RPS compliance strategies would fall significantly.
Ultimately, staff is interested in UAC feedback on this question of which RPS compliance strategy
to pursue. One possible option to consider is having multiple rate options for people with
different cost and/or portfolio content preferences (e.g., a low-cost, minimum RPS compliance
option, an option like the current portfolio, and a more expensive, carbon neutral every hour
option) instead of imposing a single portfolio approach on everyone in Palo Alto. However, it
should be noted that implementing this approach would require a significant amount of time
and staff resources.
Staff concurs with the UAC’s preference for adopting a carbon accounting methodology that
uses hourly average emissions factors. And given the cost disparity between unbundled RECs
and carbon offsets, staff feels that any environmental benefit associated with offsets is not
justified by its greater cost and thus the City should continue to rely on unbundled RECs to
maintain a carbon neutral electric supply.
NEXT STEPS
Staff intends to return to the UAC in the coming months to request formal UAC action on these
items. After that, staff will take the UAC recommendation to the Finance Committee and the
City Council. The City’s carbon accounting methodology is codified in the Council-approved
Carbon Neutral Plan (Staff Report 3550, Resolution 9322) and therefore requires Council
approval to modify. And although the City’s RPS compliance strategy is not currently codified,
staff will still discuss the current approach with Council and seek validation of any significant
changes, given the level of financial implications associated with this strategy change.
If the UAC and Council support selling some of the City’s excess renewable supplies, staff would
then begin soliciting interest from CCAs and others in short- or long-term acquisition of these
resources. In order to take advantage of selling opportunities for 2019, staff would need to
begin to pursue such transactions within the next couple of months; therefore the City may
need to continue banking excess RPS supplies in 2019 and begin selling them in 2020.
Staff will also continue to closely follow (and comment upon) the CEC’s AB 1110 rulemaking
process. Depending on the accounting methodology the CEC finally adopts, staff will work to
understand how the City’s methodology can be aligned with the CEC approach, and, to the
degree that it cannot, determine how to explain this difference to customers.
Page 12 of 13
RESOURCE IMPACT
Staff estimates that switching to a minimal compliance RPS procurement strategy could result in
a decrease in supply costs on the order of $7 million per year through 2030. In addition,
switching to an hourly carbon accounting methodology, using average hourly emissions
intensity factors, could result in an increase in supply costs of approximately $60,000 in an
average hydrological year, if the City chooses to recognize the emissions reduction benefits of
unbundled RECs. However, if the City were to change to a minimal compliance RPS procurement
strategy, cleaning up the residual emissions with offsets rather than RECs would require an
additional $1.2 million in annual costs.
POLICY IMPLICATIONS
This report satisfies Initiatives #4 and #5 of the EIRP Work Plan. This report is also in line with
the Sustainability and Climate Action Plan goals of continuing to lower the carbon footprint of
the community.
ENVIRONMENTAL REVIEW
The Utilities Advisory Commission’s discussion of the City’s RPS procurement strategy and
carbon accounting methodology does not meet the definition of a project under Public
Resources Code 21065 and therefore California Environmental Quality Act (CEQA) review is not
required.
