PUC to Staff Responses 60-65.tif

CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
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Quick Bites: Energy News Roundup
by CEM Staff
The California Air Resources Board and Quebec’s Ministry
of the Environment on Nov. 27 released results from their Auc-
tion 41. Roughly 52.6 million in current carbon allowances, cov-
ering 2019 and 2024, were available, and all sold at a settlement
price of $31.91. The 7.2 million advance allowances, for 2027,
were all sold at a settlement price of $30.16. The agencies hold
joint greenhouse gas allowance auctions that enable market par-
ticipants to acquire greenhouse gas allowances as part of their
respective capand trade programs. Dates for upcoming 2025
auctions are posted. The next is scheduled for Feb. 19, 2025.
A global initiative focused on creating guidelines and best
practices supporting clean-energy technology development
launched Dec. 5. The public-private Mercury Consortium, man-
aged by the Electric Power Research Institute, consists of roughly
two dozen energy sector companies. Kraken Technologies, an
energy technology platform created by Octopus Energy Group, in
a news release said it modeled the consortium based on Ericsson’s
Bluetooth connectivity standards development. The group seeks
to “define common functional behaviors for low-carbon devices,
ensuring they work seamlessly with the grid, regardless of brand,
boosting consumer confidence in the energy transition.” Growth
in such devices’ use is expected to exceed 200 million by 2030,
and if managed inefficiently, the surge could drive peak electricity
demand beyond grid capacity, according to the group. “Mercury is a
perfect example of how we can work together across the industry to
advance the digital, dynamic grid of the future,” PG&E Corp. CEO
Patti Poppe said in the release. Other founding members join-
ing Kraken, EPRI and PG&E include Octopus Energy, Southern
California Edison, Amazon Web Services, GridX and Oracle. The
consortium said its membership is open to electric utilities, manu-
facturers, technology providers, regulators and others.
Executives from Pioneer Community Energy and NextEra
Energy Resources on Nov. 22 celebrated the opening of NextEra’s Yel-
low Pine Energy Center II, a 125-MW solar facility with a co-located
four-hour/85-MW battery energy storage system in Clark County,
Nevada. Pioneer, a locally owned, not-for-profit community choice
aggregator serving El Dorado and Placer counties, has entered into
a long-term power-purchase agreement for 60 MW of solar energy
and 53 MW of energy storage services from the project, which is a
subsidiary of NextEra. “As California summers continue to bring
extreme heat and high electricity demand, the ability to discharge
energy during peak hours is critical as we transition to a clean grid,”
Pioneer Board Chair and Auburn City Councilmember Alice Dow-
din Calvillo said in a news release. Pioneer serves more than 800,000
people via 170,000 meters, according to the release.
Xcel Energy on Dec. 3 said it has introduced artificial intelli-
gence to its wildfire detection and mitigation efforts in the Texas
Panhandle. The company has acknowledged that equipment owned
by Southwestern Public Service, its Texas-New Mexico subsidi-
ary, most likely sparked Texas’ Smokehouse Creek Fire in March
(California Energy Markets No. 1785). It recently said it has settled
roughly half of the claims related to the incident. “We want to better
safeguard our neighbors and reduce the risk of future wildfire loss
by investing in advanced wildfire detection capabilities,” Adrian
Rodriguez, president of SPS, said in a news release. “Providing this
technology to our first responders with the information they need
to act swiftly and safely to respond to wildfires will improve public
safety.” Xcel has estimated a $215 million loss related to the incident
and said in a recent earnings call it anticipates additional complaints
and demands (California Energy Markets No. 1819).
Public Service Company of New Mexico and Clēnera on
Dec. 4 marked the opening of the 364-MW/1.2-GWh Atrisco
solar and energy storage project in Bernalillo County with a
ribbon-cutting ceremony. PNM, New Mexico’s largest utility,
has a contract for the full output and storage resources of the
$850 million project, according to a news release. The utility
expects the facility to produce enough energy to serve about
110,000 New Mexico households each year, and estimates it
will provide about $1 million in annual tax revenue.
Strata Clean Energy on Dec. 4 said it has completed the
70-MW/280-MWh Inland Empire Energy Storage project in
Rialto, California. Strata President Bob Schaffeld in a news
release called the project “a milestone that will support Califor-
nia’s transition to renewable energy and enhancement of grid
reliability across the region” and said it reflects his company’s
commitment to supporting a “sustainable, renewable-powered
grid.” The project, which became commercially operational in
October, is interconnected to both the Pacific Gas & Electric
and Southern California Edison grids to aid in grid-modern-
ization efforts. It will store excess energy generated during
periods of low demand to be released during periods of peak
demand and will support California’s renewable-energy tar-
gets, according to the release.
NEWS IN BRIEF
Courtesy Octopus Energy
Devrim Celal, CEO of KrakenFlex, addresses the crowd during the Dec. 5 launch of
the Mercury Consortium in Manchester, England.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
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BOTTOM LINES
Legislature Signals Action on Energy Costs During Special Session
by Jason Fordney
Gov. Gavin Newsom’s special session of the state Legisla-
ture that began Dec. 2 has the expressed goal of preparing for
the administration of President-elect Donald Trump, specifi-
cally continuing to sue the federal government as state officials
did during Trump’s first term.
But in the wake of a national election in which inflation
and the cost of living were central political issues, California
lawmakers indicated that energy affordability will be a priority
during the session.
While the state Legislature and state agencies in recent
years have focused on decarbonizing the electric grid, trans-
portation and buildings, Assembly Speaker Robert Rivas
(D-Salinas) on Dec. 2 said lowering energy costs for Califor-
nians will now be a priority.
“We must do more to lower energy costs,” Rivas said in his
opening speech. “High energy prices hit low-income Califor-
nians the hardest. Look—California has always led the way on
climate. And we will continue to lead on climate, but not on
the backs of poor and working people, not with taxes or fees
for programs that don’t work, and not by blocking housing
and critical infrastructure projects.
“It’s why we must be outcome-driven. We can’t blindly
defend the institutions contributing to these issues,” he said.
Rivas said he will direct the Committee on Utilities and
Energy and the Committee on Budgets to “double down on
investigating energy costs.”
Rivas’ statement follows Newsom’s Oct. 30 order directing
state agencies such as the California Energy Commission, the
California Public Utilities Commission, the California Air
Resources Board and the Office of Energy Infrastructure Safety
to review and analyze all electric-ratepayer-funded programs
for possible underutilization and potential modifications.
That action has raised concern from some consumer advo-
cates about program cuts for lower-income people (California
Energy Markets No. 1822).
The Legislature at the end of the last regular session also
threw together a last-minute attempt to defray energy costs
for California consumers, but several of the proposals fizzled
(California Energy Markets No. 1811).
There is a widespread perception that the policies of the
state Legislature and state agencies are at least partly the reason
for those high costs. The CPUC has approved a series of rate
increases for Pacific Gas & Electric, and Newsom-appointed
CARB’s move to amend the Low Carbon Fuel Standard drew
a lot of attention as it looks poised to hike gasoline prices in a
state where the resource is already very expensive. More than
2.4 million utility customers are behind on their bills, to the
tune of billions of dollars.
After Newsom called the special session, he proposed a
$25 million legal fund to sue the Trump administration, specif-
ically mentioning the areas of “reproductive health care, access
to clean air and water, and fundamental civil rights.”
In 2018, for example, the state successfully sued the
U.S. Department of Energy under Trump to force the agency
to implement nationwide energy-efficiency standards. The
action covered four products: portable air conditioners, unin-
terruptible power supplies, air compressors and commercial
packaged boilers.
Nevertheless, Newsom also signaled cooperation with the
incoming administration, saying he wants to help Trump “suc-
ceed in serving all Americans.”
