Currently, some DERs use the ISO-NE interconnection process, while others use distinct state interconnection processes, a disconnect that the grid operator says “results in multiple coordination problems and inefficiencies that in some cases result in adverse outcomes for DER developers.”
To solve that problem, ISO-NE is proposing that all new DERs proceed through the applicable state processes.
Transmission owners are currently responsible for determining whether new DERs have to use the state or RTO process, and they use different mechanisms and assumptions, ISO-NE said. The large number of DERs coming online has also made it “increasingly difficult for the [TOs] to track the status of thousands of feeders throughout New England.”
During NEPOOL stakeholder meetings, an ISO-NE official called the process “extremely challenging and time-consuming.” (See “DER Interconnection Process,” NEPOOL Transmission Committee Briefs: March 23, 2022.)
ISO-NE requested that its tariff revisions become effective on Aug. 28.
MISO is currently evaluating five new recommendations from its Independent Market Monitor that include transmission reconfiguration plans, reducing out-of-market commitments, a future-looking dispatch model and ensuring the RTO only pays for real load reductions.
Monitor David Patton, Potomac Economics’ president, issued five new recommendations last month as part of his 2021 State of the Market report.
The Monitor says MISO should:
work with its transmission owners to identify and implement economic transmission reconfiguration plans to better manage congestion;
evaluate and restructure its unit commitment process to reduce out-of-market commitments and ensuing make-whole payments;
develop a multi-hour, look-ahead dispatch and commitment model to better manage fluctuations in net load and decisions on using storage resources;
improve rules around demand participation in energy markets so that MISO only pays for load reductions that occur; and
consider classifying load-modifying resource (LMR) curtailments as short-term demand in pricing models and the unit dispatch system.
The last recommendation comes after Patton noticed that LMRs are allowed to set real-time energy prices long after emergency conditions have passed. He said that’s because of MISO’s extended marginal locational pricing (ELMP) model respecting resources’ ramp rates, which makes it impossible to replace a large volume of LMRs within a single dispatch interval. He said if the RTO would treat LMRs as an operating reserve demand in the ELMP model, it would eliminate the need for other resources to ramp up and replace them.
Patton said he also believes an hours-ahead dispatch model will be a “key component of the MISO markets’ ability to economically and reliably manage the transition of its generating portfolio.”
MISO’s out-of-market commitments and the associated revenue sufficiency guarantee costs increased “substantially” in 2021, Patton said in calling for staff to examine their commitment process.
“Our analysis indicated that most of these commitments were not ultimately needed to satisfy MISO’s energy, operating reserves and other reliability needs,” he said.
Finally, Patton said MISO should get a better handle on its demand response resources.
“In the past few years, we have identified a number of cases where demand response resources or energy efficiency resources were paid substantial amounts for load reductions that were not realized,” he said in the report.
While he said some of the problem is because of “conduct of the resources,” he also said some of the issue can be ascribed to “suboptimal tariff and settlement rules.” MISO could use better settlement calculations “to ensure that the estimated load reductions truly represent the additional load that would have existed but for the demand response resource,” Patton said.
MISO is set to review with stakeholders the report’s recommendations and its initial response during an Oct. 13 Market Subcommittee meeting. MISO spokesperson Brandon Morris said the grid operator’s executive leadership will deliver a formal response to the recommendations during the Board of Directors’ Markets Committee meeting in early December.
Under its tariff, the RTO has 120 days to make a public response to the annual report’s recommendations.
In the meantime, MISO and its transmission owners continue closed door meetings of the new Reconfiguration for Congestion Cost Task Team (RCCTT) that was formed at the beginning of the year. The group focuses on plans to reroute transmission flows during times of heavy congestion costs and could address Patton’s first recommendation. (See “RTO Forms Task Team for Tx Reconfigurations,” MISO Planning Subcommittee Briefs: Feb. 8, 2022.)
The nonpublic RCCTT maintains a monthly list of the footprint’s top congested constraints.
Some stakeholders have said MISO is about a decade away from significant new transmission that can manage increasing congestion. Reconfiguration plans are desperately needed in the interim.