ATTACHMENTS
A. RPS Portfolio Detail and Minimum Compliance Financial Opportunity
PREPARED BY: JIM STACK, Senior Resource Planner
LENA PERKINS, Acting Senior Resource Planner
REVIEWED BY: JONATHAN ABENDSCHEIN, Assistant Director, Resource Management
APPROVED BY: ___________________________
DEAN BATCHELOR
Director of Utilities
Page 13 of 13
ATTACHMENT A: RPS Portfolio Detail and Minimum Compliance Financial Opportunity
Banked RECs (2011-2018)
Excess Procurement MWh 831,965
Historic Carryover MWh 368,733
CY: 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Projected Load MWh 918,878 912,332 905,627 899,248 893,197 887,490 882,089 877,067 872,403 868,132 864,123 860,444
Projected Retail Sales MWh 886,717 880,401 873,930 867,774 861,935 856,428 851,216 846,370 841,869 837,747 833,879 830,328
Total RPS Requirement %31%33%35.8%38.5%41.3%44%47%50%52%54.7%57.3%60%
Total RPS Requirement MWh 274,882 290,532 312,430 334,093 355,548 376,828 400,072 423,185 437,772 457,969 478,091 498,197
Bucket 1 Min MWh 206,162 217,899 234,323 250,570 266,661 282,621 300,054 317,389 328,329 343,476 358,568 373,648
Bucket 3 Max MWh 27,488 29,053 31,243 33,409 35,555 37,683 40,007 42,319 43,777 45,797 47,809 49,820
Current Portfolio by Type
Large Hydro MWh 545,860 521,523 514,056 485,957 485,957 485,957 478,671 478,671 478,671 478,671 478,671 478,671
Small Hydro MWh 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000
Solar MWh 320,668 320,149 318,574 317,006 390,072 388,045 386,029 384,024 382,030 380,046 378,073 376,111
Wind MWh 99,958 100,178 100,087 42,708 42,672 42,672 42,672 42,672 42,672 21,336 - -
Landfill Gas MWh 103,489 103,773 103,489 103,489 103,489 103,489 103,489 95,275 94,528 94,528 56,922 38,242
Total Renewables MWh 534,114 534,100 532,150 473,203 546,232 544,206 542,190 531,971 529,230 505,910 444,996 424,353
Bucket 0 MWh 213,447 213,951 213,576 156,197 156,161 156,161 156,161 147,946 147,200 125,864 66,922 48,242
Bucket 1 MWh 320,668 320,149 318,574 317,006 390,072 388,045 386,029 384,024 382,030 380,046 378,073 376,111
RPS Level %60.2%60.7%60.9%54.5%63.4%63.5%63.7%62.9%62.9%60.4%53.4%51.1%
Large Hydro Level %61.6%59.2%58.8%56.0%56.4%56.7%56.2%56.6%56.9%57.1%57.4%57.6%
Adjusted RPS Requirement %31.0%33.0%35.8%38.5%41.3%43.3%43.8%43.4%43.1%42.9%42.6%42.4%
Adjusted Bucket 1 Min MWh 206,162 217,899 234,323 250,570 266,661 277,853 279,409 275,774 272,398 269,307 266,406 263,743
Adjusted Bucket 3 Max MWh 27,488 29,053 31,243 33,409 35,555 37,047 37,254 36,770 36,320 35,908 35,521 35,166
Banked RECs Applied MWh 100,058 100,058 100,058 100,058 100,058 100,058 100,058 100,058 100,058 100,058 100,058 100,058
Total RECs Available MWh 634,173 634,159 632,208 573,261 646,290 644,264 642,248 632,029 629,288 605,968 545,054 524,411
Total RECs to Sell (B0-1)MWh 386,779 372,680 351,021 272,578 326,297 310,840 306,958 301,100 302,410 282,800 225,367 207,920
Total Bucket 3 to Buy MWh 27,488 29,053 31,243 33,409 35,555 37,047 37,254 36,770 36,320 35,908 35,521 35,166
Bucket 1 Premium $/MW 19.00$ 20.00$ 18.00$ 17.00$ 16.00$ 16.00$ 16.00$ 16.00$ 16.00$ 16.00$ 16.00$ 16.00$
Bucket 3 Premium $/MW 1.25$ 1.50$ 1.60$ 1.70$ 1.80$ 1.90$ 2.00$ 2.10$ 2.20$ 2.30$ 2.40$ 2.50$
Surplus REC Sales Revenue $000 6,827$ 6,873$ 5,756$ 4,066$ 4,652$ 4,381$ 4,315$ 4,229$ 4,257$ 3,950$ 3,038$ 2,764$
Bucket Swapping Revenue $000 488$ 537$ 512$ 511$ 505$ 522$ 522$ 511$ 501$ 492$ 483$ 475$
Total Financial Opportunity $000 7,314$ 7,410$ 6,268$ 4,577$ 5,157$ 4,903$ 4,837$ 4,740$ 4,759$ 4,442$ 3,521$ 3,239$
MEMORANDUM
TO: UTILITIES ADVISORY COMMISSION
FROM: UTILITIES DEPARTMENT
DATE: JUNE 5, 2019
SUBJECT: Discussion of Natural Gas Leakage from the City of Palo Alto’s Gas Distribution System
This report is provided to inform the discussion of the Utilities Advisory Commission about natural gas
leakage from the City of Palo Alto Gas Distribution System and its impact on carbon emissions. The City
currently purchases carbon offsets to mitigate the impact of natural gas use in Palo Alto on greenhouse
gas emissions. The City purchases offsets based on its load as measured at the gas receiving stations at
the edge of its distribution system, which means the City’s offset purchases account for all gas received