Newsom’s special session got some drubbing from Cal-
ifornia media, with Sacramento Bee columnist Tom Philp
calling it “phony” and an “attention-getting gimmick.” State
Sen. Brian Jones (R-San Diego), the Senate minority leader,
said publicly that Newsom was trying to get headlines by call-
ing the session. Jones and the state’s Republican caucus said
they are introducing a bill, Senate Bill 2, to repeal CARB’s
LCFS amendment.
So, it appears that energy will be front and center as the
Legislature reconvenes in the wake of an election that saw
Trump gain ground with California voters, signaling that per-
haps state Democrats should get the message from the public
regarding costs of living, including energy costs. But as of now,
the choice seems to be confrontation or isolation from the
incoming administration.
Office of the Governor
For California Gov. Gavin Newsom, the goal for the next four years is black and
white: thwarting the incoming administration of President-elect Donald Trump.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
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MARKETS
September, would advance independent governance efforts
of both CAISO’s Western Energy Imbalance Market and its
EDAM, but that key concerns of potential market participants
remain unresolved (California Energy Markets No. 1814).
Moreover, they say that the initiative remains somewhat
speculative in that it depends on the California Legislature
enacting a change that would enable the establishment of a
new regional organization to set market policy for EDAM.
They also say the Step 2 proposal is vague regarding the
evolution of additional services in the day-ahead market.
“Preserving an option for a day-ahead market to expand to full
[regional transmission organization] services is an important
objective for many in the West that remains elusive at CAISO
for policy, political, and practical reasons,” the addendum
says. “The language in the Step 2 Final Proposal around Step
3, a pathway to additional services, is more aspirational than
concrete.”
SPP has operated a regional transmission organization in
the Eastern Interconnection since 2004 and hopes to launch its
RTO West expansion in 2026 (California Energy Markets No.
1798). The joint authors in the addendum say that Markets+
already has a structure in place to guide the evolution of a day-
ahead market into a Western RTO.
The addendum acknowledges that WWGPI’s Step 2
advances meaningful progress toward a transparent, stake-
holder-led market-development process for EDAM. It also says
that the selection process for the regional organization would
likely improve geographic diversity and independence in the
day-ahead offering.
Compared with Markets+, however, stakeholders would
still be at a deficit with regard to decision-making author-
ity and voting rights, the joint authors say. They also point
to problems with the continuation of a single shared tariff
between CAISO and the regional organization, which they say
limits the organization’s independence from CAISO’s Board of
Governors.
Also problematic, the joint authors say, is that CAISO,
under the framework proposed in Step 2, would retain its cur-
rent balancing authority and market operator roles, a circum-
stance the Markets+ proponents say presents a conflict.
CAISO maintains that such concerns have been publicly
addressed and that it is advancing efforts to provide equitable
opportunities for all balancing authority areas and their con-
stituents that participate in EDAM (California Energy Markets
No. 1821).
Under the WWGPI approach, however, EDAM would not
have an independent governance structure at its launch. This
risks harming ratepayers outside the CAISO BAA, the adden-
dum says.
Finally, the joint authors say that the market design of
CAISO’s EDAM fails to represent the interests of all stakehold-
ers because it adopts the existing EDAM and WEIM market
designs as its starting point.
“This approach embeds the numerous market design
choices that were made under California-centric governance
into the market and thus fails to address one of the most fun-
damental challenges of EDAM/WEIM,” the addendum says.
CAISO spokesperson Anne Gonzales in a phone conver-
sation with California Energy Markets said the grid operator
is still reviewing the addendum, which was posted late in the
afternoon Dec. 9.
Though multiple independent studies suggest that a single
Western day-ahead market that includes California would
provide the greatest benefit to all participants, the joint authors
conclude the addendum with a nod to the value of healthy
competition.
The development of Markets+, they say, provides stake-
holders with an option “to choose the market that is best for
their customers, while also providing continued pressure for
CAISO to continue to improve both their governance frame-
work and market design.”
The Federal Energy Regulatory Commission approved
CAISO’s EDAM tariff in December 2023. SPP anticipates
a decision from the federal regulator on its Markets+ tariff
before the end of the year.
Markets+ Funders
Continued from Page 1
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CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
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REGULATION STATUS
PG&E Requests $4.4B Capital-Costs Cap for 2025-2026
by Anne Ernst
Pacific Gas & Electric filed a request with the California
Public Utilities Commission to raise its capital-costs cap by
billions of dollars for 2025 and 2026 and eliminate a reve-
nue-requirement cap to help the utility address its energization
backlog.
If the request is approved, the average bundled rate would
increase by 1.8 percent and a typical ratepayer bill would
increase by $3.65 per month, according to PG&E’s motion.
“These impacts would be mitigated by additional revenue
from increased load that puts downward pressure on rates,”
PG&E’s Oct. 4 filing said.
PG&E filed the request for the commission to approve
increasing its 2025 capital-costs cap to $2.1 billion, up from
$619 million, and its 2026 cap to $2.3 billion, up from $669
million [R24-01-018].
The new proposed increase would allow PG&E to “more
than double the amount of customer-requested energization
work than can be completed under the current caps,” as well as
meet its legislative obligations by reducing to zero the custom-
er-connection backlog by the end of 2026.
Assembly Bill 50, which passed in 2023, requires utilities
to eliminate their backlog of energization projects. Senate Bill
410, which passed in 2023, requires the CPUC to ensure that
utilities have sufficient time to recover energization project
costs.
On Dec. 2, PG&E announced two stock offerings totaling
$2.4 billion (see related story).
The CPUC in September approved an interim rate request
for the utility of almost $944 million over a 17-month period
for wildfire mitigation cost recovery [D24-09-003, A23-12-
001] (California Energy Markets No. 1811).
PG&E also wants the CPUC to eliminate the combination
of capital-cost caps and revenue-requirement caps, or RRQ, for
2024 to 2026, because it creates “unnecessary ambiguity and
confusion” and inhibits the utility’s “ability to accelerate project
work as envisioned” in SB 410.
“Setting the annual cost caps based on capital costs only is
the most straightforward way for us to manage capital spend-
ing and support our project-acceleration efforts,” PG&E’s filing
says. “It also clearly defines the amount of eligible capital costs
for the eventual recording of RRQs to the approved memoran-
dum account once those projects become operative.”
Consumer advocacy groups such as The Utility Reform
Network and the CPUC’s Public Advocates Office oppose the
request, which would cumulatively increase ratepayer bills by
more than 4 percent on top of several other approved increases
over the past two years.
The “substantial request has significant implications for
ratepayers,” is out of line with rate-setting processes and time-
lines, and “should be dismissed,” Cal Advocates’ brief says.
“PG&E’s request is an abuse of SB 410’s Powering Up
Californians Act,” TURN spokesperson Lee Trotman said in
a statement. “The CPUC set these caps just months ago to
protect customers from excessive spending so approving this
increase so soon after the caps were set makes no sense. TURN
calls on the CPUC to hold PG&E accountable and deny this
unnecessary hike.”
Cal Advocates said the CPUC in a previous decision
found that a previous PG&E request “was unreasonable and
set a cost cap below what PG&E had proposed” [D24-07-008,
A21-06-021].
“This would include identifying the changed facts and
circumstances to justify more than tripling the energization
cost caps that the commission determined were reasonable less
than three months ago,” Cal Advocates’ brief says.
PG&E said the additional funding would allow it to “com-
plete nearly 19,000 more projects to eliminate” its existing
backlog “as well as address new applications and emergent
energization projects.”
