Texas Gov. Greg Abbott on Monday appointed Texas Water Development Board Chairman Peter Lake to head up the state’s Public Utility Commission.
Peter Lake | Texas Water Development Board
Lake has served on the water board, which provides planning for the state’s water resources and wastewater services, since December 2015 and was appointed chair by Abbott in 2018. He was formerly head of business development at Lake Ronel Oil Co. and previously served as director of special projects for the VantageCap Partners equity firm.
“I am confident [Lake] will bring a fresh perspective and trustworthy leadership to the PUC,” Abbott said in a statement. “Peter’s expertise in the Texas energy industry and business management will make him an asset to the agency.”
Lake’s appointment as PUC chair is subject to Senate confirmation and will expire Sept. 1, 2023.
Abbott made the announcement while Will McAdams, Abbott’s previous appointee to the PUC, testified before the Texas Senate Committee on Nominations. The committee approved his nomination, sending it on to the full Senate for confirmation. (See Abbott Taps ABC Texas President McAdams for PUC Seat.)
“I can sincerely say that I wish I were here under different circumstances,” McAdams told the committee.
Will McAdams introduced himself to the Texas Senate Committee on Nominations Monday. | Texas Senate
The PUC has come under heavy political fire in the aftermath of the February winter storm that nearly brought down the D’Andrea Resigns from Texas Commission.)
State Sens. Kelly Hancock (R) and Charles Schwertner (R) introduced McAdams to the nomination committee.
“I thought the appointment was a very wise appointment by the governor,” Hancock said, calling McAdams the “right man in the right place.”
“He does understand the issues the PUC is going to deal with. He knows the subject matter, and he has integrity,” Hancock said.
Schwertner, for whom McAdams served as legislative director, said, “It’s obviously a very important job, looking forward at what needs to be done in regulating the electric industry.”
ISO-NE will seek to extend its FERC Order 2222 compliance deadline until February 2022, the RTO’s Director of Demand Resource Strategy Henry Yoshimura told the NEPOOL Markets Committee.
Yoshimura said the original July 19 compliance deadline was “pretty intense,” though ISO-NE has “made very substantial progress in our compliance approach. But as we kept moving forward, it just seemed as though we need more time.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved remarks afterward to clarify their standing on the issues.]
Roadside solar panels in Vermont | Shutterstock
Yoshimura said that had the RTO kept moving toward the original compliance date, metering arrangements and tariff changes would be needed, in addition to coordinating the registration and operations of distributed energy resources with distribution utilities.
He said conversations with utilities “have been going fairly well, but there’s always room for more improvement there, so I think having more time will give us the ability to refine our approach to coordinating distributed energy resources registration and operations.”
Yoshimura added that FERC Order 2222-A might lead the RTO “to rethink some of our participation models as a result of not only that order, but the conversation leading up to that within the group stakeholder process, which has to do with how demand response might need to participate in a distributed energy resource aggregation.” (See FERC Limits State ‘Opt Out’ on DR.)
Changes to GIS, Operating Rules Adopted for Maine Thermal RECs
The MC adopted changes to the Generation Information System (GIS) and GIS Operating Rules to include the thermal renewable energy credits (RECs) requirement in Maine’s renewable portfolio standard.
Maine’s Public Utilities Commission requested the changes, and as “regulatory enhancements,” they can be adopted by the MC without additional corresponding action by the Participants Committee. The changes become effective on July 1 and apply to certificates created for energy generated on and after Jan. 1, according to a pre-vote memo from NEPOOL counsel Paul Belval of Day Pitney.
Thermal RECs will be awarded to facilities certified by the PUC to produce heat, steam, hot water or another form of thermal energy from sunlight, biomass, biogas or liquid biofuel or as a byproduct of electricity generated by Class I or Class IA resources under the RPS. To qualify for thermal RECs, a facility must have started operation after June 30, 2019, and the thermal energy must be delivered to an end-user in Maine and generated or delivered per the PUC’s energy efficiency standards.
Maine’s competitive electricity suppliers must also demonstrate that they have purchased a certain level of thermal RECs annually, starting at 0.4% in 2021 and ramping up to 4% in 2030 and beyond. The GIS and Operating Rules accommodations for Maine thermal RECs are similar to those made when New Hampshire and Massachusetts added thermal energy to their respective RPS provisions.
The GIS agreement, amended October 2020, provides that APX, the GIS Administrator, perform up to 500 hours of annual development work for enhancements each year without additional cost. APX estimates that the GIS changes for the Maine thermal RECs will require approximately 150 hours of development time. APX expects the other GIS changes targeted for July 1, including the addition of “clean existing generation” from the Massachusetts Clean Energy Standard, will require 260 hours to complete. This leaves 90 hours of development time remaining in 2021.
Other Action
The MC voted to recommend that the Participants Committee support ISO-NE’s proposal to revise Operating Procedure 9 to clarify the order of actions between coordinated transaction scheduling (CTS) and non-CTS transactions and the timing of when actions are taken on CTS transactions — either before or during operating reserve deficiencies and minimum generation emergencies.
The revisions are consistent with the net interchange that CTS software would produce if it could respond instantaneously and allow the RTO’s system operators to perform timely reductions on the CTS interface when transactions contribute to an emergency condition. These revisions will also provide a faster system response while considering the results of the day-ahead energy market. In addition, the ISO is proposing to add market notifications when CTS transactions are reduced for reserves, which will improve transparency.
