Page 1011 – RTO Insider

November 25, 2020

ISO-NE PAC Briefs: Nov. 19, 2020

ISO-NE is proposing a pilot study for its “Transmission Planning for the Clean Energy Transition” effort that would test grid performance assumptions under scenarios of high renewable penetration and quantify the tradeoffs between transmission investment and less system flexibility.

The pilot study would take a “10,000-foot view” of the entire New England system, rather than a portion of it, according to Dan Schwarting, a transmission planning supervisor for the RTO.

The goal is to identify the overall trend of system behavior and reliability concerns as more renewables are brought online, not to identify exact needs or system upgrades. Base cases will represent a likely dispatch for a given condition rather than stress any specific portion of the system through generator outages.

The RTO said steady-state N-1-1 analysis on the entire system is feasible because of recent study automation efforts. Stability analysis will concentrate on faults on the 345-kV system and 230-kV or 115-kV faults that are incredibly impactful. Limited electromagnetic transient study work may be pursued as well.

ISO-NE PAC — Each blue dot represents a single hour experienced between 2012 and 2018. ISO-NE is proposing to study the “corners,” at the intersection of high/low load and high/low solar output. | *ISO-NE*

Schwarting said the results of the pilot study will be most useful if it begins with fairly conservative conditions, such as high wind generation when low inertia may be a concern and low wind generation where load serving may be an issue. He said it would also investigate potential paths to address reliability concerns through transmission system investment, operational measures and policy changes.

Any reliability problems found would not be immediately addressed in a solutions study or competitive request for proposals. The proposed transmission solutions would be representative only, and costs would be order-of-magnitude estimates.

The results of the pilot study would inform decisions on assumptions to be used in future transmission needs assessments.

Additionally, certain study assumptions are affected by policies both inside and outside ISO-NE’s purview, such as distribution system power factor, distributed energy resource voltage and frequency control capability, and DER fault ride-through capability. Initially, the pilot study will assume a “business-as-usual” approach to these policies. If changes to the policies promise benefits, they will be considered as mitigating measures. However, the RTO wants reasonable assurance that these policies would be implemented and enforced before it could rely on them in future needs assessments.

Schwarting said that many stakeholders provided comments during and after his PAC presentation in September. (See “Proposed Study Conditions to Meet Challenges in Transmission Planning,” ISO-NE Planning Advisory Comm. Briefs: Sept. 24, 2020.)

The feedback related to study conditions centered on two questions: How likely are the proposed study conditions to occur, and can operational measures ensure reliability in those conditions?

The DER and storage policies-related feedback and questions from stakeholders included: Would the implementation of voltage and/or frequency control on DERs mitigate reliability concerns? Also, could better rules around the behavior of storage assets address peak- and minimum-load conditions?

Stakeholders may submit feedback on the pilot study proposal until Dec. 4, and the next steps include the development and review of the base cases. The analysis will begin in late 2020 or early 2021. The RTO will reach out to distribution providers regarding DER data collection in parallel to the pilot study.

Preliminary Production Cost from Economic Study Presented

ISO-NE presented preliminary production cost results to the PAC for the 2020 Economic Study requested by National Grid. The utility asked for a one-year study focused on 2035 to provide stakeholders analyses of the best ways to meet state clean-energy goals cost-effectively, leveraging transmission and storage as needed.

Richard Kornitsky, ISO-NE’s assistant engineer for system planning, said the introduction of bidirectionality across existing ties causes a reduction of spillage during situations of low load and high-variable resource production. Total systemwide spillage is relatively low compared to the New England States Committee on Electricity case of 8,000 MW spilled because of the RTO’s assumption of high load in 2035.

Because emissions associated with imports from Hydro-Québec and New Brunswick are assumed to be zero, the impact of energy banking of non-emitting New England resources is not apparent in many of the systemwide metrics. Natural gas production is replaced by adding new ties with firm low threshold-price import capability from Hydro-Québec.

The study used bidirectional threshold prices reflecting renewable energy credit values, first-to-curtail imports, then trigger exports, with renewables curtailed once export capability is exhausted. The prices ranged from -$100/MWh for behind-the-meter PV to -$30/MWh for onshore wind. The trigger for exports is assumed at -$25/MWh.

Kornitsky asked for any feedback or comments by Dec. 1, including possible sensitivity scenarios. The next steps include identifying sensitivity scenarios and assumptions for the PAC meeting on Dec. 16, presenting assumptions for ancillary services analysis and draft results in the first quarter of 2021. The final report is expected in the second quarter of 2021.

November 25, 2020

NERC Blasts Calif. Nuclear Group’s Complaint

NERC last week urged FERC to reject a request filed by the nonprofit group Californians for Green Nuclear Power (CGNP) in October to overturn the planned closing of Pacific Gas and Electric’s Diablo Canyon Power Plant, California’s last nuclear generating station, in 2025 (EL 21-13).

CGNP describes itself as a collection of “dedicated scientists … with decades of experience [in] power generation, grid safety and emissions reduction” that is “dedicated to promoting the peaceful use of safe, carbon-free nuclear power.” Its complaint alleges that the closure of Diablo Canyon will cause “adverse bulk electric system and … bulk natural gas system consequences” that NERC and WECC, along with CAISO, the California Public Utilities Commission, the California State Lands Commission and the State Water Resources Control Board have failed to properly anticipate or counter.

Shutdown Planned by PG&E, Green Groups

Diablo Canyon consists of two nuclear reactors with a nameplate capacity of 2.3 GW and has operated since 1985. In 2019, it produced nearly 16.2 TWh of electricity, according to the U.S. Energy Information Administration, accounting for about 10% of in-state generation.

PG&E asked the CPUC in 2016 to approve a plan to shut the plant down in phases beginning in 2024, with full closure the following year. Under the proposal, created in partnership with environmental, labor and anti-nuclear advocacy groups, Diablo Canyon will be replaced with “a portfolio of [greenhouse gas]-free resources.” The utility described this plan as “the most effective and efficient path forward” for meeting renewable energy goals set by California’s legislature in 2015.

CGNP has been a vocal critic of the shutdown plan since its inception, arguing before the CPUC that Diablo Canyon is the most cost-effective option for supplying the state’s power needs while also limiting carbon emissions. The group is far from alone in this concern; CAISO Vice President Mark Rothleder warned the ISO’s board last year that expected summer energy shortages could worsen when the plant is shut down. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

CGNP also warned that retiring the plant will create strains on the BES because California will need to import more natural gas to make up the difference, and natural gas imports rely on an “aging and vulnerable” transmission and storage system. Trying to replace Diablo Canyon’s generation capacity with wind and solar facilities is problematic because of their reliance on transient resources, as opposed to nuclear fuel with an assured supply, it said.