Patton delivered a state-of-the-market presentation last month where he focused on his longstanding recommendation that MISO adopt a sloped demand curve in its capacity auction. (See MISO Warming to Patton’s Sloped Demand Curve.)
The non-utility owner of a Washington gas-fired power plant says the facility faces unfair treatment under the state’s pending cap-and-trade program, scheduled to go into effect at the start of next year.
Representatives of Grays Harbor Energy Center, owned by independent power producer Invenergy, voiced concerns last month that the 620-MW plant will not receive an initial allocation of free cap-and-trade allowances from the state, unlike utility-owned generators in Washington.
“All the state’s power plants need to be on the same footing,” Grays Harbor Energy representative Torey Mielke said during a June 21 public hearing to discuss cap-and-trade program rules, which are being developed by Washington’s Department of Ecology.
Plant manager Chris Sherin contended that the state’s other natural gas power plants produce 35% more carbon emissions on the average than Grays Harbor Energy Center.
“The Washington Climate Commitment Act is structured to allocate no-cost allowances directly to utilities. Utilities may then use those no-cost allowances for compliance under the law for the emissions from utility-owned natural gas facilities or other sources,” Invenergy told NetZero Insider in an email. “Grays Harbor Energy Center, which is the state’s least carbon-intensive natural gas facility, is not eligible to receive no-cost allowances directly as it is an independently owned natural gas facility.”
Grays Harbor Energy officials have also expressed concern about their plant having to compete with out-of-state power producers that don’t have to spend money on carbon-combating measures that are required in Washington.
The Ecology Department acknowledged that Grays Harbor Energy is the only gas-fired power plant in Washington that is not owned by a public utility, which means it does not receive the same no-cost carbon allowances as the utility-owned power plants. The carbon emissions are calculated the same way for both utility-owned plants and non-utility-owned plants, they noted.
There is a chance that Grays Harbor could lobby the legislature to make the financial aid the same for both types of gas-fired plants, the agency said.
Rules Take Shape
The details of Washington’s new cap-and-trade program will continue to be tweaked until it goes into effect on Jan. 1, 2023.
The Department of Ecology held a series of public hearings last month to help nail down the regulations to implement the Climate Commitment Act, passed by the legislature last year.
Changes made so far to the regulations include requiring participants to be subject to Washington’s courts and state administrative tribunals in disputes, said Kay Shirey, the project’s rule development leader at the Ecology Department.
About 25% of Washington’s carbon emissions won’t be covered by the cap-and-trade law, Shirey said. These include emissions from agriculture, businesses emitting fewer than 25,000 metric tons of carbon a year, landfills, aviation and most marine vessels.
Washington was the second state to adopt a cap-and-trade law after California, which is in a cap-and-trade pact with Quebec. Washington’s auctions will be handled by the Western Climate Initiative (WCI). No timeline has been set for Washington to link up with the WCI.
A 2021 Ecology Department report put the state’s CO2 emissions at 99.57 million tons in 2018. A state law calls for overall emissions to be reduced to 50 million tons by 2030, 27 million tons by 2040 and 5 million tons by 2050.
Under cap-and-trade, carbon emitters would have to acquire allowances for specific amounts of carbon pollution, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions would decrease over time.
The Ecology Department’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of allowances 60 days prior to the auctions.
Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the California-Quebec pact, it would expand its purchase and trading territory to those two areas.
For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state.
The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.
Bidding companies are limited to acquiring 4% to 10% of the total number of allowances, depending on various criteria.
Companies will also be allowed to bid on offset credits that are used to preserve urban and rural forests, which absorb carbon from the atmosphere.
Washington has already begun selling forest-related carbon credits. The Washington Department Natural Resources’ duties include managing the state’s trust lands with the mission of producing revenue from property for various programs such as education. The agency routinely auctions off trees on its lands to be harvested for timber.
A new DNR program will set aside 10,000 acres of forests — with trees that began growing prior to 1900 — that have the potential to be harvested. Offset buyers will bid on carbon credits to keep those carbon-absorbing forests intact. This enables the DNR to achieve its mission of producing revenue from its older forests without having to harvest them for timber.