“To clear the backlog of in-process customer connection
applications by the end of 2026 while meeting new customer
requests, we need to complete approximately 38,000 projects in
2025 and 2026,” PG&E’s filing says.
In a Nov. 25 filing, PG&E said it energized 85 percent of
customer applications that were deemed complete as of Jan. 31,
Ken Lund/Flickr
Pacific Gas & Electric is requesting more than $4 billion in funds to cover energiza-
tion costs in 2025 and 2026.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
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2023. A higher demand forecast due to increasing electrifica-
tion will exacerbate the backlog, PG&E said.
“As of July 2024, we completed over 7,000 customer con-
nections this year. We also expect to complete more than 5,000
additional customer connections by the end of the year. More
energization work needs to be done in 2025-2026, both on
pending applications and new applications we will receive as
electrification demands increase,” PG&E’s motion says.
With the additional funds, PG&E said it could place into
service “123 line capacity and 19 substation capacity projects
in 2025; and 265 line capacity and 38 substation capacity proj-
ects in 2026.”
PG&E requested a decision on its motion by the first quar-
ter of 2025 to “maximize” planning and coordination.
CPUC OKs Adjustments to Central Procurement Entity Framework
by Anne Ernst
State energy regulators approved changes to a program
that aggregates the buying power of utilities and is intended to
improve reliability through a central procurement entity.
Modifications to the central procurement entity frame-
work by the California Public Utilities Commission in a Dec.
5 decision include adjustments to the planning reserve margin
and loss-of-load expectations as well as making procurement
information more accessible.
Investor-owned utilities Pacific Gas & Electric, Southern
California Edison and San Diego Gas & Electric have served
as the central procurement entity for their respective distribu-
tion service areas for the multiyear local resource-adequacy
program since the 2023 RA compliance year.
There has been a lack of participation by load-serving enti-
ties in the “non-compensated self-show” option in reporting
their procurement, which stifles central procurement entities
from securing a portfolio to meet resource-adequacy require-
ments, according to the CPUC decision.
PG&E recommended the CPUC eliminate and replace
the non-compensated self-show option to provide the central
procurement entity more detailed information about what
LSEs have under contract, which would then improve the CPE
procurement process, according to the decision.
Additionally, CPE allocations will be locked in earlier,
which will “increase certainty for LSEs to understand how
much system and flexible” resource adequacy they might need
to procure, the decision says.
Modifications also include correcting mistakes such as ones
found in the slice-of-day tool, which was revised in August
to correct errors identified in exceedance calculations and in
accounting for storage.
The CPUC’s loss-of-load-expectation analysis used the
California Energy Commission Integrated Energy Policy
Anne Ernst
The California Public Utilities Commission approved changes made to the central
procurement entity framework on Dec. 5.
Report’s energy-demand forecast managed peak instead of a
consumption peak because it found that managed peak was
more consistent with historical trends.
The state Department of Water Resources was directed by
the CPUC in August to procure 10.6 GW of nameplate capac-
ity from long-lead-time emerging technologies as part of the
central procurement process (California Energy Markets No.
1809).
Gov. Gavin Newsom signed Assembly Bill 1373 to create
the program in 2023 (California Energy Markets No. 1765).
Data requests for the 2026 resource-adequacy compliance
year will be sent in January, and LSEs are expected to respond
by Feb. 1.
Wildfire Fund Will Cost Ratepayers $923 Million in 2025
by Anne Ernst
Dozens of public speakers voiced their displeasure over
a ratepayer charge of almost $923 million approved by state
energy regulators Dec. 5 that will contribute to a wildfire liabil-
ity insurance fund.
Speakers at the California Public Utilities Commission’s
Dec. 5 meeting objected to the CPUC’s approval of the charge
to be collected from ratepayers in 2025 to fund the state’s
Wildfire Fund. The amount includes more than $20 million in
undercollected funds in 2024 [R23-03-007].
Several commenters said they were associated with Stop
PG&E or Reclaim Our Power, two nonprofit organizations
calling for utility restructuring. They accused commission
members of being “corrupt” and “uncaring” and allowing
investor-owned utilities—most speakers specifically referred
to Pacific Gas & Electric—to prioritize “profit over safety.”
Following the vote, which passed unanimously and
occurred after almost two hours of public comments, CPUC
member Matt Baker offered some clarification on the Wildfire
Fund.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
7An Independent News Service From NewsData • © Copyright NewsData LLC 2024
The fund, which was established with the 2019 passage of
Assembly Bill 1054, is funded half by ratepayers and half by
IOU shareholders, Baker said. It exists as a mechanism for
IOUs to recover certain costs associated with wildfires covered
by the fund, which is authorized to distribute money to the
IOUs after they have paid or settled eligible claims.
It is insurance liability protection from “any new fires that
were caused by utility equipment to cover the damages,” Baker
said, and does not apply to any fires that occurred before the
legislation’s 2019 passage.
Kevin Krejci/Flickr
The California Wildfire Fund was established in 2019 following several catastrophic
wildfires caused in previous years by utility equipment.
“The vote that we had today was to … renew the fund”
and is not technically an increase, he said. “Insurance has
traditionally been paid for by ratepayers pretty much in all
situations. AB 1054 is unique in the sense that it requires
utility shareholders to foot the bill for half of the cost of this
insurance.”
Baker was the former director of the CPUC’s Public Advo-
cates Office prior to being appointed as a commission member
in February.
The nonbypassable charge for 2025 amounts to
0.595 cents/kWh. In 2024, the amount was set at 0.561 cents/kWh
for a total revenue requirement of $889 million [R19-07-017,
D19-10-056].
The IOUs are directed to collect the charge from rate-
payers through monthly service bills and remit the funds to
the California Department of Water Resources, a decision
that was approved by the CPUC in 2020 [D20-07-014]. The
collection acts as an extension of a bond charge DWR col-
lected based on the 2000-2001 Western energy crisis, which
ended in 2020 (California Energy Markets No. 1552). The
California Earthquake Authority serves as the Wildfire Fund
administrator.
On Oct. 7, DWR notified the CPUC of updated calcu-
lations reducing the proposed amount to be collected to
$923 million from $930 million.
Consumer advocates and wildfire victims opposed the
Wildfire Fund, arguing that IOUs should foot the bill (Califor-
nia Energy Markets No. 1562).
REGIONAL ROUNDUP
acceleration in the rate of grid buildout compared with the
flatter demand growth of recent years.
Western reliability officials adopted an urgent tone in a new
reliability assessment of the region’s grid, saying a “staggering”
amount of new electrical load coming on the system has dou-
bled the demand forecast from just two years ago.
Annual demand in the Western Interconnection is forecast
to grow 20.4 percent, from 942 TWh in 2025 to 1,134 TWh in
2034, according to the report by the Western Electricity Coor-
dinating Council. The organization is responsible for enforc-
ing national reliability standards and engaging in long-term
resource planning.
The new forecast is more than double the 9.6-percent
growth rate in 2022 resource plans and four times the histor-
ical growth rate of about 4.5 percent between 2013 and 2022,
WECC said in its Western Assessment of Resource Adequacy
2024 report.
WECC took a fairly grim view as to whether the needed
capacity can be built.
“To meet growing demand, entities plan to build unprece-
dented amounts of new resources over the next decade. Never
has generation been built in the West at the rate called for
in current resource plans. These plans could be unattainable
given past struggles to build planned resources on time,” the
report says.
Current resource plans include 172 GW of new generation
over the next decade, more than double that added in the West
in the past 10 years, which will require a massive effort. About
74 GW of new resources were added between 2014 and 2023,
amid resource retirements and a more variable resource mix.
About 85 percent of planned new resources are wind and solar,
battery energy storage, or hybrid facilities.