“Rather than serving as an isolated incident, the August 2020 blackouts point to much larger systemic reliability challenges that will only be made worse by the voluntary closure of” the plant, the organization said in its complaint. “There are present reliability challenges to the California natural gas bulk transmission and storage system that are a consequence of its vulnerability to sudden earthquake motions and slow aseismic (without an earthquake) creep caused by the relative motion of Earth’s crustal plates.”

Respondents Critique ‘Unclear’ Legal Basis

CGNP’s filing drew some support from activist groups, including the Thorium Energy Alliance (TEA), which advocates “preserving and expanding the fleet of domestic [U.S.] nuclear reactors,” and the American Nuclear Society, a professional organization of nuclear engineers and scientists. Both groups echoed the organization’s warnings of rolling blackouts and “further weakening California’s power grid,” and TEA further argued that shutting down the state’s last nuclear plant would hamper its nuclear education industry.

In response, NERC and the other respondents took issue with a number of elements in CGNP’s filing. Most significantly for the ERO, the complaint cites no specific violations of reliability standards, instead offering “general, nonspecific assertions” about NERC and WECC failing to conduct proper oversight. Moreover, licensing nuclear power plants does not fall under the authority of the ERO; “as such, it is difficult to even infer the types of reliability standards violations the complaint is trying to allege,” NERC notes.

PG&E made a similar assessment in a separate filing, asserting that “responsibility for electric generation resource planning in California rests with state authorities” rather than with FERC. Other respondents, including the CPUC and CAISO, echoed this argument, calling the legal basis for CGNP’s complaint “unclear.” For example, CAISO pointed out that CGNP accused it of violating the Natural Gas Act of 1938 and the Federal Pipeline Safety Regulations, which do not apply to it as an ISO.

“CGNP’s complaint fails to meet the requirements of the commission’s Rule 206, is inconsistent with the Federal Power Act and makes factual errors,” the CPUC said. “CGNP’s complaint against the CPUC therefore has no merit and should be rejected in an order based on the pleadings.”

November 24, 2020

NYISO, Others Rebut MOPR Complaint to FERC

NYISO and sympathetic intervenors last week filed comments urging FERC to reject a request that it require the ISO to implement a “clean” minimum offer price rule (MOPR) that applies to all subsidized resources throughout the New York Control Area with limited exceptions.

The comments came in response to an Oct. 14 complaint by the owners of two natural gas-fired plants in the Hudson Valley, the 1,177-MW Cricket Valley Energy Center (CVEC) in Dover and the 635-MW Empire Generating facility in Rensselaer (EL21-7).

The complainants requested fast-track processing and the issuance of an order on or before Dec. 31 finding that NYISO’s market rules are unduly discriminatory “because they fail to address price suppression” in the installed capacity spot market auctions resulting from resources receiving out-of-market payments.

They asked the commission to require NYISO to implement a clean MOPR, “as it did when confronted with the same problem in FERC Acts on PJM MOPR Filing.)

NYISO MOPR — An aerial shot of the 1,177-MW Cricket Valley Energy Center in Dover, NY | *Advanced Power*

NYISO said that New York’s support for some resources is not resulting in price suppression because conditions in NYISO differ from those in PJM when it instituted a MOPR in 2018.

The complainants’ “price suppression claims are overstated, one-sided and incomplete,” and they try to use their concerns regarding the potential price effects of zero emission credits (ZECs) to sweep away buyer-side mitigation (BSM) rules that have nothing to do with ZECs, NYISO said.

In their complaint, CVEC and Empire pointed to the commission’s “standard solution” precedent, which found that FERC will rely on a MOPR as its standard practice for dealing with subsidized resources. But NYISO said their interpretation of that policy is “overly simplistic, inconsistent with earlier rulings (including the ‘standard solution’ precedent itself), and an impermissible collateral attack on settled commission determinations.”

The complainants failed to meet their burden of proof, NYSIO said in urging the commission not to grant the requested relief or take any other action in the proceeding.

“In the alternative, and at a minimum, the commission should reject the clean MOPR because imposing it on New York would be unjust and unreasonable,… would result in over-mitigation and would artificially increase capacity prices. The clean MOPR was designed to work with PJM’s three-year ahead forward auctions, not the NYISO’s ‘prompt’ seasonal and monthly auctions,” the ISO said.

NYISO referred to a separate but concurring comment from its Market Monitoring Unit, Potomac Economics, which said “complainants have not come close to meeting their burden of proof to show that the existing BSM Framework is unjust and unreasonable… [and the] recommended clean MOPR would result in inefficiently higher prices because it would selectively address out-of-market state actions that increase supply while conspicuously ignoring those that decrease supply.”

Supporting Voices

The Independent Power Producers of New York (IPPNY) and the Electric Power Supply Association (EPSA) supported the complaint.

IPPNY said New York’s decision to require retail electricity customers to “pay a higher price for zero-carbon energy sources than is reflected in the competitive wholesale electricity market price suppresses wholesale market prices below efficient levels,” suggesting instead a carbon pricing program.

Carbon pricing would help achieve the state’s clean energy goals, maintain the competitive market, and lessen the incidence of mitigation issues, thus avoiding unnecessary litigation, IPPNY said, noting its previous testimony to the commission. (See “RTOs, Regional Differences,” Wide Support for FERC Carbon Pricing Statement.)

IPPNY also noted that wholesale energy prices in New York currently include some value for carbon emissions because the state participates in the Regional Greenhouse Gas Initiative (RGGI).

EPSA also urged NYISO to finalize its carbon pricing proposal or face prospective implementation of a clean MOPR-type mitigation to protect the wholesale market.

“Expanding mitigation may be necessary if a market-based alternative is not finalized by the state and the ISO, though competitive suppliers want to see markets move beyond this approach,” EPSA said. “The possibility of expanding mitigation to protect the wholesale market should serve as a clear indicator to New York that a comprehensive carbon pricing approach is the necessary next step … [to] integrate emerging environmental goals as seamlessly as possible.”

Commissioner Richard Glick last month dissented from the commission’s decision not to exempt commercial demand response programs from NYISO’s BSM rules, saying the rules “that were once intended only as a means of preventing the exercise of market power have evolved into a scheme for propping up prices, freezing in place the current resource mix, and blocking states’ exercise of their authority over resource decision making.” (See FERC: NY DR Program Not Exempt from Offer Floor Rule.)

