California Energy Regulation News April 2024
Interconnection Milestones, Energy Storage vs. Inflation, Fetishistic Reliance on Models
I’m trying something new for a bit. Once a month, I’ll post a California energy regulatory update in long form. This is a different cadence than the once-a-week posting I’ve been doing the past few months because that schedule has promoted sloppiness and snark, and I want to steer clear of that. I’ll still post the occasional standalone piece if something warrants that, and I’ll leave the heavy lifting on most Bitcoin/energy topics to
While I hold firm in my belief that the so-called energy transition as it’s being implemented in California (and elsewhere) is unworkable, wrong, and fraught with bad actors, I think there’s value in dispassionately chronicling its development. My preference is to leave the more intense criticism to the many notable bloggers and firebrand social-media personalities who are doing it quite well and in ever-increasing numbers. I’m mostly interested in semi-neutrally documenting the state’s embrace of clean-energy cronyism because posterity is good, and because lessons can be extracted from reckless experimentation that occurs at-scale.
Plus, dominant monocultures create fertile ground for subcultures to emerge, and in that light maybe we can map “hell” to regain heaven. Also: not all of California’s energy ideas are bad or wrong. There’s innovation happening in spades, albeit often in service to bad ideas, but there’s innovation nonetheless, and it merits attention.
So my method of “conflict” here is more iron-fist-in-velvet-glove than brickbat, I suppose. That’s one lesson learned from doing this blog for two years.
INTEGRATED RESOURCE PLANNING
‘All models are wrong, but we are fetishistically reliant on them anyway’
— ancient California proverb
In February the California Public Utilities Commission authorized a “Preferred System Plan” in its Integrated Resource Planning docket1 whose goal is to reduce greenhouse gas emissions by 25 million metric tons in the electricity sector by 2035. These plans are routinely refreshed by the Commission.
The table below breaks down the resources that would need to be built by 2035 to realize the plan’s goals; this includes 19.0 gigawatts of solar and 15.7 GW of four-hour lithium-ion battery storage.
The Commission originally developed its figures by aggregating individual load-serving entities’ procurement submissions and reflecting those entities’ resource preferences through 2035. The Commission then applied modeling analyses to anticipate whether reliability and GHG reduction targets could both be met.
Additionally, the CPUC’s decision formally adopted aspects of an IRP reliability framework that had been used the past two years. This framework includes:
A 0.1 “Loss of Load Expectation” standard for determining reliability needs. LOLE refers to the projected number of hours (or days) per year when electricity production capacity falls short of meeting demand. An LOLE standard of 0.1 signifies an expected loss of load — involving only a fractional loss of load — for 0.1 days per year.
A planning reserve margin based on gross peak. A planning reserve margin represents the difference between the expected maximum available supply (capacity) and the expected peak demand, which is usually expressed as a percentage.
Resource counting conventions that utilize marginal “Effective Load Carrying Capability” analyses and receive frequent updates. Marginal ELCC measures the specific contribution of a resource in terms of additional load it can support compared to a base case (or compared to a scenario without the resource).
The decision also recommends that the California Independent System Operator determine how much transmission buildout will be necessary if 15 GW of natural gas generation resources are retired by 2039.
The CAISO, incidentally, just published its proposed 2023-2024 Transmission Plan, which comes with a $6.1 billion price tag. The plan, which relies on information from the CPUC’s Integrated Resource Planning docket, includes 26 proposed transmission projects, whose planning zones are indicated in the graphic below.
ENERGY STORAGE
A recurring and perhaps worrisome phenomenon happening in California right now is that utilities are frequently submitting amendments to energy storage contracts because of impacts related to supply chain crises, inflation, and increases in battery prices. Many of these projects are becoming uneconomical without price increases, and there is a non-zero risk that some of these projects could become stranded assets.
The most recent example is an agreement that PG&E entered into with Kola Energy Storage, which required updating because Kola was facing Participating Transmission Owner2 delays associated with the completion of network upgrades outlined in its interconnection agreement. Kola indicated that increases in battery prices, continuing supply chain constraints, and the effect of inflation on labor costs all factored in to the contract update, which the CPUC authorized.
INTERCONNECTION UPGRADES
The CPUC is taking multiple steps to enhance interconnection processes as the state speeds toward its desired grid anatomy. The agency greenlit 18 more months of a utility pilot program that allows for the streamlined connection to the grid of non-exporting energy storage projects under 30 kilovolt-amps.
The Commission also enacted a “major milestone” involving an interconnection option called the “Limited Generation Profile,” whose function is to maximize the use of existing hosting capacity on the grid while allowing projects to avoid distribution system upgrades. In theory, this should enable more Distributed Energy Resources (a.k.a. DERs) to connect to the grid at a lower cost than usual.