within Palo Alto’s service territory if it is combusted. However, some of that natural gas is released to the
atmosphere due to leakage. There is great uncertainty in the amount of gas released, and estimating it
would require additional study. However, there are two data sources that may be helpful in beginning the
discussion:
1. Unaccounted-for Gas: The City tracks “unaccounted-for gas” annually in its reports to the Federal
Department of Transportation. This number is the difference between gas metered and sold to
customers and gas received from PG&E’s transmission system at the edge of the City’s distribution
system. Unaccounted-for gas from 2013 to 2018 was roughly 1.5% to 2.5% of total gas received (1100-
1700 metric tons of natural gas each year). Unaccounted for gas is comprised of emissions to the
atmosphere and metering errors. Metering errors do not represent direct natural gas emissions to
the atmosphere – this gas is combusted, but escapes measurement due to meter inaccuracy. Natural
gas that is emitted to the atmosphere occurs due to a variety of reasons including: system operational
procedures to ensure safe operation of the system (which might involve actions that require venting
some gas to the atmosphere), leaks on the system, overpressure events, and excavation damage. Staff
does not know what percentage of the City’s unaccounted-for gas represents metering errors and
what represents natural gas emissions to the atmosphere. This would require additional study.
Figure 1: Unaccounted-for Gas
Palo Alto bases its GHG reporting to the US EPA and the California Air Resources Board on the amount
of gas received at its receiving stations, not the amount sold. Therefore, it purchases carbon
allowances and offsets based on numbers that include all of its unaccounted-for gas, assuming all of
that gas is combusted. This represents 2,500 to 3,900 MT CO2-e. If one were to assume that the
“unaccounted for gas” was released 100% to the atmosphere, however, it would have a greater
impact on emissions than if the gas were assumed to be 100% combusted, since methane has a global
warming equivalent of 21 times CO2 on a 100 year basis. The upper limit of 2013 to 2018 fugitive
emissions, assuming 100% of unaccounted for gas was leaked, would have been between 23,300 and
35,500 metric tons of carbon dioxide equivalent (MTCO2-e). This is an upper limit, and real fugitive
emissions are lower. For context, total reported gas system GHG emissions over that time were
between 140,000 and 160,000 MTCO2-e.
2. Other Historical Emissions Estimates: The City has also estimated its emissions using an estimating
methodology established by the American Gas Association based on United States Environmental
Protection Agency surveys and other data. The last time this estimate was done was in 2012
(Attachment A). This methodology uses estimated emissions rates for each mile of main, each meter,
and each service the utility owns. The estimated emissions rates were developed based on research
performed by various entities and are not specific to Palo Alto. In 2012 staff estimated emissions of
4,781 MTCO2-e. Since then, a number of pipeline replacements have been made of older, less resilient
pipe materials, so the emissions of the current system under this methodology is likely lower than the
2012 report.
The City works to find and control leakage for safety reasons as well. The City’s natural gas distribution
system is regulated by the Federal Department of Transportation, Pipeline and Hazardous Materials
Administration (PHMSA). PHMSA mandates all utilities perform leak surveys of their natural gas
distribution pipelines once each calendar year for pipelines in business districts, and a minimum of once
each five calendar years for pipelines outside of business districts. CPAU has taken an aggressive approach
to complete extensive leak surveys of the entire natural gas distribution system every two calendar years
instead of five years, while maintaining annual leak surveys for pipelines within business districts. These
surveys are performed using a combination of mobile and walking surveys of the City. This increased leak
survey frequency allows the City to locate, grade and repair natural gas pipeline leaks as soon as possible,
minimizing the hazards of leaking natural gas.