Subsidies for All

The New York Public Service Commission and the New York State Energy Research and Development Authority (NYSERDA) also rebutted the complaint, joined by the Utility Intervention Unit of the state’s Department of State, the City of New York, the Municipal Electric Utilities Association of New York, and Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers.

Complainants have not established a valid factual or legal basis for the granting of their request, and NYISO’s markets are functioning well, are competitive and are producing just and reasonable results, the PSC and its partners said.

A group of “Clean Energy Parties” urged the commission to allow stakeholders to work through NYISO’s governance process and the PSC’s resource adequacy proceeding to explore ways to integrate policy with the ISO’s capacity market design.

The group included the Sustainable FERC Project; the Natural Resources Defense Council; Sierra Club; American Wind Energy Association; Alliance for Clean Energy New York; and Advanced Energy Economy and relied on a Brattle Group report on resource adequacy in New York.

Expanding NYISO’s BSM rules as requested in the complaint would result in almost 3,900 MW of redundant gas- and oil-fired plants clearing the capacity market over the next decade that otherwise would have been replaced by state policy resources, the protest said.

The Brattle Group researchers “estimate the total cost to New York consumers of the MOPR expansion sought by this complaint at $1.3 billion annually by 2030. Rarely do consumers get so little for so much,” Clean Energy Partners said.

Public Citizen noted that CVEC, while attacking what it claims to be unfair subsidies provided to zero emission resources, has received over $100 million in property tax breaks from Dutchess County.

“Again, Cricket Valley’s claim that zero emission resources receive unfair subsidies ignores their own nine figure subsidy courtesy of New York taxpayers,” the watchdog group said.

Public Citizen criticized complainants for asserting that the identities of minority share owners of CVEC, partner-owners of Switzerland-based Advanced Power, are “highly sensitive commercial information that is not generally available to the public,” while the company’s public website lists the individuals.

“When Cricket Valley cannot recognize the distinction between ‘highly sensitive commercial information’ and freely-available information on a public web site, then it is unsurprising the company is struggling to earn income in excess of its costs and debt service,” Public Citizen said.

November 24, 2020

PJM Sets BRA for May 2021

PJM will hold the 2022/23 Base Residual Auction in May after being delayed since 2019 over FERC’s expansion of the minimum offer price rule (MOPR).

The auction will take place from May 19-25 PJM said, and it will post the BRA results on June 2.

Pete Langbein of PJM presented the updated schedule for the 2022/2023 BRA and future auctions at last week’s Markets and Reliability Committee meeting. Langbein said PJM determined the implementation of auction dates was appropriate after FERC’s Nov. 12 order on the forward-looking energy and ancillary services (E&AS) offset calculation (EL19-58-002). (See FERC Approves PJM Key Capacity Market Variable.)

Langbein said the order on E&AS offset was the final piece to establish the timeline for the BRA and all the associated activities leading up to the auction.

“We received a relatively clean forward-looking energy and ancillary services offset order,” Langbein said. “We feel confident that we can move forward with the actual BRA.”

FERC’s order required PJM to make a compliance filing within 15 days to use the average equivalent ability factor of all the nuclear resources in the RTO to represent a projected refueling outage. Several stakeholders had argued that using individual anticipated refueling schedules when determining nuclear resources’ availability was inadequate.

PJM Base Residual Auction — Auction Schedule | *PJM*

Langbein said the commission provided PJM the red line Tariff language necessary to make the filing.

PJM has been working on a compressed BRA schedule since February when the RTO began sketching out its response to FERC’s order expanding the MOPR. (See PJM May Compress BRA Schedule over MOPR.)

Since the BRA is scheduled to take place soon, Langbein said PJM had to cancel the first and second incremental auctions for both the 2022/23 and the 2023/24 delivery years. The 2023/24 BRA is scheduled to take place December 2021.

PJM also proposed canceling the first incremental auction for the 2024/25 delivery year in June 2022.

The incremental auction changes are based on the compressed BRA schedule, Langbein said, and PJM determined that a scheduled incremental auction will be canceled if its normally scheduled date has passed. PJM will also cancel a scheduled incremental auction if it falls within 10 months of the BRA for that delivery year, Langbein said. He continued that PJM will always conduct a third incremental auction.

PJM will use the January 2021 load forecast for the 2022/23 BRA and the most up-to-date load forecast in future BRAs, Langbein said.

“Our focus has really been on making sure we have all the dates established for the upcoming BRA, but we wanted to get out the subsequent BRA schedules as well,” he said.

The future BRA dates are January 2023 for the 2025/26 delivery year; July 2023 (2026/27) and May 2024 (2027/28).

PJM plans on conducting the BRA six months after the results are posted from the prior BRA, Langbein said, before returning to its normal auction schedule for the 2027/28 delivery year.

Langbein said some of the key pre-auction BRA dates for the 2022/23 delivery year include requests of winter capacity interconnection rights (CIRs) on Jan. 4 and the first-time fixed resource requirement (FRR) election on Jan. 18. Several activities will take place Jan. 19, he continued, including the generation state subsidy certification and the resource specific MOPR exception requests.

“We realize things are going to be a little tight with all the additional activities that normally go on prior to the start of the delivery year,” Langbein said. “But it’s the schedule we’ve come up with based on the timeline we have out there.”

November 24, 2020

‘No Time for Unicorns’ on Climate, Ill. Rep Says

Rep. Sean Casten (D-Ill.), who previously worked as a clean energy consultant and co-founded a company that developed waste energy recovery plants, said his transition from the private sector to Congress in 2018 was “surreal.”

“When I was running clean energy companies with a mission to profitably reduce greenhouse gas emissions we always prioritized the laws of thermodynamics over the laws of man. And in this new line of work, it is considered rare and exceptional to actually insist on what is scientifically necessary,” Casten, who holds master’s degrees in engineering management and biochemical engineering, told the American Council on Renewable Energy’s (ACORE) Grid Forum last week. “For 30 years we have prioritized the politically possible over the scientifically necessary. We do not have another 30 years to wait.”

No Time for ‘Unicorn Sales’

climate change — Rep. Sean Casten (D-Ill.) | *ACORE*

In a keynote speech, Casten called for eliminating the current $615 billion in annual fossil fuel subsidies, which he said “will unleash a ton of private capital.”

Getting to net zero carbon emissions will require the U.S. to double the efficiency of its energy system (energy use per dollar of GDP), which would put the U.S. at Switzerland’s level, he said.

The nation also needs “massive” research and development spending to decarbonize industries. “If you can’t say how you’re going to make steel without metallurgical coke, if you can’t say how you’re going to make fertilizer without natural gas, you are not contributing to the conversation. You are selling the unicorn. We do not have time to be in the unicorn sales business.”