PV Magazine says California is the first state to offer this option. The concept covers projects where developers choose to define operating schedules that align with Hosting Capacity Analysis (also known as “HCA”), which analyzes conditions on a distribution grid and provides answers as to whether it can host additional DERs. For example: if a Hosting Capacity Analysis says the minimum hosting capacity at a select line segment at 9 a.m. in April is 160 kW, then a Distributed Energy Resource connecting at that node cannot export more than 160 kW at that particular time.
More info is available at Power Grid International, and Canary Media’s explanatory piece is also helpful.
INCOME-GRADUATED FIXED CHARGE
On May 9, California ratepayers may find out whether they’ll be subject to a new rate-design scheme that arose out of the controversial “income-graduated fixed charge” quagmire, where more affluent utility customers would take on a greater role in subsidizing the grid. The CPUC circulated a new draft decision on this matter, and for now at least, it steers clear of any income-based ratemaking formulas.
The draft decision authorizes utilities to institute a pricing floor of $24.15 per month on most residential customers’ bills to accompany a customer’s usage rate. The CPUC claims this change will reduce electricity for all customers by approximately 5 to 7 cents per kilowatt hour.
California economist Ahmad Faruqi, who has written extensively about changes to the state’s rooftop solar policies, urges the CPUC to reject the draft decision. He provides 10 reasons, including an argument that going from a $0 price floor to $24.15 is a gross violation of gradualism, and that, if the state wants to pursue mass electrification, which it does, then the biggest barrier to doing so is high electric rates, which, year after year, outpace the rate of inflation.
Regarding the prospect of an income-graduated fixed charge, which may ultimately be reconsidered by the legislature3, the Mises Institute weighs in with the following commentary:
Too many conditions must be satisfied: revenue neutrality, protecting customer privacy when determining their income levels, energy usage rates low enough to protect low-income customers, usage rates high enough to encourage energy conservation and future installation of rooftop solar, sufficient revenue to invest in infrastructure for wildfire prevention, and additional grid capacity to support electric vehicle recharging stations and home heat pumps.
It is possible to solve such problems using linear programming, maximizing a linear function subject to the various constraints. But it is unlikely that California Public Utilities Commission staff could grapple with such a solution in time to approve income-based electric utility two-part tariffs in time for July 2024 implementation.
But I would posit that no amount of clever rate design can offset the most vexing issue at hand: California wants things that are unrealistic and too expensive in the near-term e.g., an all-renewables grid. And this costly problem is exacerbated by the state’s refusal/inability to manage forest undergrowth, which contributes greatly to the wildfires that cause utilities to initiate expensive grid-hardening campaigns. (Wildfires, by the way, are the second highest source of state carbon emissions, behind transportation.)
For those curious to learn more about the fixed-charge draft decision (also called a proposed decision, or “PD”), I direct you to this E3 blog post, which contains a fact sheet on the CPUC’s draft decision and provides readers with the Fixed Charge Design tool, which informed the PD.
PG&E RATES
In early March, the CPUC OK’ed another rate increase for PG&E. A decision authorizing $516 million in “interim” relief (i.e., 75% of what PG&E requested) carried unanimously on March 6. Notably, the Commission said that the move was necessary to “stabilize” PG&E’s “still precarious financial position,” which is unlikely to endear the Commission to critics who accuse the organization of being in bed with the investor-owned utilities, and specifically PG&E, vis-a-vis Gavin Newsom.
Additionally a new PG&E proposal surfaced in March where the company is requesting $131.4 million in capital and $11.9 million in expenses associated with advanced metering infrastructure on the gas side of the company’s operations.
Still another PG&E proposal — one that would spin off the company’s non-nuclear generation assets to a subsidiary called “Pacific Generation” (thereby facilitating the sale of Pacific Generation equity assets to third-party investors) — is tentatively scheduled for consideration on April 18. The CPUC’s current inclination is to say “no” to this proposal, with the rationale being that it’s not in the public interest and because its costs may lead to still more rate increases.
According to Platts:
FERC authorized the spinoff in 2023, but PG&E faced resistance from consumer and environmental advocacy groups concerned about whether a proposed 49.9% minority stake sale of the new entity was in the public interest. The portfolio would include 3,848 MW of hydroelectric resources, 1,400 MW of natural gas-fired capacity, 152 MW of solar and 182 MW of battery energy storage. Among the largest assets, according to S&P Global Market Intelligence data, are the 1,212-MW Helms Pumped Storage facility in Fresno County, Calif.; the 668-MW gas-fired Maxwell Generating Station in Colusa County, Calif.; and the 586-MW gas-fired Gateway Generating Station in Contra Costa County, Calif.