PJM stakeholders questioned whether a proposal addressing compensation for reactive power supply and voltage control service should be delayed because of several other important issues on which members are working.
Jim Davis, regulatory and market policy strategic adviser for Dominion Energy, provided a second first read of a problem statement and issue charge first presented at the Market Implementation Committee meeting in March. (See “Reactive Supply Compensation,” PJM MIC Briefs: March 10, 2021.) Davis said the “great discussion” on the issue at the MIC allowed Dominion to make changes to the issue charge.
PJM transmission customers pay for reactive power as an ancillary service under Schedule 2 of the tariff, and generation owners must submit a filing to FERC under Federal Power Act Section 205 to seek compensation. The existing rate mechanism is time-consuming for generation owners, developers and transmission customers, Davis said, exposing them to litigation costs in the defense or challenge of the requested rates.
Dominion proposed several key work activities in the issue charge, including studying the existing rate filing process, reviewing the inputs for determining revenues and examining the recovery mechanisms in other RTOs and ISOs. It also calls for discussing improvements to the cost recovery process and examining alternative mechanisms.
Some stakeholders requested that the key work activities include education and discussion to “identify potential gaming risks” for reactive power, Davis said. Dominion also added language to the issue charge that if gaming risks are identified, stakeholders would develop “protective provisions” to be included in a cost recovery mechanism.
Davis said stakeholders also questioned the timing of the issue, so Dominion extended the time for completion from June to August.
“We recognize there’s a lot on stakeholders’ plates these days,” Davis said.
Paul Sotkiewicz of E-Cubed Policy Associates asked how a generator could game reactive power.
Davis said there’s a concern that if a generation owner doesn’t like a rate that FERC approved or that the proceedings weren’t going in its favor, it could then elect to use the existing stated rate. “We thought that was a valid concern.”
Sotkiewicz said he recognized the importance of addressing the issue, but he wondered if it was the right time to take on extra stakeholder discussions because of pending FERC decisions and the significant work being done on the capacity market.
Michael Cocco, senior director of RTO and regulatory affairs for Old Dominion Electric Cooperative (ODEC), said he thought the issue charge would require any proposed solutions to create obligations on both buyers and sellers. Cocco said he didn’t think the proposal would provide the option for sellers to submit a Section 205 filing with FERC, essentially creating a potential floor rate.
ODEC was also concerned the issue may not be broad enough because it exempts existing generators who have reactive power service rates already submitted with the commission, Cocco said, and that the issue charge “seems to be limiting” discussions.
“We would want more of a market solution that looks at need and competition for these services,” Cocco said.
Davis said the intent was not to “prescribe a solution” in the issue charge, but to establish key work activities to have a “meaningful discussion” by all stakeholders to examine how the process works.
“We may not come to a solution, or we may come to something that’s very similar to ISO-NE,” Davis said. “In the end, if we decide that the existing methodology is appropriate, then so be it.”
Independent Market Monitor Joe Bowring reviewed an alternate problem statement and issue charge addressing the issue. The proposal largely mirrored Dominion’s language with some proposed additions.
Bowring pointed out that customers pay $355 million per year in separate reactive capacity charges and, currently, the costs of reactive are only partially integrated into the capacity market. He said 100% of the capacity costs of generating units are included in the cost of new entry, offset by a defined amount of reactive revenues, which is less than the levels currently paid, and that there is no reason to have a separate payment outside the capacity market.
Bowring said the Monitor wanted to point out some of the problems seen with the current process, make it “more efficient and more effective” and include the potential to recover capital costs related to reactive power through a market mechanism. He said stakeholders are spending a great deal of time and effort at FERC in “endless settlement conferences” regarding reactive power.
“It would be great to streamline that process,” Bowring said.
Dominion’s issue charge was “relatively noncontroversial,” he said, but the Monitor’s version aims to add clarity and more education on topics, including the fundamentals of planning for reactive capability and the coordination of planning with the competitive PJM market design.
Sotkiewicz said he had some objections to the language in the Monitor’s proposal. He didn’t oppose the proposed education, but he said many of the proposed issues for clarification “aren’t going to be clarified.”
“I think this goes a step too far and gets into the capacity market,” Sotkiewicz said.
Bowring said he doesn’t know why there would be objections to clarification of the issue and believes it “won’t take very long” to get some clarity in the issue by raising questions.
Sharon Midgley of Exelon said she felt the Monitor’s issue charge is “very broad” and “very comprehensive” and would be more time consuming to address. Midgley said there are other strategic issues members are working on, including the minimum offer price rule and energy pricing, that will take up valuable discussion time in the stakeholder process.
Midgley asked if Bowring thinks reactive power is a “top five” issue that stakeholders should be addressing this year or if it could be held off on.
Bowring said the Monitor has contemplated bringing the issue forward before but has chosen not to because of more pressing issues.
“We’re OK with putting it off for a while,” Bowring said. “I don’t think it makes sense to put it off forever, but fitting it in an appropriate spot of priority is fine with us.”
The committee will vote on the proposals at its May meeting.
Fast-start Pricing Manual Revisions
PJM presented the committee with an update on proposed manual revisions stemming from a FERC order late last year on fast-start pricing.