Energy Price Act

Casten has co-authored several pieces of legislation to address the challenge.

The Energy Price Act would clarify that FERC has the responsibility to ensure that public utilities take into account greenhouse gas emissions when setting their electricity rates. The bill, introduced earlier this year, has not seen any committee action. (See related story, FERC, DOE, Interior Keys to Biden Climate Plan.)

“The deployment of clean energy creates huge problems. … Namely, clean energy’s too damn cheap. And every time we deploy a zero marginal cost generator on an electric grid that prices to the highest marginal cost generator, the price of power comes down and the investment thesis gradually erodes for building new assets. What happened to the nuclear industry happened to the cogen industry, and it’s going to happen to the clean energy industry as well,” Casten said.

“When I started my career you could get $60-$70 [/MWh] PPAs. Now you’re lucky to get $20-25 [/MWh] on a spot price market.”

“That creates an awesome problem: How do we better allocate … that economic gain of clean energy [so that it] flows appropriately between consumers and investors and flows to the right assets? What we developed in this Energy Price Act is basically a sense of the Congress resolution, but it was meant to be a shot across the bow … Several of the current [FERC] commissioners have privately been favorably disposed to our approach on that.”

Tradeable Performance Standard Act

Casten said the Tradeable Performance Standard Act , introduced last month, would eliminate about 40% of U.S. net greenhouse gas emissions by 2040 by creating tradeable emission allowances for the electric and industrial thermal energy sectors.

“It’s an idea that we developed way back when RGGI was being negotiated. It essentially recognizes that if you’re going to have a market you have to get paid to reduce carbon the exact same amount you pay to release it, and to recognize that there is always going to be political pressure to provide free allowances.

“We’ve got to get to greenhouse gas pricing, [but] most things that we use to describe carbon pricing fail a really simple market test, which is to say: Does the amount you pay to emit a ton of carbon equal the amount you receive if you reduce a ton of carbon? If you are going to go build a solar panel, a wind turbine or a geothermal plant and you can’t identify a specific cash flow stream that you will realize for reducing that CO2 [and] the guy building a coal plant can’t identify a specific cash penalty, then it ain’t a market.”

Uniform Reporting of Climate Risk

The Climate Risk Disclosure Act, which Casten introduced with Rep. Matt Cartwright (D-Pa.) and Sen. Elizabeth Warren (D-Mass.), cleared the House Financial Services Committee in July 2019 and had a hearing in the Senate Committee on Banking, Housing, and Urban Affairs on Nov. 17. It has 16 Senate co-sponsors and 35 House co-sponsors, all Democrats.

The bill would direct the SEC to develop a consistent set of standards to quantify exposure to, or hedging against, climate risk. Casten likened it to “a FASB for ESG,” referring to the Financial Accounting Standards Board, which sets the Generally Accepted Accounting Principles (GAAP) rules for public U.S. companies, and environmental, social and corporate governance — ways to measure a company’s sustainability and societal impact.

A related bill sponsored with Sen. Brian Schatz (D-Hawaii), the Climate Change Financial Risk Act, would direct the Federal Reserve to conduct stress tests on large financial institutions to measure their resilience to climate-related financial risk.

“There’s lots of subjectivity in financial liabilities, but there are consistent ways that they get reported. And as long as everybody understands that, then [they can price] capital accordingly,” Casten said. Currently, he said, “it’s hard to argue that markets are efficiently allocating capital.”

November 24, 2020

FERC, DOE, Interior Seen as Keys to Biden Climate Plan

With a narrow Democratic lead in the House and Senate control in doubt, FERC and the departments of Energy (DOE) and Interior will have central roles in advancing President-elect Joe Biden’s climate goals, speakers told the American Council on Renewable Energy’s (ACORE) Grid Forum last week.

Rep. Sean Casten (D-Ill.), a former clean energy entrepreneur, said the “just and reasonable” clause in the 1935 Federal Power Act that created FERC was not limited to price.

“Couple that with [EPA’s 2009 finding that CO2 emissions endanger public health] and I think there is a very strong legal argument to be made that FERC has not only the authority, but the obligation, to factor carbon prices into the way they regulate power markets,” said Casten, who serves on the House Select Committee on Climate Change and the New Democrat Coalition Climate Change Task Force.

“Pricing carbon doesn’t provide any cash flow to government. That makes it hard to pass in a democratic body when everybody wants to play Santa,” he said during a keynote speech. “But it makes it much easier to think about how to do that in the context of a FERC hearing that’s saying let’s examine all the equities here. FERC actually structurally is much better suited to deal with carbon policy. My hope is with a fully constituted FERC and a Biden White House, there’s way to really do some things even if we still have a [Mitch] McConnell-led Senate.” (See related story, ‘No Time for Unicorns’ on Climate Ill. Rep. Says)

Fixing Order 1000

The Natural Resource Defense Council’s John Moore said his top recommendation for the new administration is to have FERC advance a transmission rule that addresses the holes in Order 1000, “which everyone at this point knows has not fulfilled its promise.”

Moore, director of the NRDC’s Sustainable FERC program and Climate and Clean Energy program, cited “shortcomings in competition, in cost allocation, in siting large projects vs. small projects.”

“There’s a whole set of topics we could talk about there that I think a new FERC could really robustly address,” Moore said in a discussion moderated by ACORE CEO Gregory Wetstone. “This is the best opportunity we’ve ever seen for DOE [and] the Department of Interior — especially with offshore wind permitting issues — to come together and work cooperatively with FERC on a shared agenda. I think that’s true on a number of different issues, and it’s true in a way that we have not seen with certainly any administration at least since I started [working on] this.”

‘Climate Change Lens’

Ana Unruh Cohen, House Select Committee on the Climate Crisis | *ACORE*

Also participating in the discussion was Ana Unruh Cohen, staff director of the House Select Committee on Climate Crisis, who said every decision by the new administration “is going to go through a climate change lens.”

“My expectation is that all the agencies that are responsible for making these long-term infrastructure siting decisions and permitting are going to put that through the climate scenarios that we know are real possibilities,” she said.

Casten said he was encouraged by reports that the Biden administration will create a central clearinghouse for climate policy to ensure cooperation among FERC, EPA and DOE. Each of the agencies “do little corners of [climate policy and we need to] have them pitch together,” Casten said. “We’ve got to prioritize climate change above all else and stop tolerating the excuses for why we can’t act.”

Legislative Options Limited

During the campaign Biden outlined a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production. But a Republican-controlled Senate and a narrower Democratic edge in the House would likely prevent him from winning approval of such a plan and diminish his ability to include incentives for renewable energy in a new economic recovery package.