Not only have the new facilities and widespread electrifica-
tion pushed up the load growth forecast dramatically in recent
years, they have made it much less predictable, the officials said.
Only about 76 percent of resources proposed between 2018
and 2023 came on line as scheduled. And only a little more
Reliability
Continued from Page 1
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
8An Independent News Service From NewsData • © Copyright NewsData LLC 2024
than half—53 percent—came on line as scheduled in 2023,
with the rest delayed or canceled. If there are major delays to
new resources, the West might run into resource problems
over the next decade, the report says.
“In the past, when there was steady, predictable load
growth and a generation surplus, entities could grossly esti-
mate the resources needed 5 to 10 years in the future and hone
those plans later. There was enough surplus generation in the
interconnection to cover situations where new resources were
built late, cancelled, undersized, or when demand increased
unexpectedly,” WECC said.
A separate report by Grid Strategies that looks at the whole
country also has some dramatic numbers that highlight increases
in load-growth forecasts over the past two years. The consulting
firm projects a fivefold increase compared with the five-year load-
growth forecasts over those two years, from 23 GW to 128 GW
nationally, also with data centers as a strong driver.
The report puts national data center demand growth at
between 65 and 90 GW, manufacturing demand at up to
20 GW and new demand from other sources, such as elec-
trification, at 20 GW. Regions driving the growth include
the Pacific Northwest (data centers and chip manufacturing
plants); the Southwest Power Pool (oil and natural gas pro-
duction, data centers); the Midcontinent Independent System
Operator (manufacturing and data centers); the PJM Inter-
connection (data centers in northern Virginia); Georgia (data
centers and manufacturing in Atlanta); and Texas (data centers
in the Dallas-Fort Worth area and oil and gas production).
The Bonneville Power Administration projects almost
3 GW of demand growth by 2029 from data centers and only
1 GW from other drivers, according to the report.
Over the past few decades there has been low growth in the
utility industry—about 1 percent per year—but if the new fore-
casts are correct, growth will rise to 3 percent a year over the
next five years. That might sound small, but it means sixfold
growth in planning and construction of new generation and
transmission, Grid Strategies said.
Western Electricity Coordinating Council
The planned mix of new resources in the Western Interconnection over the next
decade.
Challenges in meeting this growth include low rates of new
transmission construction and the fact that some data centers
use power in a way that makes reliable grid operation more
difficult. A great amount of uncertainty overall adds to the
challenge, the firm said. Another threat is that unavailability of
adequate power could affect the artificial intelligence industry’s
growth and the larger American economy, making accelerated
development of new resources critical, the report says.
Utilities and regulators are turning to new financial com-
mitments from large-load customers through new direct con-
tracts between customers and generation suppliers—including
a recent deal between Google and NV Energy, for example,
which “allows Google to select its power supplier, but it must
do so for the life of the project and cover any premium com-
pared to what NV Energy would have procured to serve the
load,” according to Grid Strategies’ report. The deal is pending
regulatory approval. Others are relying on tariff changes for
large-load customers, as AEP has done in Indiana and Ohio.
Data centers can also cause new risks such as rapid changes
in load, which might stem from cryptocurrency miners
responding to prices, activation of backup power systems to
enable ride-through of even small changes in voltage, or the
changing-load-growth nature of AI training models.
“Where large amounts of load suddenly disappear (or reap-
pear) due to any of these causes, it can require a large, almost
instantaneous response by grid operators,” the report says,
mentioning a 400-MW instant load reduction in the Electric
Reliability Council of Texas.
Necessary steps to deal with the soaring demand include
interconnection reform, increased investment in transmission
and improved load forecasting.
Grid Strategies said the data in its report was compiled
from utility forecasts filed to the Federal Energy Regulatory
Commission.
PG&E Extends Contract With CEO Patti Poppe for Another Six Years
by Linda Dailey Paulson
Pacific Gas & Electric parent PG&E Corp. approved a con-
tract extension for CEO Patricia Poppe until Jan. 4, 2031.
A Dec. 2 8-K filing with the U.S. Securities and Exchange
Commission contains a letter from Kerry Cooper, chair of
PG&E Corp., stating that Poppe submitted an amendment to
her Nov. 13, 2020, offer letter, which the board approved.
“The original Offer Letter remains in full force and effect,
and Ms. Poppe’s compensation will continue to be subject to
an annual performance evaluation and market review, as well
as approval at least annually by the independent members of
the Board of Directors of PG&E Corporation,” the filing states.
In 2023, Poppe’s salary was $1.4 million along with a
“target value”—a salary-based short-term incentive award of
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
9An Independent News Service From NewsData • © Copyright NewsData LLC 2024
$2.03 million—plus another $10.75 million of compensation
issued as performance shares.
Also, two separate Dec. 2 filings with the SEC show Poppe
sold roughly $1.46 million in stock as of Dec. 2.
Poppe, who assumed her role in January 2021, followed a
series of four different CEOs in the previous five years in the
aftermath of the chaos of the 2018 Camp Fire and PG&E’s
earth-shaking 2019 bankruptcy. When she took over PG&E,
“I had one real objective, and that was to make it right, and
make it safe, and I had a lot to learn,” Poppe said at a 2024
industry conference (California Energy Markets No. 1785).
She came to PG&E after about four-and-a-half years at
Jackson, Michigan-based CMS Energy. In remarks during an
earnings call immediately after assuming the role, she said she
had visited Paradise, California, on her first day on the job
(California Energy Markets No. 1683).
At the market’s close Dec. 2, PG&E shares traded at
$20.53 per share. Trades ranged from $20.08 per share to
$20.86 per share that day. Over the past year, PG&E share
prices have ranged from $15.94 to $21.72.
PG&E Files Fire Report With CPUC, Makes $2.4B Stock Offering Public
by Linda Dailey Paulson
Pacific Gas & Electric filed a fire incident report with the
California Public Utilities Commission Nov. 25 indicating its
equipment sparked the Sites Fire in Colusa County in June;
days later, the utility’s stock value plunged after it made public
a $2.4 billion stock offering.
The preliminary filing was prompted by “a pending claim
of more than $50,000 for damage to fencing which made this
incident reportable,” PG&E said in the report.
The Sites Fire started near Lodoga Road and Wilson Creek,
southeast of Stonyford in Colusa County, according to the California
Department of Forestry and Fire Protection website. The fire con-
sumed 19,195 acres and no injuries or deaths were reported, accord-
ing to the last incident update on the Cal Fire website, posted June 24.
Cal Fire’s Sonoma-Lake-Napa Unit is the administrative
unit overseeing the incident. Other responders included the
federal Bureau of Land Management, the California Depart-
ment of Transportation, several Colusa County agencies, the
Maxwell Fire Protection District, the Williams Fire Authority,
PG&E, Yocha Dehe Fire Department and Marin County Fire.
Cal Fire told California Energy Markets the Sites Fire
remains under investigation and said that until it completes its
investigation, it cannot comment on it.
“PG&E is appreciative of the firefighters who battled the
Sites Fire in Colusa County,” PG&E spokesperson Matt Nau-
man said in an email to California Energy Markets. “A PG&E
outage occurred on our Elk Creek 1101 circuit at 1:26 p.m. on
Monday, June 17, 2024, in the general vicinity of the Sites Fire.
MODIS Land Rapid Response Team, NASA GSFC
Image of the Sites Fire captured by NASA’s Terra satellite, June 18, 2024.
“We have been in communication with CAL FIRE and the
CPUC since June and have been cooperating with their inves-
tigations ever since. On Nov. 25, 2024, PG&E filed an Electric
Incident Report (EIR) related to this fire,” he said.