FERC in December ordered PJM to make several changes to its tariff, including relaxing fast-start resources’ economic minimum operating limits and allowing resources to reflect their commitment costs in their prices. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
PJM responded to the order on Feb. 16, Militello said, requesting a response by this Friday. She said that if PJM receives a “clean” approval by then, it will implement the order on May 1 and conduct a second read of the manual changes in May at the MIC and the Markets and Reliability Committee meetings. If PJM doesn’t receive notification from FERC or has to make additional compliance filings, Militello said, the RTO will delay the second reading.
In Manual 11, PJM created new sections on fast-start capable resources, the fast-start capable adjustment process and eligible fast-start resources. In total, Militello said, PJM updated or created 21 sections in Manual 11 to provide clarity on how fast-start pricing will impact the current business rules.
Militello said Manual 18 had only minor changes, including a clarification that the scheduled megawatts used for excusal and bonus purposes in performance assessment interval settlement calculation will use dispatch run LMP.
Stadelmeyer said the Manual 28 updates include changes for dispatch differential lost opportunity cost credits and double counting of commitment costs.
Monitoring Analytics’ Catherine Tyler said the Monitor is “carefully reviewing” the manual changes, especially those for Manual 11. She said there are potential situations that may occur in which prices “don’t make sense given the outcomes happening in the market.”
Some of the changes in Manual 11 are “highly consequential,” Tyler said, including sections on verification of offers greater than $1,000/MWh and how reserves will be cleared and priced.
“There is a great need for clarity and transparency here because market participants are going to have questions once they see the different market outcomes with fast-start,” Tyler said.
Virtual Combined Cycles
Becky Robinson of Vistra provided a first read of a problem statement and issue charge addressing regulation for virtual combined cycle units.
Robinson said units that are “virtually” modeled by PJM can sometimes receive regulation awards from the market clearing engine that vary, which Vistra has been experiencing with some of its units.
The issue charge proposes several high-level work activities, Robinson said, including education on the operational and technical difficulties of operating virtually modeled combined cycle units with different regulation assignments and brainstorming possible solutions to ensure that regulation awards are consistent.
Robinson said Vistra wanted to scope the issue charge to be “targeted” because it’s a specific and technical issue.
“We don’t think of this as a broad policy issue,” Robinson said. “We don’t need to put another big item on stakeholder’s plates right now.”
The committee will vote on the proposal at its May meeting.
A Texas Supreme Court panel on Friday stayed 50 lawsuits filed against ERCOT and other entities in the wake of February’s long-term controlled outages, which have been blamed for almost 200 deaths.
The court’s Multi-District Litigation (MDL) Panel granted ERCOT’s request to stay court proceedings, including discovery, in 35 cases filed against it and other market participants. The grid operator’s April 7 motion also asked the panel to consolidate those cases (21-0313).
The panel also granted a request by Vistra, NRG Energy, Calpine, Exelon Generation and other ERCOT market participants to stay proceedings in another 15 cases related to the February storms.
The grid operator’s attorneys said in the motion that the 35 cases have been filed in four different counties, with 24 filed in Harris County in 15 different district courts.
“Based on the current number of filings and public advertising efforts undertaken by in-state and out-of-state attorneys, ERCOT anticipates there will be additional cases filed against ERCOT in numerous different counties,” the grid operator told the panel. “Under those circumstances, the likelihood of inconsistent rulings is near certain.”
ERCOT spokeswoman Leslie Sopko said the consolidation request was a “procedural mechanism to … more efficiently resolve common questions of law and fact.”
The grid operator maintains it has legal immunity from litigation, saying in its motion, “ERCOT has and will continue to assert that it is entitled to sovereign immunity due to its organization and function as an arm of state government.”
The Supreme Court last month left standing an appellate ruling granting ERCOT sovereign immunity from lawsuits in a 5-4 ruling. The issue is expected to be revisited as additional lawsuits are filed. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)
Cincinnati Insurance has requested legal authority to not pay claims against ERCOT following the winter storm. | Cincinnati Insurance
In a separate court proceeding last week, Cincinnati Insurance, ERCOT’s insurance company, asked the U.S. District Court for the Western District of Texas to excuse it from covering storm damages or damages from lawsuits filed against the grid operator (1:21-cv-298).
The insurer argued that it does not have to defend ERCOT because it does not view the power outages as an accident, which it defined as a “fortuitous, unexpected and unintended event.”
“The allegations in the underlying lawsuits allege ERCOT either knew, should have known, expected and/or intended that Winter Storm Uri would cause the same power outages which occurred as a result of previous storms in Texas, including storms in 1989 and 2011,” Cincinnati said in its motion. “The underlying lawsuits allege the power outages caused by Winter Storm Uri were a result of the exact same failures including failures of the same generators which failed in the previous winter storms, and therefore, the power outages were foreseeable, expected and/or intended.”
The insurer said the policy, which expires June 1, 2022, requires it to cover “damages because of ‘bodily injury’ or ‘property damage.’”
“We will have the right and duty to defend the insured against any ‘suit’ seeking those damages,” it said. “However, we will have no duty to defend the insured against any ‘suit’ seeking damages for ‘bodily injury’ or ‘property damage’ to which this insurance does not apply.”
If the federal court doesn’t grant the declaratory judgment, Cincinnati would likely have to cover ERCOT under its current policy contract.
The insurer said it had received 19 lawsuits alleging ERCOT’s responsibility for damages resulting from the storms. If the court doesn’t grant the declaratory judgment, it will likely have to cover the grid operator as part of its contract.
Cincinnati said it requested information on March 18 from ERCOT to facilitate its coverage investigation but said the grid operator didn’t respond to the requests.