Democrats still have a chance at winning effective control of the upper house, with two Senate races in Georgia headed to runoff elections on Jan. 5. Winning both seats would result in a 50-50 tie that would be broken by Vice President-elect Kamala Harris. (See GOP Senate May Limit Biden Climate Ambitions.)

National Vision Needed

Moore said DOE should begin work immediately on “the HVDC moonshot” — a system of HVDC converter and inverter stations to link the interconnections and provide power for EV charging. He said the National Renewable Energy Laboratory and the other DOE labs should help FERC identify “what the real needs are.”

The Eastern and Western interconnection grid studies funded by the America Recovery and Reinvestment Act (ARRA) during the 2007-2009 recession “were great collaborations among many different interest groups that developed plans for … a lower carbon future,” Moore said. “But they really didn’t go anywhere because those plans were completely divorced from existing grid planning. So, I think the next round of grid studies needs to be linked to actionable outcomes through the existing regional transmission organizations and FERC. FERC and DOE could work on portfolio analysis, looking at the areas with the best resources around the country and thinking about what could be done there.”

Biden could also ask FERC to create a new office of transmission planning and oversight “to get more cohesion and control over the planning process so we could integrate more of the Biden administration plans with the FERC-regulated entities of the RTOs,” Moore said. “We need a more coordinated national system for doing this because the worst possible outcome is to have fights over eminent domain in local and regional projects that aren’t really connected to a larger grid vision. That to me is a waste of time”

Macro Grid Studies

During the conference, Americans for a Clean Energy Grid (ACEG) released an international su rvey of “macro grids,” authored by two Iowa State University researchers, which shows that the U.S.’ development of interregional transmission lags far behind that of China, India and the European Union. It followed an ACEG study in October that projected a macro grid that allowed transmission of cheap renewable energy throughout the Eastern Interconnection would create 6 million jobs, cut carbon emissions and save consumers more than $100 billion. (See ‘Macro Grid’ Study Promises Cost Savings, Emission Cuts.)

The studies were part of the Macro Grid Initiative, a joint project of ACEG and ACORE funded by Microsoft founder Bill Gates’ Breakthrough Energ y Ventures, a $1 billion fund whose board members and investors include Amazon founder Jeff Bezos, former New York Mayor Michael Bloomberg, Virgin Group founder Richard Branson and LinkedIn founder Reid Hoffman.

“At the heart of this effort is the reality that the 15 states between the Rockies and Mississippi River account for 88% of the nation’s [onshore] wind potential while 56% of our solar potential is located in that same area. Meanwhile, this region is home to less than a third of the projected 2050 electric demand,” Wetstone explained. “Hence the obvious necessity of moving renewable power from the renewable resource rich part of the country to where the people live. We can do that with a macro grid. We can enhance grid resilience, lower costs and reduce carbon.”

The House Climate committee endorsed the macro grid concept, although it referred to a “national super grid,” Unruh Cohen said.

“To unleash the ambitious plans that the states and utilities already have to shift to clean energy, they really needed the support of an enhanced grid of new lines in some places to bring new resources to demand centers, but also upgrades on the existing footprint in other places to just be able to deal with the dynamism that we see in the grid now, [to] bring on storage, all of those things,” Unruh Cohen said. “And of course, the very important task of resilience, both to climate impacts and other [threats].”

Moore said a larger grid will be needed to support the “tens of millions of distributed energy resources in the forms of cars, trucks and buildings that we see in our future.”

He noted the growth of renewables in the last 20 years from a “niche” to the “huge” presence it now has in SPP, which boosted its record for wind energy with a new peak of 18,442 MW on Nov. 14.

Dying on the Vine

Without substantial new transmission in MISO West Risks Becoming ‘Dead Zone,’ Stakeholders Warn.)

Unruh Cohen said grid improvements “will be right in the mix as we put an infrastructure package together, and I think we can hopefully have some bipartisan support going forward.”

“There are other good reasons to build a grid,” Wetstone added, citing the National Commission on Grid Resilience’s report in August that “has recommendations that are very sympatico” with those who want grid expansions to support climate efforts. Wetstone noted that the commission is co-chaired by Rep.-elect Darrell Issa, a California Republican who will return to Congress in January. (See related story, Retired General Sounds Alarm on Grid Security.)

“When you look at the maps where a lot of these projects are popping up, they don’t look like they’re all in red or blue districts. This is real in a way that we haven’t seen in the past,” said Moore. “So that, plus the COVID crisis, I think, could produce the best possible scenario for something to happen that’s big.”

In the meantime, he said, progress could be made through investment tax credits for transmission and by directing the federal power marketing agencies in the West — Bonneville Power Administration and the Western Area Power Administration — to use their authority to expand the grid.

Moore said the Senate Appropriations Committee bill for 2021 has a section on renewable energy grid integration that includes $10 million for the development of an “energyshed” model to address transmission constraints in renewable-rich areas based on Texas’ Competitive Renewable Energy Zones (CREZ) buildout. “That’s the kind of exciting thing you might see go through even while we’re waiting for the big, comprehensive legislation,” he said.

Coalitions Needed

Unruh Cohen said passing energy legislation will require the kind of broad coalitions that backed the 2007 Energy Independence and Security Act and the Waxman-Markey cap-and-trade bill that cleared the House in 2009 but stalled in the Senate.

Bringing together “clean energy, the environmental community, agriculture — for both of those bills, having the farmers and ranchers who were benefitting from hosting renewable energy — was really critical to putting together a winning strategy,” she said.

November 24, 2020

Texas PUC Briefs: Nov. 19, 2020

The Texas Public Utility Commission last week threatened Texas-New Mexico Power (TNMP) with a “comprehensive” rate case if the utility didn’t remove proposed Tariff language from a proceeding before the commission.

The PUC in August approved TNMP’s settlement agreement for an annual increase of $14.29 million in its distribution cost recovery factor (DCRF). Two months later, it filed in the same docket revisions to its wholesale Tariff for transmission service to correct errors in it (50731).

On Nov. 6, energy storage developer Broad Reach Power filed for relief from TNMP’s distribution service charges being assessed to wholesale storage entities as a result of the utility’s proposed correction. Broad Reach said the changes tucked into TNMP’s proposed correction were “inconsistent” with commission rules and applicable legal standards and asked the PUC for declaratory and injunctive relief and a rulemaking to address the issues (51501).

The developer found a sympathetic ear in PUC Chair DeAnn Walker.

“DCRF proceedings are meant to provide periodic changes to rates to cover distribution investment. This is not what occurred in this instance,” Walker said during the commission’s open meeting Thursday. “The manner in which TNMP chose to try to address it in filing a new Tariff two months later does not comply with the commission’s order. They should have filed a new case to change the Tariff back to what it should have been.