The filing states that a utility troubleshooter “arrived at
the outage location and observed a tree with a green canopy
that broke approximately 10-12 feet above the ground and was
lying on a de-energized line.”
PG&E’s Nauman enumerated highlights of the utility’s 2023-
2025 wildfire mitigation plan, which he said “outlines critical
layers of wildfire protection that work together to reduce wild-
fire ignition risk and strengthen PG&E’s electric grid.”
Another fire erupted Dec. 2 in financial markets after
PG&E stated its intent to issue $2.4 billion in stock and made
additional announcements stating it would be raising divi-
dends by 150 percent—up from 1 cent per share quarterly to
2.5 cents per share—and also reaffirmed its earnings guidance
for the year. The announced offerings are for $1.2 billion of
common stock and $1.2 billion of preferred stock.
PG&E expects the net proceeds from the share sale to be
roughly $2.35 billion, but they could be as much as $2.7 billion
or more should the underwriters exercise their options to pur-
chase additional shares.
The funds will be used, according to PG&E, “for general
corporate purposes, which may include, among other things,
to fund PG&E’s five-year capital investment plan.”
PG&E reaffirmed its earnings in a Nov. 29 8-K filing with
the U.S. Securities and Exchange Commission. The 2024 non-
GAAP earnings per share range is between $1.34 and $1.37.
PG&E said corporate management “anticipates recommending
consistent dividend increases targeting a dividend payout ratio
of approximately 20% of non-GAAP core earnings per share
by 2028.”
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
10An Independent News Service From NewsData • © Copyright NewsData LLC 2024
parties can review that data just as they do now,” O’Connor
said, adding that formula rates will better align with other eco-
nomic factors and fluctuations than current rates because they
are adjusted annually.
Ratepayer advocates and others at the meeting said they
also felt the change is worthy of a rulemaking and that formula
rates, when adopted in other states, tend to benefit utilities
and shareholders at the expense of consumers. Several also
raised concerns that the option would obscure the impact of
other ratemaking changes the ACC has made recently, such
as offering a system reliability benefit that allows utilities to
recover costs between rate cases for certain utility investments
(California Energy Markets No. 1784).
Sarah Barrios Cool of Arizona’s Residential Utility Con-
sumer Office said there are other ways to improve regulatory
lag issues at the commission, including the SRB, and agreed
with other commenters that the commission should allow
more time to observe the impact of that change before making
others. There’s a risk of “too much medicine,” she said.
The prospect of annual true-ups, which would be part of any
formula-based rate plan put forward, also presents an increased
workload for ACC’s legal and utility division staff, Tovar said.
The option under the policy statement is available to all utilities
regulated by the ACC, whether they provide electricity, natural
gas or water service. Annual true-ups and audits could have a
tremendous impact on staff workload, and both divisions are
already at capacity, Tovar said. Myers, however, countered that
formula rate plans would make for easier and less frequent rate
cases because the annual true-ups would reduce the accumula-
tion of data between rate cases while improving the availability
of cost-of-service information for ratepayers.
Formula rate plans under the policy will continue to be
based on a historic test year, and the annual true-up process
gives stakeholders an opportunity to question utilities about
their spending at or around the time of that spending rather
than having to wait for the next rate case, Myers said. Utilities
SOUTHWEST
ACC
Continued from Page 1
The filing also contains a letter from Kerry Cooper, chair
of the PG&E Corp. board of directors, approving the contract
extension of CEO Patricia Poppe until Jan. 4, 2031 (see related
story).
The CPUC has voted on at least four PG&E rate increases
this calendar year. A general rate case increase of almost
11 percent took effect Jan. 1 [D23-11-069] (California Energy
Markets No. 1770). In addition, the CPUC approved two
interim rate increases related to wildfire mitigation earlier
this year: one for $1.1 billion, which is 85 percent of the total
requested amount [A22-12-009, D23-06-004], and a second
for $516 million, which is 75 percent of the total requested
amount [A23-06-008, D24-03-006] (California Energy Mar-
kets No. 1811). Then, on Sept. 12, it approved a decision for
$943.9 million plus interest, predominantly for wildfire mit-
igation in 2022 and 2023 [A 23-12-001]. It still has proposed
decisions on the table, including rate recovery for the Diablo
Canyon nuclear power plant.
PG&E share prices tumbled by 6.7 percent Dec. 2, which
Seeking Alpha said made PG&E “Monday’s biggest decliner on
the S&P 500.”
At the market’s close Dec. 2, PG&E shares last traded at
$20.53 per share. Trades ranged from $20.08 per share to
$20.86 per share that day. Over the past year, PG&E share
prices have ranged from $15.94 to $21.72.
Nick Myers and Chair Jim O’Connor, was approved on a 3-2
vote, with ACC member Lea Márquez Peterson joining the
commission’s lone Democrat, Anna Tovar, in opposition.
Márquez Peterson and Tovar both said they felt a formal
rulemaking rather than a policy statement was the preferable
route to such a change. The policy’s proponents say formal rules
can come later and will be stronger after utilities and the com-
mission have experience working within the new structure.
O’Connor, before opening discussion on the topic, said he
hopes to correct a “gross misperception or misunderstanding
of what formula-based rates are and how they would be uti-
lized.” Formula-based rates use a cost-of service model based
on a return on equity set through a rate case, “just like we do
now,” he said, adding that the new approach would provide
equal or improved protections for ratepayers because he and
Myers kept current customer protections in place in the policy
statement [AU-00000A-23-0012].
Under the new policy, utilities that choose to pursue for-
mula rate plans must submit all of their financial data to the
commission for review and approval each year. “All interested
Mary Fairchild/Flickr
Cacti with Piestew Peak in the background in Arizona.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
11An Independent News Service From NewsData • © Copyright NewsData LLC 2024
ACC’s Anna Tovar Says Ethics Investigation Is Politically Motivated
by Abigail Sawyer
An Arizona Corporation Commission member says she is
the subject of a politically motivated “witch hunt and a sham
investigation” into her conduct for possible ethics and statu-
tory violations.
Arizona Corporation Commis-
sioner Anna Tovar.
The ACC during a hastily called staff meeting Nov. 22
voted 4-0 to investigate fellow commission member Anna
Tovar for comments she made in a letter posted on the ACC
website regarding the commission’s decision to award a
$20,000 bonus to its executive director, Doug Clark (California
Energy Markets No. 1823).
Tom Van Flein, the ACC’s current Legal Division director, at the
conclusion of that meeting said he would carry out the investigation
into Tovar’s conduct within 10 days and
make a recommendation to the com-
mission. Tovar is the only Democrat on
the five-member commission.
The ACC on Nov. 6 had held a
closed session in which it performed
a performance evaluation on Clark
and then awarded him the bonus.
Tovar dissented and wrote about her
decision in a letter she made public.
Other commission members allege
she violated confidentiality rules
with the letter, prompting the move to investigate her.
“To my knowledge, the Commission has never performed a
performance evaluation for the position of executive director pre-
viously,” Tovar said in the letter, posted to the news section of her
page on the ACC website. She added that there were no objective
metrics or criteria used to evaluate Clark’s performance and said
that the evaluation was “very subjective in nature.”
Tovar in the letter acknowledged that the job of executive
director is challenging. She also called attention to issues that
have plagued the commission since Clark took the job in April
2023. These include staff turnover and retention challenges in
the commission’s legal and utilities divisions, which have been
at the center of other turmoil at the ACC.
The commission has faced controversy regarding the
removal of Elijah Abinah, former head of the ACC’s Utilities
Division. The agency is being sued by former Legal Division
Director Robin Mitchell, who alleges discrimination and a
violation of the Equal Pay Act in a complaint that names Clark,
another ACC staff member, and three commissioners as defen-
dants (California Energy Markets No. 1810).