Please note that these leakage estimates do not include upstream emissions from the City’s receiving
stations. Some have estimated that leakage from the gas transmission system and from gas extraction is
substantial relative to the emissions from natural gas end-use consumption. If leakage from these sources
were also included, leakage emissions related to the community’s gas use could be considerably higher.
Estimation of this total leakage can be challenging, and estimates vary, but in August 2015 the National
Renewable Energy Laboratory, while acknowledging the high uncertainty in their analysis, estimated
nationwide fugitive emissions from natural gas production, transmission, and related activities could be
as much as four times as high as fugitive emissions (leakage) from gas distribution systems (see Estimating
U.S. Methane Emissions from the Natural Gas Supply Chain: Approaches, Uncertainties, Current Estimates,
and Future Studies, National Renewable Energy Laboratory Technical Report NREL/TP-6A50-62820,
August 2015).
Figure 2: Nationwide Natural Gas Production, Transmission, and Distribution System Emissions
Production, Gatherlna and 8oostin1
(50 MMt CO.e YC1 (33"11
ll DnDina: ancfWetl Completion
2) Producln& Wells
3) Githerint Unes
4) Gatherln, and Boosttn, Stations
Transmission and Storap
f52 MMt COat YC1 [U"ll
6). Transmiulon Comprusot Stations
7) Tranmusslon Pipeline
8) Undefsround Storace
Distribution 131 MMt C01• YC1 [Z°"U
9) Distribution Mains
10) Reculltors and Meters for.
a. City Gate
b. Larae Volume Customers
c:. Residential CUstomers
cl. Commffl:111 Customers
Source: National Renewable Energy Laboratory Technical Report NRELITP-6A50-62820, August 2015
Attachment:
Attachment A: 2012 Natural Gas Distribution System Greenhouse Gas Emission Report
PREPARED BY:
APPROVED BY:
JONATHAN ABENDSCHEIN, Assistant Director, Utility Resource Management
DEAN BATCHELOR
Utilities Director
City of Palo Alto
Utilities Engineering Department
Water-Gas Wastewater
Natural Gas Distribution System
Greenhouse Gas Emission Report
Based on (DOT Report 2012)
Source Emission Factor Units CPAU-Units Extended Units lb of CH4 lb of CO2
Commercial/Industrial Meters 2.02 lb CH4/meter-year 2350 gas meters 4747
Residential Meters 5.85 lb CH4/meter-year 21650 gas meters 126652.5
Plastic Pipe, Main Length 693 lb CH4/meter-year 143.8 miles 99653
Plastic Pipe, Main Length (Oxidation)38.89 lb CO2/mile-year 143.8 miles 5592
Plastic Pipe, Main (Leaks)41.64 lb CO2/mile-year 143.8 miles 5988
Protected Steel Pipe, Main Length 129.5 lb CH4/meter-year 65.62 miles 8498
Protected Steel Pipe, Main Length (Oxidation)11.01 lb CO2/mile-year 65.62 miles 722
Protected Steel Pipe, Main (Leaks)7.86 lb CO2/mile-year 65.62 miles 516
Copper Pipeline Services 10.74 lb CO2/service-year 48 services 516
Copper Pipeline Services (Oxidation)0 lb CO2/service-year 48 services 0
Copper Pipeline Services (Leaks)0.63 lb CO2/service-year 48 services 30
Plastic Pipeline Services 0.39 lb CH4/service-year 18147 services 7077
Plastic Pipeline Services (Oxidation)0.29 lb CO2/service-year 18147 services 5263
Plastic Pipeline Services (Leaks)0.03 lb CO2/service-year 18147 services 544
Protected Steel Pipeline Services 7.45 lb CH4/service-year 1126 services 8389
Protected Steel Pipe, Pipeline Services (Oxidation)0.55 lb CO2/service-year 1126 services 619
Protected Steel Pipeline Services(Leaks)0.45 lb CO2/service-year 1126 services 507
Total piping/meters CH4 Emission/year (lb of CH4)255532
Total piping/meters C02 Emission/year (lb of CO2)19782
Gate Stations 61390 lb CH4/station-year 4 stations 245560
Total CH4 Emission/year (lb of CH4)501092
Total C02 Emission/year (lb of CO2)19782
Converted CH4 to CO2 (lb of CO2)CH4 21 times the potential of CO2 10522937 19782
Total CO2 equivalent emission (lb of CO2)10542719
Total CO2 equivalent emission (Metric Tons of CO2)1 metric ton = 2205 lbs 4781.3
Gas Distribution System Meters and Piping (DOT Report 2012)
Gas Stations Emissions Calculations
City of Palo Alto - Utilities Engineering Department
Fugitive Gas Emissions Calculations
NOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to exceed 100,000
for each violation for each day that such violation persists except that the maximum civil penalty shall not exceed
$1,000,000 as provided in 49 USC 60122.