“Now we have pending this new docket, which sets forth various alternatives, none of which I believe the commission has the legal ability to implement, except maybe the rulemaking. We have two dockets that are spending a lot of the commission’s time that are not our core mission.”

Socially distanced PUC staff during the commission’s open meeting | *Texas PUC*

TNMP’s correction added language that would separately meter a storage facility from all other facilities and set the interconnection point at the distribution level.

“The changes proposed to the Tariff for transmission service go well beyond the intent of the statue and the rules allowing a DCRF,” Walker said. She suggested that TNMP and other parties in the Broad Reach proceeding file a petition by Dec. 8 that would remove the troublesome language. If not, she said, she would use the PUC’s Dec. 17 open meeting to require TNMP to file a rate case to address the issue and any others “that may be out there.”

“I want to be clear to all utilities that they are not to abuse the DRCF process or any of these other processes they have gotten through the legislature and through us to give them quick relief,” Walker said.

She also had harsh words for other parties in the proceedings and PUC staff, saying the commission was caught off-guard by the dockets.

“In my view, the system failed the commissioners on this issue. [TNMP] should never have included this request in their application, and the other parties and staff should not have included this change in the Tariff,” Walker said. “I do not believe based on the record of this case that the commissioners were in a position to identify the issue without the input from the parties and the staff. There’s no way the three of us could have ever caught this issue and said, ‘This shouldn’t be in a DCRF.’”

“You can’t sneak it through the way it was sneaked through here,” Commissioner Arthur D’Andrea said. “It embarrasses me that I missed it. It’s still our job. We still signed [the order].”

Hearing on Proposed Entergy Rider

The commission agreed to hold a hearing in December or January on a proposed rider by Entergy Texas for a new gas-fired power plant north of Houston (51381).

Entergy in October filed a request for a generation cost recovery rider to begin recovering a return of and on its capital investment in the Montgomery County Power Station, a 993-MW, combined cycle natural gas plant near Willis. Entergy, which has said the plant’s construction costs will be $937 million, is attempting to collect about $91 million annually from its Texas customers.

The plant was originally expected to be placed in service next June. Entergy now projects the in-service date to be moved up, leading to the PUC’s decision to quickly hold a hearing on the rider.

Walker said she was concerned that in reviewing the case, the utility might have included costs in the rider “more appropriately defined” as operations and maintenance costs.

“I want to be clear to Entergy that they better scrub before the hearing any costs they are requesting,” Walker said. “If they are getting a rider with inappropriate carrying costs, they will have to refund those amounts, and they will have to refund them with carrying costs.”

The plant’s expenses and costs will be part of a future rate case, she said.

Texas Industrial Energy Consumers, the Office of Public Utility Counsel and a coalition of Houston-area cities all requested the PUC hold a hearing on Entergy’s application.

Staff File Enforcement Report

PUC staff filed its annual report on customer complaints and enforcement activities on Nov. 10, listing 6,805 electric complaints during fiscal year 2020. According to the report, staff opened 152 investigations and closed 110, approving orders that resulted in $2.2 million in administrative penalties and $225,000 in refunds.

The commission recently ended Texas Reliability Entity’s reliability monitor contract for the PUC Cancels Texas RE as ERCOT’s Reliability Monitor.)

November 24, 2020April 9, 2024

Overheard at ACORE Virtual Grid Forum

The American Council on Renewable Energy (ACORE) held its 2020 Virtual Grid Forum last week. The two-day event examined the role of regulators, grid operators, electric service providers and the renewable sector as states progress toward their clean energy goals. It also explored the policy and regulatory issues and technology challenges associated with integrating increasingly high penetrations of renewable electricity on the grid.

Following is some of what we heard.

Tackling MOPR Issues

During a panel on capacity market design and the future of resource adequacy Nov. 17, panelists discussed at length the minimum offer price rule (MOPR) as a symptom of outdated design.

Grid Strategies President Rob Gramlich said several states have threatened to back out of capacity markets and that MOPR is not viewed as a “long-term, sustainable approach,” according to PJM, which is “trying to get back into a way that works with states rather than contravening [their] wishes and goals.”

Abe Silverman, general counsel for the New Jersey Board of Public Utilities, said that clean energy policies “are non-negotiable in New Jersey, and we’re not backing off; we’re not slowing down.” Silverman noted New Jersey is also “very active” in current MOPR litigation.

“I think we see MOPR as a symptom of a market design that’s about 20 years out of date,” Silverman said. “These markets were put into place in the early 2000s, and they were great at optimizing cost and maximizing reliability. … They’re very effective at that, but they haven’t been tweaked a lot.”

Clockwise from top left to right: Abe Silverman, New Jersey Board of Public Utilities; Casey Roberts, Sierra Club; Lloyd MacNeil, McDermott Will & Emery; Rob Gramlich, Grid Strategies; and Nora Mead Brownell, EPSY Energy Solutions | ACORE

Silverman said “fundamentally” the question should be: What are these markets doing for states?

“We’re putting band-aids on band-aids, and MOPR is the ultimate band-aid, and it’s not a good one,” Silverman said.

Former FERC Commissioner and Pacific Gas and Electric board Chair Nora Mead Brownell added that capacity markets were supposed to be “a short-term solution.” According to Brownell, another quick fix is additional responsibilities for the RTOs, which have created administrative solutions like MOPR.

“They’re going to be imperfect,” Brownell said. “We can dance on the head of a pin all we want. At some point, there’s going to have to be compromises.”

Brownell said that it needs to be clear that if RTOs are going to have a stakeholder process, “You don’t get everything you want. You look for everything you need. How do we get to a place where we are more market-driven, rather than these endless, litigated, imperfect administrative solutions?”

Silverman said New Jersey also has an ongoing proceeding about whether it should take back resource adequacy from PJM.

“It’s about MOPR, frankly, but it’s also about cost and achieving our clean energy goals faster and at the least cost to our consumers,” Silverman said. “We look to California as obviously the gold standard for driving a clean energy agenda. But it is daunting, and it’s an amazing thing that they’ve done that their reliability has been so good while they’ve been pioneering so many different new technologies and driving the investment.”

ERCOT Example

“Probably the best part of the ERCOT market is that it does allow, or encourages, consumers to moderate their energy behavior,” Silverman said.

Silverman added there is no default service provider in ERCOT, which makes “all things become possible because you have third-party suppliers … who have a million customers so that they can make those kinds of long-term hedging arrangements.” Silverman said most New Jersey customers stay with the default service provider, which was included in restructuring the state’s markets.