“I would simply state that nothing has improved during
Mr. Clark’s time at the helm as executive director of the Com-
mission,” Tovar said in the letter. “In fact, I would say things
have remained the same if not become worse.”
The issue of bonuses has not come up for any other staff
member since Tovar joined the commission in 2020, she said
during a phone interview with California Energy Markets.
ACC Chair Jim O’Connor during the Nov. 22 meeting said
it was “with a deeply troubled heart” that he moved to autho-
rize Van Flein to investigate Tovar’s conduct.
“I think when our employees are publicly attacked without
them being afforded due process, it’s not something we should
would also have greater flexibility in changing course on
approved projects if more affordable alternatives emerge.
Cost and tax savings would be implemented more quickly
and reflected in rates sooner, further reducing costs for rate-
payers, Myers said. Formula rates would also promote rate
gradualism, which customers prefer over a big increase every
three to five years, he said.
The policy does not change existing rules at the ACC, nor
does it reduce regulatory scrutiny of utility spending, Myers
said. “All of the expenses that they include must still pass the
prudency determination that we always apply. We’re simply
spreading all of that out and doing it yearly.”
Diane Brown, executive director of the Arizona Public
Interest Research Group, in a news release said the ACC’s
current ratemaking approach offers ample opportunities to
challenge utility expenditures and engage the public. She and
others worry that formula ratemaking would reduce utility
incentives to operate efficiently.
Brown said the policy statement makes claims that aren’t
backed up with evidence and fails to provide details on what
rate-related information will be routinely provided; how
oversight and stakeholder engagement will be improved; how
reducing regulatory burden won’t just shift the financial risk
from utilities and their shareholders to ratepayers; or how
administrative efficiency will be enhanced in a manner that
enables appropriate oversight.
Tovar explained her “no” vote by saying that the policy
statement was attempting to circumvent rulemaking. The
purpose of policy statements is to inform the public of how an
agency interprets an existing rule or statute, she said, adding
that she anticipates possible legal challenges.
Also at the meeting, the commission discussed the Federal
Energy Regulatory Commission’s recent revisions to its Order
No. 1920 and the adoption of Order No. 1920-A, which gives
states a greater voice in interstate transmission planning (Cali-
fornia Energy Markets No. 1823).
O’Connor said he placed the matter on the agenda in
response to the increased transmission buildout facing all
states and the potential for transmission costs decided by
FERC to be passed through to Arizona ratepayers. The com-
mission called on its executive director to oversee a process of
appointing staff or a consultant to monitor Order 1920-A-re-
lated filings at FERC that are relevant to Arizona.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
12An Independent News Service From NewsData • © Copyright NewsData LLC 2024
purchased-power pass-throughs for the publicly owned utility.
Funds from the base increase would be used to replace aging
infrastructure, adapt to an evolving power grid, and enhance
customer programs and services, while maintaining reliability
and safety, the utility said in the release.
“Our grid is undergoing a transformation in how energy
is generated and the ways our customers are using it,” Pratt
said in the release. “This proposal seeks to provide plans and
options that meet our customers’ needs while ensuring we
maintain the reliability and affordability that are critical to our
communities.”
The new rates, if approved by SRP’s board of directors,
would result in an average monthly bill increase of 3.5 percent,
or $5.64, for SRP residential customers using 1,117 kWh per
month, according to the utility. SRP’s solar customers, how-
ever, would see a nearly $8 monthly increase on their bills
under the proposed plan.
Monthly service charges for SRP residential customers
would remain at $20 for multifamily home dwellers, while
single-family home customers would see their service charges
jump significantly, from $20 to $30 each month. About 3 per-
cent of SRP residential customers who live in homes with “a
very large electric service entrance” would see their monthly
charges double from $20 to $40.
In addition to boosting revenues, the request includes new
time-of-use plans with super-off-peak discounts of more than
50 percent below base rates for electricity used between 8 a.m.
and 3 p.m. It also seeks to increase SRP’s limited-income Econ-
omy Price Plan bill credit to $25 a month and expand program
eligibility so more customers can participate in the plan.
SRP’s last rate increase was approved in 2019. The utility
will host open houses and meetings to solicit feedback and
engage ratepayers on the proposed changes. It anticipates a
final vote Feb. 27, with the new rates taking effect with the
November 2025 billing cycle.
SRP Seeks $168.8M Rate Hike to Upgrade, Replace Aging Infrastructure
by Abigail Sawyer
Arizona’s Salt River Project is seeking a 2.4-percent rate increase
for its electricity ratepayers to support power system upgrades.
“As a not-for-profit, community-based utility, we make
decisions based on what is best for our customers, not inves-
tors,” SRP General Manager and CEO Jim Pratt said in a news
release. “SRP management’s proposal reflects increases in the
company’s operational costs driven by needed improvements
to the electric grid to maintain reliability and meet our ambi-
tious sustainability and decarbonization goals, by rising labor
costs and by important customer service enhancements.”
The proposed changes reflect a $168.8 million base revenue
increase and an anticipated $67.7 million decrease in fuel and
Orsted/SRP
Arizona’s Salt River Project seeks a $168.8 million revenue increase to upgrade its
grid for the transition to more renewable resources and an evolution in how cus-
tomers use energy.
tolerate as leaders of this organization,” ACC member Kevin
Thompson said at the meeting before voting in favor of the
investigation. Thompson also said he had “experienced first-
hand how [the ACC’s] ethics code could be weaponized for
political purposes.”
Thompson was the subject of a citizen complaint filed by
Abhay Padgaonkar in February 2023 regarding his attendance
at a meeting of institutional utility investors. He referred to the
complaint in a response as “an unfortunate attempt to weapon-
ize the ACC’s Ethics Code.” The complaint was dismissed 3-0
in a public vote at a March 2023 staff meeting, with Thompson
recusing himself and Tovar abstaining on the basis of process.
Tovar in a separate letter dated Nov. 22 explained her
decision not to attend the last-minute meeting in which the
commission voted to investigate her. She alleged that the accu-
sations against her were being handled differently from other
complaints before the commission and said that protocol and
due process have not been followed in her case.
Details regarding both the Thompson and Tovar investiga-
tions that were discussed during confidential closed sessions
are not publicly available, but documents pertinent to both
investigations have been filed in the ACC’s generic investiga-
tions docket [AU-00000E-17-0079].
Tovar opted not to run for a second term on the ACC this
year but believes politics are behind the investigation into her
conduct. “It is well known in Arizona that I hope to run again,”
she told California Energy Markets during the phone inter-
view. Tovar will leave the commission Dec. 31 and plans to
wage a campaign for lieutenant governor in 2026. She believes
her Republican colleagues at the ACC hope to tarnish her
image ahead of that race.
Tovar denies the allegations and has hired an attorney to
defend her in the matter.
ACC spokesperson Nicole Garcia in a Dec. 4 email to Califor-
nia Energy Markets said the investigation into Tovar is ongoing.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
13An Independent News Service From NewsData • © Copyright NewsData LLC 2024
DOE Pushing Loans Out the Door
by Jim DiPeso
The Department of Energy is advancing loans and loan
guarantees for battery and electric vehicle manufacturing in
the Biden administration’s remaining weeks as congressional
Republicans and the incoming Trump administration eye
DOE’s loan program for cuts in the 119th Congress.
In the past two weeks, DOE has closed or made conditional
commitments for up to $14.4 billion in loans and guarantees,
including conditional commitments of up to $6.57 billion for
Irvine, California-based Rivian to build an EV plant in Geor-
gia and up to $7.54 billion for StarPlus Energy, a joint venture
between Stellantis and Samsung SDI, to develop a battery
production facility in Indiana.