The new state program has identified 2,500 acres on DNR trust lands to be set aside this year in Whatcom, King, Thurston and Grays Harbor counties, stretching from northern to southern Puget Sound. Another 7,500 acres are scheduled to be identified next year.
Regen is collecting carbon credits from King County to offset its contributions to greenhouse gas pollution elsewhere when its overall carbon footprint is calculated.
The New Jersey Board of Public Utilities (BPU) on June 29 agreed to hear a petition filed by developer Ørsted seeking to override Cape May County officials who it says have not responded to its efforts to secure local approvals for the Ocean Wind 1 offshore wind project.
Ørsted is seeking approval to run an underground transmission line from its turbines to the shoreline at Ocean City to a substation in the next town, including through land owned by Cape May County. The developer is seeking to secure permission under a new law passed by the legislature last year and enacted in July that gives the BPU authority to override local government officials in land-use questions concerning offshore wind projects if the board finds that the land is “reasonably necessary” for the project’s construction.
The five-member BPU voted unanimously at its monthly meeting to take up the case and assigned board President Joseph Fiordaliso as the hearing officer.
The Ocean Wind 1 petition follows a similar petition filed by Ørsted in March seeking to override officials in Ocean City who oppose the project. The BPU on June 24 held closing arguments in that case. (See NJ City Calls for Delay to Ocean Wind 1.)
The Ocean City case is the first test of the new law, which was enacted in July, and both cases could provide a roadmap for the difficulties facing other projects in the future. The 1,100-MW Ocean Wind project, which was approved in 2019, was the first of three approved offshore wind farms by the state so far. The BPU has also approved the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores, and the state expects to hold three more solicitations for a total of 7,500 MW by 2035.
Obtaining Consent
Ørsted’s latest petition states that in order to advance, the project needs to obtain “certain easements” across property owned by Cape May County and “certain consents” from the county. The project needs a temporary 18-month easement and a 30-foot wide permanent easement, both in Ocean City, the developer’s May 20 petition says.
The project also needs the county’s consent as part of the application for 10 permits needed for the project to advance, the petition says.
Ocean Wind “must have the legal authority and/or consent from Cape May County to perform the project activities on the properties owned by the county,” it says. “Cape May County has been unwilling to provide consents needed for any [New Jersey Department of Environmental Protection] permit applications.”
In a June 7 motion asking the BPU to decline and dismiss the petition, Cape May County argued that Ørsted’s move was premature. Although the new law requires the offshore wind project to make its request to the local government and then wait 90 days for a response before filing any petition, the developer had made only “vague, ambiguous and expressly conditional” requests that don’t meet the definition of “request” under the law, the county said.
Ocean Wind 1 “has not supplied all required information and documents in order for the county to provide consent,” the county also said.
Michael Donohue, the attorney for Cape May County, told RTO Insider that the county is “not against wind-generated electricity.”
“Living in one of the last nearly pristine environments in the state, the people of Cape May County are all extraordinarily engaged when it comes to preserving that environment and its flora and fauna,” he said. “The county is not attempting to delay project approvals.
“The brand new statute in question seeks to transfer the authority of the five, duly elected County Commissioners to the unelected members of the BPU,” he said. “We think it is important that any process that leads to such a result be fair, impartial and unbiased and that it should afford the people of the County of Cape May substantial due process.”
Responding to Cape May’s argument in a June 20 brief, Ørsted said it had been in discussion with the county for two and a half years, and the county had no basis for claiming that the request lacked specificity. The country’s motion to dismiss was “little more than an attempt to delay” the project, the company said.
“The county’s arguments and certification alleging the inadequacy of the [petition] rest not on objective facts, but rather on subjective conclusions that the notice was inadequate,” Ørsted said. The developer added that the law does not require it to “request” the environmental permitting consents, only to “consult” with the county, which Ørsted did in “various meetings and correspondence with the county.”
PSE&G Infrastructure Spending
The board also approved Public Service Electric and Gas’ (NYSE:PEG) Infrastructure Advancement Program (IAP), in which the utility will spend $511 million over four years to replace aging electric equipment, upgrade substations and install electric vehicle infrastructure.