ERCOT declined to comment on the insurance company’s allegations.
ERCOT to Take Questions on Outage Report
ERCOT on Friday invited stakeholders to submit questions about staff’s recent preliminary report on the causes behind generation outages that led to February’s long-term controlled outages. (See related story, ERCOT Blame Share: Weather (54%), Equipment (14%), Gas (12%).)
A preliminary ERCOT report attributes 54% of the February outages to bad weather. | Entergy
In a market notice, the grid operator acknowledged the “many questions” about the report and concerns that it may not have accurately reflected the total amount of capacity affected by the various outage causes. ERCOT filed the report with the Public Utility Commission on April 6.
During a Wholesale Market Subcommittee meeting last week, several stakeholders pushed back on the methodology that staff used in compiling the report. It used nameplate capacity in aggregating the outage numbers, resulting in outsized values for renewable resources.
“It seems likely, based on the outage cause categories presented, that a significant amount of wind and solar impacts were categorized as ‘Weather Related,’ resulting in that bucket appearing much larger than was operationally relevant during the event,” Luminant’s Ian Haley said in an email requesting the WMS place the report’s discussion on the agenda.
“Just as importantly, this may visually obscure valuable information about the relative outage and derate drivers for thermal generation,” he said. “Thermal and intermittent resources need to be separated into different graphs as these types of resources have very different characteristics. That comparison, while more helpful, is still not completely fair to wind and solar generation, as we would not expect every intermittent resource to be at nameplate capacity for six days in a row.”
Stakeholders have until the close of business on Thursday to submit questions about the report, which staff will “endeavor” to promptly respond to. ERCOT has promised a final report by Aug. 31.
In my last column I suggested that Texas pass on Berkshire Hathaway’s offer to give Texas 10 GW of new emergency generation to be fueled by liquefied natural gas, at a cost of $8.3 billion, in exchange for a guaranteed return on that $8.3 billion. BH had billed this as a “TOTAL SOLUTION” to the tragedy this winter in Texas.
I pointed out that the 10 GW would not have avoided load shed, and how impossible it would be for new facilities with winterizing to cost more than winterizing existing facilities. I gave an example of the South Texas Nuclear Unit 1 that could have been winterized for a pittance relative to what BH wants for equivalent capacity, $1.1 billion.
And I discussed some low-hanging fruit that Texas ought to pursue before throwing billions at BH.
BH has responded to my column, and here I address some of its claims.
No Load Shed if Existing Thermal Units Had Run
Perhaps most egregious of the BH claims is that “even if 100% of the thermal units were operating at full load during winter storm Uri there still would have been load shedding, as there was not sufficient dispatchable capacity to meet demand.”
The numbers simply belie this. As these pie charts from Wood Mackenzie show, ERCOT had 72 GW of thermal capacity, and an average of 30 GW were out during the storm.[1] Maximum load shed during the storm was 20 GW.[2]
ERCOT’s anticipated available capacity by fuel type for Winter 2020/21 compared to Wood Mackenzie’s estimate of the average contribution of each unit type to total resource outages from Feb. 15-17. | Wood Mackenzie, using data from ERCOT Seasonal Assessment of Resource Adequacy
Thus, if all thermal units had been operating at full load, ERCOT would have had at least 10 GW of extra capacity during the storm. Obviously, no load shed would have occurred. As many have said, the problem wasn’t lack of steel in the ground; it was steel in the ground that didn’t run.
Lifetime Cost No Bargain
On to the BH claim that the true lifetime cost of the 10 GW isn’t $8.3 billion but really is $3.55 billion because of revenue from two weeks of annual testing over 40 years, which revenue “flows back to customers.”
I don’t know how BH gets this $4.75 billion of revenue credits (difference between $8.3 billion and $3.55 billion), but if two weeks of testing covers more than half the cost of 10 GW, why not test for four weeks a year and make the 10 GW free? That’s of course impossible, and the reason is that the hypothetical $4.75 billion is billed to customers in the first instance. So the revenue credits are simply returning monies that customers pay.
Same, by the way, if the 10 GW had been around for Uri. BH says the 10 GW could have generated $9 billion in revenue, “fully paying for the entire cost of the facilities.” But again, customers would pay that $9 billion in the first instance, so BH would just be returning what customers pay. No free lunch.
Dual-fuel Capability
As for the option of adding dual-fuel capability at existing generation, BH says a generator is unlikely to add, say, a diesel fuel tank “with the expectation to never or rarely use it.” Of course, the BH proposal would reduce any incentive to do that by reducing energy prices.
And while conceding that the incentive may be insufficient in an energy-only market — with or without the BH proposal — my suggestion was that if Texas decides that some amount of dual-fuel capability is worthwhile, that it conduct a descending clock auction to add that to existing generation in a cost-effective way.
Subsidies Are Contagious
Let me close by observing that subsidized resources tend to crowd out unsubsidized resources in a kind of Gresham’s Law. The ERCOT Market Monitor aptly states, “As an energy-only market, ERCOT relies heavily on high real-time prices that occur during shortage conditions to provide key economic signals that incentivize development of new resources and retention of existing resources.”[3]
Adding 10 GW of subsidized resources in ERCOT would disrupt and crush those economic signals, discouraging new market-driven resources and inevitably leading to a need for more subsidized resources. As the PJM Market Monitor says, “subsidies are contagious.”[4]
Western states must work together to share renewable resources and build transmission to avoid blackouts like those that happened in California and Texas, speakers said Friday during a roundtable discussion hosted by the Western Energy Imbalance Market’s Body of State Regulators (BOSR).