On Dec. 3, DOE closed a $303.5 million loan guarantee for
New Jersey-based Eos Energy Enterprises to finance develop-
ment of a stationary-batteries plant in Pennsylvania.
As of last month, 212 loan applications were on file at DOE
seeking $324.3 billion for projects involving renewable energy,
virtual power plants, advanced nuclear, advanced vehicles
and components, transmission, energy storage, hydrogen,
advanced fossil fuels, carbon management, critical miner-
als and EV charging. Applications totaled 86 from the West,
Alaska and Hawaii, according to DOE figures.
DOE estimates its remaining loan authority totals
$397.2 billion.
Mary Anne Sullivan, a senior counsel with the Hogan
Lovells law firm’s energy practice, said in a Nov. 20 web post
that clean energy and advanced vehicles “are unlikely to be
priorities in the next few years,” but added that the Trump
administration might consider loans and guarantees for critical
minerals, transmission and carbon dioxide transport projects.
She added that “proponents likely will have to speak up
early, to guard against action in the Congress to simply elimi-
nate the program as just another part of the ‘Green New Deal’
that President-elect Trump campaigned against.”
FERC Approves Idaho Power 206 Proceeding
The Federal Energy Regulatory Commission on Dec. 5
opened a Section 206 proceeding to determine whether Idaho
Power’s market-based rate authority in the utility’s balancing
authority area is just and reasonable.
FERC acted following Idaho Power’s submission of a filing
on July 31 that reported new affiliation with 111.8 MW of
capacity in the balancing authority. The filing included a mar-
ket-power analysis reporting it passed the pivotal supplier screen
but failed the wholesale market share screen in three seasons.
In a notational order, FERC directed Idaho Power to file a
mitigation proposal eliminating its ability to exercise market
POTOMAC power in its balancing authority area, agreeing to adopt FERC’s
cost-based rates or proposing other cost-based rates.
FERC Opens Basin Electric Section 206 Proceeding
The Federal Energy Regulatory Commission on Dec. 2
accepted Basin Electric Power Cooperative’s 2025 Rate Sched-
ule A, set to take effect Jan. 1, but also opened a Section 206
proceeding to determine whether the schedule is just and
reasonable and whether a reduction in the generation and
transmission co-op’s rates is warranted.
In a notational order, FERC said the co-op has proposed an
overall rate increase, but that a decrease might be warranted.
Basin proposed increases in its base energy and contract
rate of delivery rates; an increase in the noncontrolled electri-
cal/dual-space heat rate from 3.4 to 3.7 cents/kWh; a higher
member-standby rate; and a boost in the behind-the-me-
ter transmission charge from $5.31 to $5.46 per kilowatt of
behind-the-meter generation discharge.
Motions to intervene and protests were filed by fellow
wholesale co-op Tri-State Generation and Transmission Asso-
ciation of Colorado, Sierra Club, and a group of three co-ops in
North Dakota and Minnesota. Basin, which is headquartered in
Bismarck, North Dakota, serves 140 retail co-ops in nine states,
including Montana, Wyoming, Colorado and New Mexico.
According to the FERC order, Tri-State argued that Basin
failed to show that the proposed Rate Schedule A is just and
reasonable, noting that it “continues to feature rolled-in, social-
ized transmission costs for third-party transmission services
procured by Basin that members whose contracts extend to
2050 … subsidize, but are precluded from using.”
The Sierra Club argued that the 2025 rates include costs of
installing selective catalytic reduction technology and bottom-ash
handling equipment at two coal-fired plants—the 1,700-MW
Laramie River plant in Wyoming and the 660-MW Leland Olds
facility in North Dakota—that a FERC administrative law judge’s
initial decision found imprudent, according to the order.
Defending the schedule, Basin has argued that its board
approved it on Sept. 10 based on forecast load and energy
requirements for 2025 and forecast revenue for next year. Basin
also noted that the judge’s initial decision has not been finalized.
FERC Grants SDG&E Refund Petition
The Federal Energy Regulatory Commission on Dec. 5
granted a petition confirming that San Diego Gas & Electric
must issue refunds in connection with the 2019 fifth transmis-
sion order formula rate case settlement.
In a notational order, FERC ruled that because California’s
three investor-owned utilities are required to participate in the
California Independent System Operator under state law, they
are not eligible for a regional transmission organization adder.
The commission, however, did not order SDG&E to issue
refunds, noting that “under our rules of practice and procedure,
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
14An Independent News Service From NewsData • © Copyright NewsData LLC 2024
a declaratory order is not a proper vehicle to compel an entity
to issue refunds.” Commissioners said the petitioners can file a
complaint alleging failure to comply with the 2019 settlement.
FERC granted a petition filed by the California Public
Utilities Commission, the California Department of Water
Resources, the Northern California Power Agency, and the
cities of Azusa, Banning, Colton, Pasadena and Riverside.
Under the 2019 FERC-approved settlement, SDG&E
agreed to refund a 50-basis-point adder if the commission
issued a finding that California’s investor-owned utilities are
not eligible for the adder in CAISO.
The petitioners argued that SDG&E is overcollecting $18
million to $21 million per year from the RTO adder. They also
pointed to FERC’s 2023 order that found Pacific Gas & Electric
is no longer eligible for the adder, because IOUs’ participation
in CAISO is not voluntary under terms of California Assembly
Bill 209, which took effect in 2022 and reaffirmed existing stat-
utory requirements that CAISO participation is mandatory.
FERC rejected SDG&E’s argument that the petition is
premature because the PG&E order is under review in the U.S.
Court of Appeals for the 9th Circuit. In addition, FERC said
AB 209’s requirements are clear. “Accordingly, because their
participation in CAISO is mandatory, the California IOUs are
not eligible for the RTO adder,” FERC said in the order.
FERC also dismissed SDG&E’s argument that it would be
unfair to require funds for the period before enactment of AB
209. “The refund effective date that SDG&E agreed to in the adder
refund provision is unambiguous: June 1, 2019,” FERC ruled.
FERC Finalizes Certification Rule
The Federal Energy Regulatory Commission on Dec. 5
finalized a rule clarifying application of Clean Water Act certi-
fication requirements for FERC proceedings.
The rule clarifies that all commission authorizations of proj-
ects with potential to discharge into “waters of the U.S.” must have
water-quality certifications from states or tribes under the Clean
Mike Liu/Flickr
Transmission lines near San Diego.
Water Act’s Section 401. FERC said previous regulations were silent
on whether authorizations for some hydro projects that might trigger
Section 401 requirements—including license amendments, surren-
ders or applications for license exemptions—must have certifications.
The rule also clarifies that certifying authorities have one
year to act on certification requests.
Power Groups Urge Transformer Funding
Energy and manufacturing groups on Nov. 27 urged
congressional appropriators to support funding for domestic
transformer manufacturing.
In a letter to chairs and ranking minority members of
appropriations committees, the groups said they support inclu-
sion of $600 million to support transformer manufacturing in
Senate appropriations legislation.
The letter quotes National Renewable Energy Laboratory
estimates that distribution transformer demand will increase
as much as 260 percent in coming decades. The groups warned
that production lead times for some classes of distribution
transformers exceed 30 months.
“Compounding this problem are significant rises in energy
demand—driven by data centers, AI and quantum computing, elec-
tric vehicles and the increasing electrification of our economy. Amer-
ica quickly needs greater domestic output of critical grid components
to both fix the grid and prepare it for the future,” the letter says.
Signatories include the American Public Power Associa-
tion, GridWise Alliance, National Electrical Manufacturers
Association, National Rural Electric Cooperative Association,
Transformer Manufacturing Association of America and Lead-
ing Builders of America, a homebuilders group.