The last of those will “begin preparing the grid for the rapid transition to EVs and enable a greater blend of renewable energy resources by increasing the reliability of the state’s electric grid down to the street and neighborhood level,” PSE&G said in a press release.
The proposal will cost the typical residential electric and gas customer about $1.50/month in 2026, PSE&G said.
PSE&G initially petitioned for an expenditure of $850 million, starting in 2022 and concluding in 2026, with about 85% of the funds to go to electric projects and the remainder for gas projects, the BPU order approving the program said.
New York Gov. Kathy Hochul signed a climate-related legislative package Tuesday that includes bills to align building codes with state climate law and authorize utilities to operate thermal energy networks.
The Advanced Building Codes, Appliance and Equipment Efficiency Standards Act (A10439/S9405) will update New York’s codes to help reduce greenhouse gas emissions in the building sector, which is the state’s largest contributor to emissions.
“We are going to save $15 billion, which includes $6 billion for low- and moderate-income households at a time when that is so critically important for them,” Hochul said at the bill signing ceremony in Brooklyn. “Stronger energy codes also will give us $2.5 billion in lifetime savings for homeowners.”
The act establishes a new definition of life-cycle cost for regulators to consider when making any potential amendments to the state’s energy conservation construction code. That definition requires regulators to consider the estimated cost of acquisition, operation, maintenance and construction of an energy system for the life of a building.
In addition, regulators will have to ensure that efficiency standards and regulations do not increase emissions of co-pollutants or burden environmental justice communities.
Meanwhile, the Utility Thermal Energy Network and Jobs Act (A10493/S9422) authorizes New York utilities to own and operate thermal energy networks and sell the energy to consumers. Under the law, the Public Service Commission must initiate a proceeding this fall to support thermal network deployment.
Thermal networks are defined in the legislation as the infrastructure that supports utility-scale projects supplying energy from piped, noncombustible fluids for building heating and cooling. State utilities now have three months to submit proposals to the commission for at least one, and up to five, thermal network pilot projects.
For projects developed under the law, utilities will have to demonstrate that they have signed an organized labor agreement, with job priority given to workers at risk of losing their jobs from the downsizing of the gas transmission and distribution system.
Hochul also signed a bill (A.9598/S.8648) that amends the state labor law to ensure that renewable energy systems workers receive prevailing wages for projects with a capacity of 1 MW or more. The previous wage standard applied to projects of 5 MW or more.
“It is critical that workers in new green industries are paid a fair wage and that workers in the fossil fuel industry are not left behind,” John Murphy, international representative for the United Association of Pipe Trades, said during the signing ceremony. A coordinated effort between union leadership and state legislators ensured that “labor standards are front and center in these climate bills.”
Crypto Bill
A cryptocurrency mining bill (A07389/S06486) that passed the New York legislature in the final hours of its session in early June was “missing” from Hochul’s climate package, according to a statement from the advocacy group Seneca Lake Guardian.
“In the middle of a climate crisis, New York cannot allow fossil fuel plants to reopen as gas-guzzling crypto-mining cancers on communities, accelerating climate change just to make a few rich people even richer,” the group said.
The bill would put a temporary moratorium on cryptocurrency mining operations that use an authentication method called proof-of-work (PoW) to validate blockchain transactions.
On June 30, the New York Department of Environmental Conservation denied an air permit renewal for Greenidge Generation’s PoW crypto-mining operation in Torrey, saying that it is “inconsistent” with the state’s climate law.
The natural gas power plant that supports Greenidge’s operations has transitioned from supplying power to the grid to “primarily” providing behind-the-meter power for the mining facilities, the department said.
Under the cryptocurrency bill, the department would develop a generic environmental impact statement for crypto-mining to help the state understand the effects of the PoW technology on energy use.
The leadership for the U.N.’s 27th Climate Change Conference of the Parties (COP27) is preparing a new guide for Paris Agreement signatories on just financing that it will release at the conference in Sharm El-Sheikh, Egypt, this fall.