Body Chair and Oregon Public Utility Commissioner Letha Tawney moderated a discussion between CAISO CEO Elliot Mainzer and Idaho Power CEO Lisa Grow.
The creation and expansion of CAISO’s EIM showed what entities across the West could do by working together, Grow said. The interstate exchange of energy has saved market participants $1.18 billion since 2014. Now, with more states enacting clean-energy mandates and interests aligning, the West will need to build more transmission, she said.
“Transmission, in my mind, is the great enabler of all of this,” Grow said.
“The notion that everyone is just going to build all the resources they need in their [balancing authority areas] to get to clean [energy], I don’t think is necessarily the best way to think about it,” she said. “When we really think about where the richest fuel sources are, the Pacific Northwest has hydro. The Desert Southwest has solar. Wyoming and Montana have wind. That’s where the really good stuff is, and so, when you think about how we connect it, it’s transmission.”
The rolling blackouts in California in August and, to a lesser extent, the blackouts in Texas this winter, were examples of “what happens when you don’t have enough transmission to move resources around to where they’re needed,” Grow said.
Transmission constraints were one factor that CAISO and state agencies cited in their report on the root-cause analysis of the Aug. 14-15 blackouts in California. (See CAISO Says Constrained Tx Contributed to Blackouts.)
BOSR Chair Letha Tawney, CAISO CEO Elliot Mainzer and Idaho Power CEO Lisa Grow discussed issues facing the West. | EIM BOSR
Building transmission is difficult, but “it’s just such a foundational requirement to get to where we all want to go and to unleash the economic potential” of transitioning to clean energy while ensuring reliability, Grow said.
“Lord knows we’ve been trying to build some transmission lines, it seems like, for most of my career,” she said. “It is a long, drawn-out process, and I would just ask everyone to think about how we can reduce some of the barriers if we’re all trying to get to that same goal.”
Mainzer said: “I couldn’t agree more.”
In his previous job as head of the Bonneville Power Administration and now at CAISO, Mainzer said he has seen the importance of “interconnectedness and optionality and resource development, resource diversity, resiliency — those are all becoming so increasingly important.”
Looking to 2045 — the year California is required by Senate Bill 100 to supply all retail customers with clean energy — “I think there’s a real recognition that having that additional capability and exchange of capacity, diversity and optionality with the rest of the West is going to be really important,” he said. “The West has been planning its transmission system for a long time. I think people look at the map and they know a lot of the big paths. Some of them are even permitted and almost ready to go. It’s how do you move from transmission planning, which is incredibly important, to transmission construction and the energization.”
At CAISO, “we’re really looking forward to accelerating the pace of transmission construction and working with the [California] Energy Commission, working with the [California Public Utilities Commission], working with all of you across the West to … see if we can put some commercial activity together.”
Tawney asked Mainzer and Grow how not having a Western RTO — and relying on the hybrid structure of the EIM, a real-time interstate trading market — could affect the shift from transmission planning to construction.
Efforts to create a Western RTO have been halting and unsuccessful, Grow said. But the EIM “is showing how you can have this organic growth … whether or not you ever get to the full RTO.”
“This is a way that we can incrementally grow … as we build the system out. With that in mind, I actually think it’s a facilitator” of transmission construction, she said.
Mainzer said, “I agree with that a lot. I see the two things [EIM and transmission] as being very complimentary.
“If you think about a big piece of the value proposition of the Energy Imbalance Market, then your transmission interconnectivity that we already have with the West” is a big part of it,” he said.
“Just last week, when we incorporated [the Los Angeles Department of Water and Power] into the EIM, that’s a nice big piece of additional transfer capability between the ISO and L.A.,” Mainzer said. “We’ve got that same thing happening with [Public Service Company of New Mexico] now.” (See Expansion Takes EIM into LA, New Mexico.)
“As you think about the other regions, and we open up the EIM, we could take the existing transmission topology that we’ve got and we can ask ourselves, ‘What are some other enhancements, reinforcements, new builds that could further open up resource development, diversification, capacity capability and strengthen the ability to exchange more energy, to unlock more economic and environmental value?’” he said.
“Part of it is just about raw access to resources.” California may need an additional 80 GW of bulk generation to meet its clean energy goals by 2045, according to recent projections, he said.
“That’s a lot of resources. We are going to need to access capability from out of state and transfer it and import and export economic and environmental capability,” Mainzer said. “So we just have get to really real about where is the system today … what are the most potent and effective line expansions … so that we can unlock economic value.”
Rhode Island Gov. Dan McKee on Saturday signed the 2021 Act on Climate into law in Newport.
The act sets a legally binding 2050 net-zero emissions target for the state and updates previous emission-reduction targets to 45% below 1990 levels by 2030 and 80% by 2040.
“With 400 miles of coastline, urban and rural coastal communities, fishing and agricultural industries, the Ocean State is on the frontlines of this climate crisis,” McKee said at the signing ceremony. “This legislation represents a commitment that not only addresses a moral imperative, but also presents an opportunity to enhance our economy, public health, environmental equity and natural environment.”