“ERCOT took that very bold step 20 years ago of forcing the baby birdie out of the nest, and other states were not willing to go that direction,” Silverman said.

Brownell said she agreed with Silverman that ERCOT took a bold step, but it also had “very strong political and business leaders who made the decision to go to markets fully and stuck with it; they didn’t back off.”

“It’s unbelievable to me in this day and age, and this isn’t this isn’t a knock on New Jersey, [that] the Northeast largely hasn’t deployed [smart] meters and acts as if it needs, you know, one more death-by-pilot [program]. What don’t we know about the value of meters and the data that they produce? It’s a mystery to me.”

Sierra Club Senior Attorney Casey Roberts said it’s tough to get other states to make that ERCOT-type leap. She said PJM recently approved more revenue being recovered through energy and ancillary services (EAS) and less through the capacity market.

“Because of the way the capacity market works as a missing money mechanism, that [decline in capacity costs] should naturally happen as you increase the energy revenues, but less is coming through the capacity market” Roberts said. “So it’s going to be a more slow and painful transition without that kind of the political and business leadership that Nora was talking about. There is already the framework in place to move away from mandatory capacity markets, or at least reduce their relevance in those Eastern markets.”

Gramlich said it does not have to be an all-or-nothing approach. There can be incremental shifts to have more EAS revenue relative to the capacity market with design changes over time.

Roberts added that FERC needs to lead on market design as “people just get stuck in their corners and don’t see how a series of tradeoffs could ultimately lead to a more optimal design.”

Supporting Renewable Expansion

A panel on Nov. 17 led by Heather Curlee, senior counsel of Wilson, Sonsini, Goodrich, & Rosati, explored the concept of establishing power markets to support the expansion of renewable resources.

Robert Stoddard, managing director of Berkeley Research Group, was asked if expanding RTOs and ISOs would be the right approach for continued renewable integration into the system. Stoddard said markets have performed “extremely well” in helping attract and retain investment in a way that has been “sensibly done” and conducted at the risk of the investors instead of ratepayers.

When RTOs and ISOs were created in their current form by FERC Order 2000 in 1999, Stoddard said, it was done as a response to concerns that utilities owning generation and controlling the transmission lines led to “no nondiscriminatory open access to the grid.” Innovation had to come from the utilities, Stoddard said, leaving little room for innovation or risk-taking from outside investors.

Stoddard said markets can create conditions for innovation, and there are many functions of RTOs and ISOs to ensure the open access that allows outside companies to come forward and take risks. He said markets operate through prices, and the prices tell people what is valuable and allow an innovator to look for changes in generation or transmission to create value.

The challenge with RTOs and ISOs, Stoddard said, has been figuring out the best way to put together market prices with the necessity of long-term planning.

“The RTO markets are really good at wresting all of the small efficiencies out of day-to-day operations,” Stoddard said. “Where we’ve had bigger challenges is [in whether] these markets provide the long-term signals not only for generation, but wise transmission expansion.”

Joe Hoerner, senior vice president of regional grid solutions for Portland, Ore.-based Pacific Power, was asked how carbon pricing fits in to help accommodate existing or future state renewable energy goals and whether more transmission is needed to integrate renewables on the West Coast.

Hoerner said CAISO has been “struggling with” the best way to approach carbon pricing. Absent a standardized approach to carbon pricing, a “hodge-podge approach” to pricing could lead to unintended consequences, he said.

As more solar resources are being built in the Southwest, Hoerner said, there are “a lot of eggs in one basket” in the renewable generation mix. He said the reliance on solar is starting to create reliability concerns.

“There’s not enough transmission to make that connection and build that new backbone throughout the West to interconnect all of the solar resources,” Hoerner said. “You really do need to diversify; you need to be able to get to those different assets, and you need the transmission to be able to interconnect all of that”

The panelists were also asked if RTO membership should be mandated on a federal level to create more efficient markets.

Stoddard said the market would work more efficiently if there was mandatory RTO membership, but efficiency would come at some costs. He said one of the biggest sacrifices would come with the loss of local control and oversight of long-term planning.

“A well-designed integrated resource plan is a great thing, but it does put a lot of risk on ratepayers,” Stoddard said.

Bob Helton of ERCOT’s Technical Advisory Committee said he agreed with Stoddard’s description of an RTO mandate, saying states presently get to “pick their own poison” when it comes to deciding whether to join an RTO or ISO or to go out on their own.

Helton said there are pros and cons to each idea, but it’s a decision best made on a local level rather than a dictate from above.

“It would be hard for me to say to mandate anything on anybody at this point,” Helton said.

Hoerner said he doesn’t think RTO membership should be mandated. He said decisions for a “pursuit of perfection” toward a market design can lead to a market implosion and cause more problems.

“When you mandate something, there’s the risk that it gets jammed in or doesn’t get designed properly, and you end up with something that isn’t well-functioning,” Hoerner said.

November 24, 2020

CPUC Tries to Head off Summer Blackouts

The California Public Utilities Commission opened a proceeding Thursday to help prevent energy emergencies next summer like those that occurred in August and September.

The rulemaking is intended to identify and institute near-term measures that could limit energy consumption and boost generation during heat waves that strain the Western grid. California’s rolling blackouts in mid-August were the first since the energy crisis of 2000/01. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)

“Through this proceeding we will identify measures that can be implemented as soon as possible to address reliability for next summer,” Commissioner Liane Randolph said. The CPUC, CAISO and the California Energy Commission (CEC) are working together to ensure reliability going forward, she continued.

Load-serving entities under the CPUC’s jurisdiction are procuring 2,400 MW of new capacity to come online by summer. But the CPUC said additional measures, including enhanced demand response programs, are needed to ensure the state has enough energy to meet demand and maintain reserves intended to prevent a larger grid failure.

CPUC blackouts — CPUC headquarters in San Francisco | © *RTO Insider*

The rulemaking will consider compensating customers for switching to back-up generators during times of strained supply. It will try to reach more residents through advertising and social media to urge them to conserve energy during heat waves. And it will seek increased capacity from the state’s investor-owned utilities by retrofitting generators and increasing efficiency for greater output.

The measures must be approved by April 2021 so they can be implemented by the summer, the CPUC said.

A preliminary root-cause analysis of the August blackouts by the CPUC, CAISO and the CEC recommended that the CPUC update its resource and reliability planning targets to account for extreme heat waves and expedite the development of resources that can come online by summer. (See CAISO Says Constrained Tx Contributed to Blackouts.)