Colorado River Salinity-Control Bill Passes
The House of Representatives on Dec. 3 passed a bill to boost
the federal cost share of Colorado River salinity-control programs.
The bill, HR 7872, sponsored by Rep. John Curtis (R-Utah),
would cut the reimbursable portion of salinity-control project
costs paid from hydropower revenues. In House testimony
May 22, the Colorado River Basin Salinity Control Forum said
drought has reduced lower-basin power generation, lowering
revenues needed to meet the reimbursable requirement.
PV Anti-Dumping Tariffs Get Preliminary Nod
The Department of Commerce on Nov. 29 announced a pre-
liminary finding that companies in four Southeast Asian countries
have been selling photovoltaic cells in the U.S. below cost.
Meanwhile, China on Dec. 3 announced a ban on exports
to the U.S. of germanium, gallium and antimony. Germanium
and gallium are used in production of solar cells and semi-
conductors, and China is the world’s dominant producer of
germanium and gallium.
The dumping finding by Commerce’s International
Trade Administration, if finalized next year, would result in
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
15An Independent News Service From NewsData • © Copyright NewsData LLC 2024
anti-dumping duties imposed on PV exporters from Cambo-
dia, Malaysia, Thailand and Vietnam. Between 2021 and 2023,
PV imports from the four countries soared from $4.3 billion to
$11.9 billion, according to Commerce figures.
The finding was made in a case brought by the American
Alliance for Solar Manufacturing Trade Committee, made up
of Arizona-based First Solar, Hanwha Q CELLS USA of Geor-
gia and Mission Solar Energy of Texas.
Commerce is due to make a final finding by April 18,
followed by a final determination of the International Trade
Commission on June 2 and issuance of tariff orders June 9.
Supreme Court Weighs Utah Lands Suit
The Supreme Court is weighing whether to hear the State
of Utah’s legal complaint challenging federal ownership of 18.5
million acres that the state argues is “unappropriated” and
consequently is “unconstitutional.”
The Biden administration on Nov. 21 filed a brief with the
high court urging justices to reject hearing the state’s com-
plaint, arguing that “it plainly lacks merit.”
In an Aug. 20 complaint filed with the high court, the state said
the U.S. Constitution does not authorize the federal government
“to hold vast, unreserved swaths of Utah’s territory in perpetuity,
over Utah’s express objection, without even so much as a pretense of
using those lands in the service of any enumerated power.”
The state’s complaint said the federal government is hold-
ing the acreage “for its own exploitation” to collect “significant
revenue” from the Bureau of Land Management’s leasing of
the acreage for oil and natural gas production and for grazing,
selling timber and other commodities, and permitting com-
mercial filmmaking.
The state said it is “deprived of significant revenue” from min-
eral development and other activities on the acreage in dispute.
In a response for the Justice Department, Solicitor Gen-
eral Elizabeth Prelogar said the state’s complaint is untimely,
arguing that it brought the suit “176 years after the United
States acquired the lands at issue, 128 years after Utah joined
the union and 48 years after Congress adopted the statutory
provisions that Utah challenges.”
Prelogar added that “until recently, Utah acquiesced in
federal possession of the lands; indeed, its state constitution
disclaims any interest in the lands, and in the early 20th century,
its governor rejected an offer to cede the lands to the state.”
Utah took its case directly to the high court, arguing that justices
hold original jurisdiction over cases in which a state is a party.
The Justice Department argued that Utah’s complaint doesn’t meet
the high court’s criteria for hearing original-jurisdiction cases.
Among the friend-of-the-court briefs supporting Utah’s case are
filings by Utah’s congressional delegation and 12 states—including
Idaho, Alaska and Wyoming—as well as the Arizona Legislature.
The Ute Indian Tribe of the Uintah and Ouray Reservation
is seeking to intervene in opposition to Utah. In its brief, the
tribe said Utah is seeking to force the federal government to
give up public lands and tribal trust lands in the state.
Reclamation Funds Western Water Projects
The Bureau of Reclamation on Dec. 3 rolled out $849 million
in funds to upgrade 77 aging water projects in Western states.
The Department of the Interior said the upgrades would
improve storage and hydropower generation, increase safety
and provide water treatment.
Projects are in Arizona, California, Colorado, Idaho, Mon-
tana, New Mexico, North Dakota, Oregon, South Dakota, Utah
and Washington, and include equipment upgrades at the Glen
Canyon, Shasta, Folsom, Friant, Stampede, New Melones, Blue
Mesa and Elephant Butte power plants.
Funding will come from the 2021 Infrastructure Invest-
ment and Jobs Act.
Gas Inventories at Eight-Year High
Natural gas in storage in the lower 48 states totaled 3,922
Bcf—the highest level at the start of winter since 2016, the
Energy Information Administration reported Dec. 2.
The EIA said inventories are 6 percent higher than the
2019-2023 five-year average. Net injections into storage during
the April-October injection season totaled 1,640 Bcf, which
the EIA attributed to high inventories at the end of March and
reduced production linked to lower prices.
Tariffs Worry Petroleum Trade Group
An oil and petrochemicals trade group on Nov. 27 called for
exempting crude oil and refined petroleum products from the
25-percent tariff on Canadian and Mexican imports that Presi-
dent-elect Donald Trump has vowed to impose after taking office.
The American Fuel & Petrochemical Manufacturers group
said higher costs for crude oil would translate into higher fuel
prices in the U.S.
President Joe Biden on Nov. 29 said the proposed tariffs
would be “counterproductive.”
Bob Wick, Bureau of Land Management/Flickr
BLM lands in Utah.
CALIFORNIA ENERGY MARKETS • Dec. 10, 2024 • No. 1825
16An Independent News Service From NewsData • © Copyright NewsData LLC 2024
AFPM said U.S. refineries built before the growth of
shale-oil production depend on heavy grades of Canadian oil
because they are not engineered for light, low-sulfur crude oil
produced domestically.
The group also said some U.S. regions, including Califor-
nia, don’t have enough pipeline capacity to rely solely on U.S.
oil and refined petroleum products.
As of September, the U.S. imported nearly 8.2 million
barrels of petroleum and refined products per day, of which
56 percent came from Canada and 8 percent from Mexico,
according to Energy Information Administration figures.
DOE Opens AI Interconnection Fund Applications
The Department of Energy on Nov. 26 said applications are
open for up to $30 million in funds to accelerate grid intercon-
nections through artificial intelligence.
Energy Secretary Jennifer Granholm said AI could help
reduce the interconnection backlog. Nearly 12,000 projects
totaling 1,570 GW of generating capacity and 1,030 GW of
storage are in interconnection queues, according to a Lawrence
Berkeley National Laboratory report released in April.
Funded projects would use AI algorithms to speed up
identification of deficient interconnection applications and
flag problems for applicants to resolve, DOE said, noting that
interconnection applications often are reviewed manually.
The application deadline is Jan. 10. Funding will come from
the 2021 Infrastructure Investment and Jobs Act.
EPA Reports Record-Low Tailpipe GHG Emissions
Model year 2023 fuel economy reached a record high while
tailpipe greenhouse gas emissions fell to a record low, the Envi-
ronmental Protection Agency reported Nov. 25.
For model year 2023 vehicles, fuel economy reached a
record of 27.1 miles per gallon and “real-world CO2 emis-
sions” fell to a record low of 319 grams per mile, EPA said,
adding that since model year 2004, tailpipe CO2 emissions
have fallen 31 percent and fuel economy has increased
40 percent.
Battery-electric and plug-in hybrid vehicles are accelerating
the downward trend, cutting emissions by 38 grams per mile
and improving fuel economy by 2.2 mpg in model year 2023,
EPA said.
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