Rhode Island Gov. Dan McKee signed the 2021 Act on Climate into law at Bowen’s Wharf in Newport. | Gov. Dan McKee via Twitter
Under the new law, the state’s Executive Climate Change Coordinating Council must create a plan to reduce emissions and coordinate them through state agencies. The plan will be updated every five years and will address environmental justice issues, public health inequity and a fair transition for workers.
Legislators sent the bill to McKee at the end of March, but the governor replied with a letter to Rep. David Bennett, chairman of the House Environment and Natural Resources Committee, expressing “serious concern” over the bill’s enforcement provision. He said the language, which authorizes residents or entities to sue the state if it is not fulfilling any part of its duties as laid out in the act, is “unduly broad” and would promote protracted and expensive litigation. His concerns echoed those of legislators on both sides of the aisle.
Any action to enforce the climate law, McKee said, should be limited to the attorney general.
In an April 6 letter to the governor, however, Attorney General Peter Neronha urged passage of the bill without amending it. He said that the enforcement provision is common and there are “both practical and procedural safeguards that prevent specious litigations from advancing in the court.”
The Senate and House of Representatives passed the bill a second time on April 7 and sent it back to McKee.
Regulators in Connecticut are trying to create an environment in which stakeholders of the emerging electricity marketplace can safely innovate and scale new solutions.
The Connecticut Public Utilities Regulatory Authority (PURA) has expanded its docket on an Equitable Modern Grid to 11 tracks, which include creating a “regulatory sandbox,” Chair Marissa Gillett said.
A sandbox provides an opportunity to test products and services and establish guardrails to ensure consumer protection and ratepayer benefits. It would also encourage competition and further Connecticut’s public policy goals.
PURA is trying to project what the grid will look like in 10 years, Gillett said during the Connecticut Green Bank webinar Clean Tech in CT: A Sandbox for Local Innovators. And the track is meant to find ways to “foster and incentivize new solutions and ideas,” Gillett said.
PURA is not trying to dismantle “the inherent monopolies” of electric distribution companies (EDCs) like Eversource and Avangrid, Gillett said, adding that there is still a need for competition in the ideation space.
“I don’t think it’s a secret that traditional utility regulation is not particularly nimble or adaptable,” she said.
In December, PURA released a strategic vision document that builds on the concept of a sandbox for addressing the tension between EDCs and the regulators with limited waivers from standard regulations and requirements. It allows companies to test their products or services in a constrained and safe environment, often on an expedited basis.
That flexibility is especially critical for the introduction of new customer offerings. In the ever-evolving electricity marketplace, utilities, third-party innovators and regulators benefit from agile processes and approaches that can quickly scale up potential new solutions. PURA released the vision document to promote discussion of the potential sandbox framework.
“We’re used to these tried-and-true methods in the regulatory world, and introducing new ideas to that regime takes a very deliberate process that we’re trying to work through here,” Gillett said.
The goal of the sandbox should be creating a “safe space” to identify solutions that can either scale up quickly or “fail fast” with minimal ratepayer risk, she said.
Venture capital investor Connecticut Innovations is launching an innovation lab for investing in companies that are going to “get into that sandbox,” CEO Matthew McCooe said.
The firm invested $10 million across “six very strong clean tech companies” in the state, and their collective revenue for this year should be north of $200 million, which is “remarkable,” McCooe said.
Pete Londa, president and CEO of Tantalus, said the current grid was designed as a one-way flow of power that cannot deal with power coming from the home, electric vehicles or storage devices accessing and delivering energy. He said that the transformation to a two-way grid creates fear “because the world’s changing.”
“Utilities are challenged in that capacity of having to continue to leverage and maximize the value of existing infrastructure that wasn’t designed for the future innovation that leads to fear,” Londa said. “That fear leads to challenges and making decisions, and that’s an inhibitor.”
He added that Tantalus could help Eversource, for example, obtain more granular data at the “very edge” of its network that would not require the utility “to rip and replace 100% of the meters immediately.”
“They can continue to maximize the value of what they have while upgrading and preparing for the future; as things evolve and change, it would be immediate savings out of the gate to allocate those dollars to other initiatives across the organization,” Londa said. “Ultimately, it would help them improve their impact on the environment, improve their services to their community and ultimately lead to better governance inside their organization in terms of how they’re allocating dollars.”
Some California lawmakers want the woody biomass from forest thinning efforts to be used for electricity generation, after four years of catastrophic wildfires bathed the West Coast in smoke, with rural disasters choking major urban areas.
The normally good air quality in the San Francisco Bay Area, for instance, was among the worst in the nation during last summer’s massive fires that burned more than 4 million acres.
Assemblymember Rebecca Bauer-Kahan (D), who represents the wealthy San Francisco suburbs near where the SCU Lightning Complex of fires burned almost 400,000 acres in August and September, argued for biomass during Wednesday’s hearing of the Assembly Utilities and Energy Committee, which approved a measure that could give bioenergy a boost.
Sierra Pacific Industries operates five cogeneration facilities in California that use woody biomass from forest thinning and sawmill operations, including this plant in Shasta County. | Sierra Pacific Industries
“I am a diehard environmentalist and have one of the strongest environmental records in the legislature, and yet we have to be real about what is happening,” Bauer-Kahan said. “We are having to thin our forests because, as we all know, one of the largest emissions sources right now is our wildfires, and the toxic air that is coming into all of our communities, whether you live in one of these high fire [threat] zones or not, is poisoning our children. And so we’re doing the work to prevent that, and that is leading to biomass.”