The retirement of fossil-fuel plants and switch to renewable energy left the state short of capacity as solar power waned in the evenings during the summer heat waves. More storage for renewable resources is needed to compensate for shortfalls, CAISO and the CPUC said.

“With respect to updating resource and reliability planning targets to increase supply and account for the state’s transitioning energy mix, this [order instituting rulemaking] will evaluate whether it is possible to increase the month-ahead RA procurement requirement, outside of the current multi-year process, using information provided in the prospective summer assessment report,” the commission’s decision said.

After the blackouts of Aug. 14-15, CAISO reported that large amounts of electricity had been exported on those days. The root-cause report acknowledged the error.

“Under-scheduling of load [by LSEs’ scheduling coordinators] and convergence bidding clearing net supply signaled that more exports were supportable.”

Some critics, including former CPUC president Loretta Lynch, questioned why the ISO had allowed the exports to occur. (See Former CPUC President Calls for CAISO Probe.)

The CPUC said it will address the issue in its rulemaking.

“For purposes of determining when capacity can be exported from the CAISO-controlled grid, particularly during reliability events, a resource that provides RA capacity can be tagged such that it would not be exported during these critical times,” it said.

November 24, 2020January 15, 2025

Experts Urge West to Address RA Shortfall Immediately

Western utility regulators have no time to waste in addressing the region’s looming resource adequacy shortfalls, industry experts said last week.

“Yes, there is a problem, and it’s happening now,” WECC Manager of Performance Analysis and Resource Adequacy Matt Elkins said during the regional entity’s second Resource Adequacy Forum on Wednesday. (See WECC Seeks to ‘Invent’ Future with RA Forum.)

“We saw it in 2020. Our models started seeing this coming a couple years ago. I think everyone started talking about this — ‘Hey, variability is growing’ — and I think we’re there now. I think we need to come together and really figure out how to do this as an interconnection,” Elkins said.

Arne Olsen, senior partner with Energy and Environmental Economics, agreed about the urgency: “It’s a right-now problem, not a five-years-from-now problem.

“All the modeling shows it in California. Our Northwest studies show that the Northwest has a problem. … I don’t know about the Southwest and the Front Range areas, because I haven’t looked at those specifically, but West-wide I think we have a problem,” Olsen said.

California and the Northwest both face immediate capacity needs, experts said during WECC’s Resource Adequacy Forum. | WECC

“In California … our problem is now and is going to get much worse in the future” with the loss of the 24/7 baseload capacity from the 2,256-MW Diablo Canyon nuclear plant, slated for closure in 2025, said Karl Meeusen, CAISO senior adviser for infrastructure and regulatory policy.

What should a regulator do?

“I guess my first advice would be [to] examine very closely the [integrated resource plan] practices of the utilities that are under your jurisdiction. And if you see one of your utilities with a very large short position, then you should be aware that it’s going to be difficult — and perhaps expensive — for them to fill that position over the next couple of years,” Olsen said.

Over the long run, regulators should be looking at what resources their utilities need to serve load “reliably and at a reasonable cost,” he said.

Olsen said that all resources contribute to RA but do so in different ways. While fully dispatchable resources are rated at their nameplate capacity, dispatch-limited variable resources are rated based on their effective load-carrying capability, a measure of a resource’s ability to perform during intervals with a high loss-of-load probability (LOLP).

“The more you have of a non-dispatchable resource, the more apparent their limitations become,” Olsen said, adding that it is best to pair resources such as wind and solar with battery storage, for example.

‘Summer-needy’ Northwest

John Fazio, senior analyst with the Northwest Power and Conservation Council, said his organization has a mandate to produce a five-year regional power plan for Idaho, Montana, Oregon and Washington, the region covered by the Bonneville Power Administration’s hydroelectric system. The council uses annual LOLP as its RA standard, with an expectation of no more than one shortfall every 20 years — which, Fazio clarified, refers to a need for balancing authorities to take emergency actions, but not necessarily initiate blackouts.

With climate change bringing higher temperatures, “we anticipate that during winter, we will see less demand, which is a good thing, and we will also see more snowfall and rain in the system, which is good thing,” Fazio said. On the flip side, earlier snowmelt means the hydro system will have less water in the summer, leaving the Northwest with less energy to export to California. Meanwhile, retirements of coal-fired plants in the region will translate into an increasing LOLP heading into the next decade.

Fazio said the council’s RA standard counts some imports on top of the resources within the Northwest region. “And we’ve had debates about how much we should rely on that — and that is a policy question; that’s not an assessment of what’s physically available, but it’s a question of how much the region wants to rely on that,” he said.

“The challenges that we’re facing now is that we’re seeing this general trend toward warming temperatures, which means that, even though our summer loads may not be as high as our winter loads, the more important thing for us is the gap between the loads and the resources,” Fazio said. “And it looks like the Northwest is moving toward becoming more of a summer-needy region, which means there will be a challenge in the future because both the Northwest and the Southwest may be competing for the resources at the same time.”

Fazio said the council is shifting from using a historical model in its power plans to one based on climate change trends.

Meeusen said California’s approach to RA entails “making sure that resources are not just there but contracted and offered into the market” through month-ahead and year-ahead contracts.

“We really don’t know until 45 days prior to the month which resources we’re going to be relying on,” Meeusen said.

CAISO relies on a stochastic production simulation that allows the ISO to look at load, wind, solar and outages and “see how they work together” and determine risk “if something drops off.”

“The hard part of this stochastic model is, do we have enough,” and if not, what does the ISO need to procure using its backstop authority?

Olsen said regional reserve sharing has the potential to yield “significant benefits.”

“In effect, we’ve kind of been counting on that regional coordination already as we’ve got resource planning throughout the West, but largely in an uncoordinated manner,” Olsen said. Each system performs its own estimate of how much capacity might be available in the market, but it’s difficult to ascertain whether there’s enough available for everyone in the Western Interconnection, he said.

“And that has gotten us into a little bit of trouble. I think this was a good assumption as long as the system had surplus capacity, which it has had for 20 years, but now as we move towards a system with less and less capacity available and some resources are getting retired … it’s difficult to know how much capacity might be available,” Olsen said.

“Which is to say that the way we’ve been doing things for the past several years, really a couple of decades, may not be sufficient to maintain reliability going forward.”

Olsen said he likes the direction the Northwest Power Pool is moving in developing its RA program, noting that it fits with the region’s system of bilateral trading among largely vertically integrated utilities. (See NWPP RA Effort Quickly Ramping Up.)

“If we had just four of those entities, each of them looking after its own region [in the West], and then they could all get together and talk about how much they can lean on each other on a broad regional basis — under the auspices of a WECC task force, for example — that would feel like a good long-term direction.”