“The idea is to capitalize on the needed interplay between different stakeholders in order to promote an actionable climate agenda and achieve scale financing,” Nada Tawfik, senior adviser for strategic planning at Egypt’s Ministry of International Cooperation, said Wednesday.
The Sharm El-Sheikh Guidebook for Just Financing will highlight the role in global climate financing of different stakeholders, such as multilateral development banks (MDBs), philanthropies, private-sector entities and climate funds, said Tawfik during an E3G-hosted webinar for London Climate Action Week.
Key goals of the guide are to: map the global climate finance landscape; identify key stakeholders and their complementary roles and competitive edge; and target priority sectors that have a direct impact on accelerating climate action.
“Recent statistics have … shown that the climate financing that has been mobilized in 2021 mainly was targeting [greenhouse gas emission] mitigation sectors,” Tawfik said. “In this guidebook, we aim to strike a balance between adaptation and mitigation and pinpoint opportunities to accelerate climate action.”
The guide will provide an international framework for climate action that applies to all developing and emerging counties, while also detailing implementable regional actions.
“The role of the different stakeholders would be important for creating an enabling environment for climate investment, enhancing the invest-ability of green projects and thinking of innovative ways to de-risk investments and bring in financing at scale,” Tawfik said.
The COP27 presidency’s preparation committee is holding discussions now with multiple stakeholder groups, which includes MDBs, to discuss “a pipeline of implementable projects on the national level” for the guide, she said.
Key Strategies
In preparing the guide, the COP27 leadership wanted to show how MDBs can instigate investments by the private sector.
“MDBs play an important role in providing financing and technical support; however, this financing is not enough to meet the recent estimates of more than $4 trillion in order to finance the [global] climate action agenda” through 2030, Tawfik said.
An MDB is a financial institution established by a group of countries to support developing countries. The U.S., for example, is a member of five MDBs, which include the World Bank, Inter-American Development Bank, Asian Development Bank, African Development Bank and European Bank for Reconstruction and Development (EBRD).
Nationally determined contributions (NDCs) and long-term low GHG emission development strategies, as the building blocks of the Paris Agreement, are important levers in MBDs’ ability to support developing countries. An NDC, which is a five-year climate plan of a party to the Paris Agreement, does not have the time frames that MDBs need to plan for climate investments, according to Jan-Willem van de Ven, head of international climate policy and engagement at EBRD.
“It’s very good that the Paris Agreement found this instrument of long-term strategies [LTSes], because the long-term strategies are where the analysis, synthesis and objectives can come together on a longer time pathway,” van de Ven said. “We know that if [MDBs] invest in infrastructure, these are typically investments with payback times of more than 10 years.”
The current challenge, he added, is that more countries need to “ramp up” work on their LTSes and submit them to the U.N.
To date, 51 countries have submitted an LTS, and only 30 of those are countries with coordinated economic development goals as members of the Organization for Economic Co-operation and Development, according to Marcela Jaramillo, senior associate at the 2050 Pathways Platform. The U.S. submitted a pathway for net-zero GHG emissions by 2050 during COP26 last fall.
An additional 60 countries are working on their strategies, and Jaramillo says many of those governments expect to submit a strategy in September. Others in that group may continue to work on their strategies and present them at the 28th Conference of the Parties (COP28) in 2023 in Dubai, United Arab Emirates.
“The LTS process really takes time to bring everyone to the table, build consensus and have conversations on this vision of the country,” Jaramillo said.
The U.N. climate change secretariat will release a report on all the strategies submitted by September for review at COP27. That report will allow parties to the Paris Agreement to look at the strategies in relation to the goal of holding global temperature rise to below 1.5 degrees Celsius, said Tom Evans, a researcher at E3G.
It will take another year, however, to really understand the scope of LTSes and their impact. Evans sees COP28 as the next “important moment” for working on those strategies and giving parties clear instructions for moving their climate goals forward.
Before the U.S. Supreme Court ruled Thursday to limit the Environmental Protection Agency’s ability to regulate carbon emissions from existing power plants, the White House released a fact sheet announcing that 61 major hospitals and health sector companies had pledged to cut their greenhouse gas emissions 50% by 2030.