The black carbon and other particulate matter from wildfires are far worse than the relatively small amount of pollutants released by biomass plants, she and others contended.
California law requires the state to rely entirely on clean energy and renewable resources by midcentury. Although biomass is classified as a renewable resource, environmentalists have opposed it because burning wood and agricultural waste emits pollutants, as does burning methane from the mountains of manure produced by California’s large industrial dairies.
Two major environmental groups, the Sierra Club and the Natural Resources Defense Council, initially opposed the measure that Bauer-Kahan and other urban Democrats supported. The groups removed their opposition to Assembly Bill 322, introduced by Assemblymember Rudy Salas Jr. (D), only after he agreed to remove a proposal to dedicate a large chunk of the state’s renewable energy research funding to biomass projects.
Before it was amended, AB 322 would have required the California Energy Commission (CEC) to allocate at least 20% of its Electric Program Investment Charge (EPIC) funding to biomass research and innovative startup projects. The EPIC program dispenses about $130 million each year, meaning biomass could have received $26 million annually, significantly more than the CEC has allocated previously.
Woody biomass fuels the 44-MW Mt. Poso Cogeneration faciliity in Bakersfield, Calif. | DTE Energy
Getting rid of the spending requirement means the bill only asks the CEC and the California Public Utilities Commission to consider biomass projects in future funding cycles. Some lawmakers on the committee, both Democrats and Republicans, strongly disagreed with the decision.
“A whole lot of people just spoke on a bill that no longer exists,” Assemblymember Bill Quirk (D), also from the San Francisco Bay Area, said after a round of public comment. “We’re just basically going to politely ask, which I’m sure will not mean a whole lot.”
Forest biomass is typically the most expensive fuel for generation. It cost about $200/MWh, compared with $50/ MWh for solar power in 2019, the CPUC reported.
Transportation is a major factor. “The maximum viable haul from the forest to the biomass power plant is 50 miles to be financially feasible,” the energy committee’s analysis of AB 322 said.
That cost is a main reason biomass has never become a major power source in California.
The CEC said there were 79 biomass and waste-to-energy power plants operating in 2019, producing less than 3% of in-state generation. Most of the plants are small, with nameplate capacities ranging from 2 to 32 MW, and only a half dozen use woody biomass for fuel.
Total capacity of bioenergy in California declined from 1,301 MW in 2014 to 1,289 MW in 2019, with 10 plants idled, the CEC reported.
Quirk acknowledged the cost hurdle, but he said biomass research and demonstration projects are needed for forest management and wildfire prevention.
“The problem I see is that it’s not just a matter of generating electricity,” he said. “The problem here is what you do with the biomass and what the alternatives are if you don’t do this. It becomes extremely expensive to, say, take it and compost it somewhere. Is that what we’re going to do?”
Gov. Gavin Newsom and legislative leaders announced a deal Thursday to spend an extra $536 million to accelerate forest management and other fire-prevention efforts.
With the state focused on wildfire fuel reduction, it needs a plan to deal with millions of tons of forest debris or face larger problems down the road, Quirk said.
“This is not just an energy issue; this is a much wider environmental issue,” he said.
Assemblymember Jim Patterson, the Republican vice chair of the energy committee, said he was disappointed the bill had been weakened. Patterson’s district encompasses much of the burn area from last summer’s 380,000-acre Creek Fire, which started in September 2020. It was the biggest wildfire in state history that was not part of a larger complex of fires.
“Most of you know I’m a rate hawk, and I’ve been one since being vice chair here,” Patterson said. “But I think my colleague [Quirk] raises a very important point: that there is more to cost than merely the creation of the electricity.”
Like others, Patterson said he would vote for the weakened bill in hopes that it would prompt more interest in using biomass generation as part of the state’s wildfire prevention efforts.
“My hope is that it will begin a conversation, and I hope that the regulatory agencies that are going to make these decisions will take the comments seriously of members here, and also ask the real tough question about what happens if we don’t,” Patterson said.
During his first month as president of the University of Connecticut in 2019, Thomas Katsouleas had several hundred students visit his office, but they were not a welcome wagon. They were there to read him a list of demands as part of a student-led climate strike organized by the university’s Fridays for Future chapter. Katsouleas said one thing that stood out to him was the students’ command of climate issues.
“What impressed me the most was the nuanced understanding of the challenge ahead that those students showed and the commitment to meeting that challenge,” Katsouleas said during a webinar co-hosted by the sustainability offices at UConn and Southern Connecticut State University.
Katsouleas said he had made the university’s role in addressing the climate crisis “a focus of my presidency,” including campus carbon neutrality by 2040 and strategic planning that focuses on the existential threat of climate change and environmental justice through the lens of education, research and outreach.
The webinar was presented as part of the virtual, three-day Solve Climate by 2030 educational dialogue created through Bard College’s graduate programs in sustainability. Students joined sessions that were held in 50 countries and every U.S. state to learn about actions that can support a just energy transition.
The University of Rhode Island joined institutions around the world in hosting educational webinars on climate and energy as part of a three-day Solve Climate by 2030 dialogue. | Shutterstock
Speaking during the webinar, SCSU President Joe Bertolino said he signed a climate emergency declaration by college and university presidents in July 2019 after 200 students implored him.
He said that colleges and universities like SCSU and UConn “are essentially small towns and cities.”
“We are a significant sector of buildings, acreage, jobs, transportation fleets and productivity,” Bertolino said. “Higher education institutions are testing grounds and learning labs for how sustainable communities can be built.”