OMB NO: 2137-0522
EXPIRATION DATE: 01/31/2014
U.S Department of Transportation
Pipeline and Hazardous Materials Safety Administration
Form Type:
INITIAL
Date Submitted:3/5/2013
(DOT use only)20130562-17651
ANNUAL REPORT FOR
CALENDAR YEAR 2012
GAS DISTRIBUTION SYSTEM
A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply with a collection of
information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid OMB Control Number. The OMB Control
Number for this information collection is 2137-0522. Public reporting for this collection of information is estimated to be approximately 16 hours per response, including the
time for reviewing instructions, gathering the data needed, and completing and reviewing the collection of information. All responses to this collection of information are
mandatory. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Information
Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590.
PART A - OPERATOR INFORMATION
1. Name of Operator PALO ALTO, CITY OF
2. LOCATION OF OFFICE (WHERE ADDITIONAL
INFORMATION MAY BE OBTAINED)
2a. Street Address 3201 EAST BAYSHORE ROAD
2b. City and County PALO ALTO,SANTA CLARA
2c. State CA
2d. Zip Code 94303
3. OPERATOR'S 5 DIGIT IDENTIFICATION NUMBER 15084
4. HEADQUARTERS NAME & ADDRESS
4a. Street Address 250 HAMILTON AVENUE
4b. City and County PALO ALTO,SANTA CLARA
4c. State CA
4d. Zip Code 94301
5. STATE IN WHICH SYSTEM OPERATES CA
PART B - SYSTEM DESCRIPTION
1.GENERAL
STEEL
UNPROTECTED CATHODICALLY
PROTECTED
BARE COATED BARE COATED DUCTILE
IRON COPPER
CAST/
WROUGHT
IRON
PLASTIC OTHER TOTAL
MILES OF
MAIN 0.000 0.000 0.000 65.620 0.000 0.000 0.000 143.800 0.060 209.480
N0. OF
SERVICES 0.000 0.000 0.000 1126.000 0.000 48.000 0.000 18147.000 0.000 19321.000
2.MILES OF MAINS IN SYSTEM AT END OF YEAR
MATERIAL UNKNOWN 2' OR LESS OVER 2' THRU 4' OVER 4' THRU 8' OVER 8' THRU 12' OVER 12'TOTAL
STEEL 0.000 38.970 17.390 6.890 2.370 0.000 65.620
DUCTILE IRON 0.000 0.000 0.000 0.000 0.000 0.000 0.000
COPPER 0.000 0.000 0.000 0.000 0.000 0.000 0.000
CAST/WROUGHT
IRON 0.000 0.000 0.000 0.000 0.000 0.000 0.000
PLASTIC PVC 0.000 22.800 12.090 2.190 0.000 0.000 37.080
PLASTIC PE 0.000 49.440 20.100 24.830 0.000 0.000 94.370
PLASTIC ABS 0.000 4.100 6.290 1.960 0.000 0.000 12.350
PLASTIC OTHER 0.000 0.000 0.000 0.000 0.000 0.000 0.000
OTHER 0.060 0.000 0.000 0.000 0.000 0.000 0.060
TOTAL 0.060 115.310 55.870 35.870 2.370 0.000 209.480
3.NUMBER OF SERVICES IN SYSTEM AT END OF YEAR AVERAGE SERVICE LENGTH: 40
MATERIAL UNKNOWN 1' OR LESS OVER 1' THRU 2' OVER 2' THRU 4' OVER 4' THRU 8' OVER 8'TOTAL