Incidentally, the Helms Pumped Storage Facility, mentioned in the blurb above, is the subject of yet another new proposal of PG&E, which entails increasing the nameplate generating capacity of the facility to provide 150 to 180 incremental megawatts of long-duration storage. All of this would come online sometime between 2029 and 2031. PG&E is seeking authorization to recover actual costs of this work up to a forecasted amount of $462 million.
NATURAL GAS PRICES, HYDRO GENERATION, etc.
December natural gas prices in Southern California were the lowest since 2016, according to the EIA. The main drivers were a mild winter, more natural gas available in storage, and increased hydro generation. All these moving parts should further highlight that a confluence of factors affect natural gas prices in California, so when they eventually rise to exorbitant levels once again, we can be sure that certain scheming nihilists will leverage the situation for political gain and/or performance art.
The EIA also noted that — despite record winter precipitation in California — hydro generation across the west fell to a 22-year low in the 2022/2023 water year, mostly because of droughts in Oregon and Washington. Per RTO Insider:
California weather in 2022/23 was dramatically different than in the Northwest. A series of atmospheric river storms dropped record rain and snow on the state from December 2022 to March 2023.
The wild winter left California with its largest snowpack since records began in the mid-1980s. Drought-depleted reservoirs were replenished, and hydropower generation for 2022/23 reached 30.0 million MWh, nearly twice that of the previous year.
The 11 states in the Western region produced about 60% of the nation’s hydropower last year, roughly the same as in the 2021/22 water year.
Washington, Oregon and California produced the most hydropower in the region; Washington and Oregon combined contributed 37% of the U.S. total. The other Western states are Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah and Wyoming.
COMMUNITY CHOICE AGGREGATION
For the past several years, Community Choice Aggregators, a.k.a. CCAs, have distinguished themselves as burgeoning entities in the California energy marketplace. They are often held up as a more “righteous” alternative to investor-owned utilities, but they are increasingly coming under fire from voices in the energy pragmatism sphere.
In a February 2023 piece, the Substack blog Green Leap Forward criticized the CCA business model here, and now a similar piece has surfaced at a blog called Tell Me How This Ends. The author (Chris Bray) argues that while CCAs claim to procure and manage energy supplies for communities, in the end, they don’t really do much at all:
…these very important new electric power utilities don’t generate electricity, don’t deliver electricity, don’t build, own, or maintain any portion of the power grid, don’t do any billing, and don’t do customer service. That’s why they have billions of dollars a year in annual revenue, you see.
Most disconcertingly, CCAs are not run by engineers or those with knowledge of managing electrical systems, but rather by activists and non-profit/NGO types.
Similar criticisms arose in Mason Willrich’s 2017 book Modernizing America’s Electric Grid. In the book, Willrich explains what CCAs are meant to do, in theory: under the CCA model, cities and counties have authority to “aggregate” the buying power of individual electricity customers in their specific jurisdictions and act as the retail energy function for consumers in those jurisdictions.
However, using the example of California’s first CCA (Marin Clean Energy), Willrich notes that, when that particular CCA came into existence, Marin residents were automatically made into Marin Clean Energy customers unless they opted out (see my accompanying footnote, por favor).4 Marin Clean Energy then engaged Shell Oil to buy power from the CAISO wholesale power market for delivery via PG&E’s system to Marin residents who did not opt out. The main impetus for Marin Clean Energy customers to choose MCE over PG&E was “to reduce their overall carbon footprint in using power from renewable resources, which did not emit carbon.”
But…the renewables content provided by Shell consisted mainly of Renewable Energy Credit (REC) purchases, which did not add any renewable generation within California or elsewhere in the Western United States. Shell’s REC transactions simply reshuffled the sources within the CAISO’s wholesale market, with no overall reduction in overall carbon emissions.
“The takeaway from this discussion of CCAs,” he wrote, “is that before consumers decide not to opt out, they should make sure that the green sources advertised take the form of hardware in the ground and not RECs pulled from cyberspace.”
Thanks for reading. For non-energy takes that exist on the quasi-schizoid side of life, please visit my other blog.
The IRP is an umbrella proceeding centered on the CPUC’s electric procurement policies. The proceeding collects and analyzes individual electricity providers’ plans to inform a statewide “preferred system plan portfolio.”
A Participating Transmission Owner is an entity that has authority to participate in the transmission system. PTOs can make economic decisions regarding out-of-state generation and transmission. This model, known as the Subscriber Participating Transmission Owner model, allows off-takers or load serving entities in California to make their own choices regarding transmission-related matters. To become a PTO, entities must follow the application process outlined in the Transmission Control Agreement.
As Cal Matters notes here, the possibility of the income-based fixed charge emerged from a trailer bill to the state budget, which was supported, for example, by Democratic Assemblywoman Jacqui Irwin of Thousand Oaks, who’s now spearheading the legislative effort to rethink the charge.