At the state level, Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes said her agency is “laser focused” on passing a bill to support the Transportation and Climate Initiative Program (TCI-P), which aims to cut vehicles emissions by 26% from 2022 to 2032.
“It’s kind of a simple program … it requires the polluters to pay for their pollution,” Dykes said. “In this case, the polluters are those companies that sell gasoline and diesel fuel at wholesale.”
Bryan Garcia, president of the Connecticut Green Bank, said that his “one, bold solution” to address climate change would be a federal Green Liberty Bond, like one launched last year at the state level. Garcia said the bonds could finance the national fight against climate change in the same way that bonds raised money during World War II. Garcia said nearly $17 million in Green Liberty Bonds were sold during the inaugural offering in 2020.
Shanté Hanks, deputy commissioner of the Connecticut Department of Housing, said she considers herself a translator when explaining climate change’s impact on communities of color.
“We talk to members of the local communities and explain to them how these concepts affect people’s day-to-day lives or explain that what they do today will impact their grandchildren’s lives in the future,” Hanks said. “It’s so important that we connect with their values.”
Social Components of Policy
Lawmakers need to incorporate societal benefits in climate and energy policy, such as public health, job creation and environmental justice, to be successful in reaching net-zero goals, according to Jennie Stephens, director of the School of Public Policy and Urban Affairs at Northeastern University.
“We’ve placed too much emphasis on tech and not enough on social innovation,” Stephens said during a Solve Climate webinar hosted by Brandeis University.
Policies should connect the dots between renewable energy, economic development and clean air and water, and focus on “communities that have been under-invested in for far too long,” Stephens said.
Otherwise, renewable energy policies contribute to racial and economic disparities through incentives and subsidies that give the wealthy access to clean energy and leave low-income communities paying higher utility rates. As more high- and medium-income communities harness clean energy resources, it will increasingly fall on people who cannot afford to make the transition to renewable energy to provide the same revenue stream to utility giants, she said.
“One social movement that I think is really helpful here is the idea of energy democracy, which is about redistributing power literally and figuratively,” Stephens said.
Renewable energy policies can create a future with a handful of multinational solar and wind companies that dominate the industry, much like fossil fuel companies today, she said. Or policy can focus on intentionally distributing the right to have a heterogenous mix of different-size companies and different ownership models.
At the national level, President Biden’s infrastructure bill proposes economic recovery investments that are “integrated rather than separate,” Stephens said. The Biden administration also created a new role in the U.S. Department of Energy for implementing energy policies that align with energy justice goals.
Shalanda Baker, a professor of law and policy from Northeastern University, stepped into the position earlier this year. According to Baker, energy justice is the goal of achieving racial equity in participation with the energy system.
“It’s an opportunity to rethink our climate commitments in a more integrated and holistic way, and I think that’s essential for it to be effective,” Stephens said. Decarbonization policies should “acknowledge all the harm that has been done and how to make up for that.”
Building a Regenerative Economy
Solve Climate sessions in Rhode Island and New York characterized the ways people are reframing their thinking on climate and energy.
The Rhode Island Office of Energy Resources is working internally to raise awareness about how racism in the state has contributed to systems of oppression within the energy sector, according to Yasmin Yacoby, the agency’s program manager for energy justice.
There is a direct link, she said, between communities where lending was limited historically, often based solely on racial demographics, and communities today that have the highest energy burden in the state.
“We need to ensure that we have a solid understanding of these historic legacies so that we can actively undo them,” she said during a Solve Climate webinar hosted by the University of Rhode Island.
Achieving that goal, according Yacoby, requires state leaders to use a targeted approach to solving universal climate goals.
“If we only focus on climate solutions and not on the racial disparities that exist within that sphere, we’re going to continue to exacerbate the issues,” she said.
OER’s work focuses on increasing community engagement and building a just energy transition.
“We don’t have a lot of the knowledge that community members have, so we have to make sure that their voices are at the table and that the communities that have been historically oppressed have a way to shape their energy future,” Yacoby said.
Building up those oppressed communities will mean Rhode Islanders must transition away from an extractive economy and embrace a regenerative economy.
That process, Yacoby said, displaces the fossil fuel economy with a “new economy that provides democratic governance, ecological resilience and personal resilience.”
Current clean technologies like solar are starting to make a regenerative economy possible, said Simeon Banister, vice president of community programs at The Community Foundation.
If solar panel efficiency improves and costs come down further, solar can be a “game changer” for marginalized communities, Banister said during a Solve Climate webinar hosted by six New York institutions of higher education.
“If we start with those that have been historically excluded, it means that we can finally have the conversation about how we do things differently, and that’s what systems change is all about,” he said.
Regenerative thinking must consider how decisions are made, according to Jodi Smits Anderson, director of sustainability for the Dormitory Authority of New York. Historically, energy decisions have been short-term and do not consider co-benefits or co-burdens, she said during the New York webinar.
“We haven’t asked, ‘How does this decision affect the systems that are impacting this particular building or this particular policy?’ And we haven’t taken it to the next step to ask, ‘How does this decision affect nature’s systems?’” she said. “That is a regenerative practice mentality.”
Climate and energy decision-making must be centered around people, Banister said.
“It’s not a question of just how we can reduce emissions … it’s how do we do it for the folks that have suffered the most,” he said. “If we center them, if that’s our point of departure, then that gives us the chance to really make something that is sustainable in nature.”