STEEL 0.000 1104.000 22.000 0.000 0.000 0.000 1126.000
DUCTILE IRON 0.000 0.000 0.000 0.000 0.000 0.000 0.000
COPPER 0.000 48.000 0.000 0.000 0.000 0.000 48.000
CAST/WROUGHT
IRON 0.000 0.000 0.000 0.000 0.000 0.000 0.000
PLASTIC PVC 0.000 3021.000 319.000 73.000 1.000 0.000 3414.000
PLASTIC PE 0.000 12593.000 297.000 67.000 63.000 0.000 13020.000
PLASTIC ABS 0.000 1390.000 262.000 61.000 0.000 0.000 1713.000
PLASTIC OTHER 0.000 0.000 0.000 0.000 0.000 0.000 0.000
OTHER 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOTAL 0.000 18156.000 900.000 201.000 64.000 0.000 19321.000
4.MILES OF MAIN AND NUMBER OF SERVICES BY DECADE OF INSTALLATION
UNKNOWN PRE-1940 1940-1949 1950-1959 1960-1969 1970-1979 1980-1989 1990-1999 2000-2009 2010-2019 TOTAL
MILES OF
MAIN 10.000 13.000 11.200 14.000 23.000 33.280 18.500 40.000 43.000 3.500 209.480
NUMBER OF
SERVICES 395.000 446.000 330.000 354.000 1345.000 2233.000 2945.000 5197.000 5811.000 265.000 19321.000
PART C - TOTAL LEAKS AND HAZARDOUS LEAKS ELIMINATED/REPAIRED DURING THE YEAR
CAUSE OF LEAK
MAINS SERVICES
TOTAL HAZARDOUS TOTAL HAZARDOUS
CORROSION 3 0 8 4
NATURAL FORCES 0 0 3 1
EXCAVATION DAMAGE 3 3 44 44
OTHER OUTSIDE FORCE
DAMAGE 0 0 0 0
MATERIAL OR WELDS 10 5 6 2
EQUIPMENT 8 0 0 0
INCORRECT OPERATIONS 0 0 0 0
OTHER 2 0 8 3
NUMBER OF KNOWN SYSTEM LEAKS AT END OF YEAR SCHEDULED FOR REPAIR : 111
PART D - EXCAVATION DAMAGE PART E-EXCESS FLOW VALUE(EFV) DATA
NUMBER OF EXCAVATION DAMAGES: 47 NUMBER OF EFV'S INSTALLED THIS CALENDER YEAR ON SINGLE
FAMILY RESIDENTIAL SERVICES: 180
NUMBER OF EXCAVATION TICKETS : 4151
ESTIMATED NUMBER OF EFV'S IN
SYSTEM AT THE END OF YEAR: 4762
PART F - LEAKS ON FEDERAL LAND PART G-PERCENT OF UNACCOUNTED FOR GAS
TOTAL NUMBER OF LEAKS ON FEDERAL LAND REPAIRED OR
SCHEDULED TO REPAIR: 1
UNACCOUUNTED FOR GAS AS A PERCENT OF TOTAL INPUT FOR
THE 12 MONTHS ENDING JUNE 30 OF THE REPORTING YEAR.
INPUT FOR YEAR ENDING 6/30: 3.1%
PART H - ADDITIONAL INFORMATION
PART I - PREPARER AND AUTHORIZED SIGNATURE
Alicia Easton,Utility Projects Coordinator
(Preparer's Name and Title)
(650) 496-5944
(Area Code and Telephone Number)
alicia.easton@cityofpaloalto.org
(Preparer's email address)
(650) 496-6924
(Area Code and Facsimile Number)
Attachments:
2012 DOT Annual Report
Page 79, Table VII-4. More Detailed Fugitive Emission Factors for Transmission
Equipment, World Resources Institute, June 6, 2007
Page 80, Table VII-5. More Detailed Fugitive Emission Factors for Transmission
Equipment, World Resources Institute, June 6, 2007