These commitments, from some of the country’s largest hospital systems, came in response to the administration’s Health Sector Climate Pledge. With the health care sector accounting for 8.5% of the nation’s GHG emissions, the fact sheet said, the administration “is committed to using every available tool to protect public health, while moving full-speed ahead with our mission to tackle the climate crisis.”
Exactly what those tools might be, how they might be used and the role of the private sector in the fight against climate change quickly became a central theme in the administration’s response to the court’s ruling in West Virginia v. EPA.
In a statement Thursday, Biden promised continued action on climate, including a careful review of the decision to “find ways that we can, under federal law, continue protecting Americans from harmful pollution, including pollution that causes climate change.”
EPA Administrator Michael Regan: “The markets have already spoken.” | PBS
EPA Administrator Michael Regan and National Climate Advisor Gina McCarthy amplified the administration’s stand in media appearances. Speaking on PBS New Hour on Thursday, Regan called the ruling “devastating” and “frustrating,” but said his agency still has the authority to regulate climate and “health-based pollution” from power plants.
“We have just lost some flexibility there,” he acknowledged, adding, “we’re hoping that, when they [generation operators] look at the regulation of waste and discharges in water, climate pollution, health-based pollution, they will see that it’s not worth investing in the past and they will continue to do what they’re doing now, which is invest in the future.
“The market is already moving in this direction. And it’s our obligation as the government to be able to provide some certainty, so that they can make longer-term investments,” he said.
In a June 28 interview with Time magazine, McCarthy anticipated the court’s ruling, saying the administration would need to find “creative” ways to continue the climate fight.
“It can’t just be about using regulations or using Congress to fix this,” said McCarthy, who headed the EPA during the Obama administration, when the agency proposed the Clean Power Plan rejected by the court. She pointed to Biden’s ongoing engagement with the private sector — the health care industry, for example — and the use of its own purchasing power and the Defense Production Act to promote investment in clean energy. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)
“We’re making significant progress on the transition to clean energy, and that is not going to live and die by the Supreme Court’s decision,” she said.
The former EPA administrator was even more outspoken in a June 30 interview with CNN following the ruling. While the decision “sent a signal that the Supreme Court is interested continually in going backwards instead of forwards … the private sector is all in on this transition to clean energy because it makes them money,” she said. “And we’re interested in it because it creates jobs, it lowers costs for families that are trying to struggle with energy costs today … and we’re succeeding, which is why this decision actually happened.”
Separation of Powers
The Clean Power Plan sought to cut power sector carbon emissions by 32% compared with 2005 levels by substituting coal-fired generation with natural gas and renewables. The court’s 6-3 ruling voided the CPP, saying that without “clear congressional authorization,” EPA lacks authority to compel generation shifting to reduce carbon emissions. (See Supreme Court Rejects EPA Generation Shifting.)
The immediate impact of the ruling is minimal, as the Clean Power Plan was withdrawn by the Trump administration, and the Biden administration has said it would not attempt to implement it. Moreover, the Biden administration says the electric industry achieved the CPP’s emission limits a decade ahead of its 2030 deadline, without the regulation.
But as the latest in a series of orders by the conservative-dominated court to limit executive agencies’ discretion, it could act as a constraint on any future EPA action.
Noting that the decision is rooted in the concept of separation of powers, industry analysts ClearView Energy Partners said going forward, EPA “policy ambitions are limited to clearly expressed congressional authority.”
Similarly, in a post-decision blog, Jay Duffy, an attorney with the Clean Air Task Force, said the ruling takes generation shifting, the “most efficient, cost-effective emissions reduction measure off the table.”
But Duffy says the decision does uphold an essential tool for the EPA – its right to regulate carbon dioxide from power plants under the Clean Air Act. The agency has “ample authority to set stringent existing source standards based on directly applied pollution control technologies and techniques, such as carbon capture and sequestration and co-firing with zero-carbon fuels,” he said.
Market mechanisms, such as emission trading — “as long as the trading is between power plants in the [same] source category” — could also be available, Duffy said.
Echoing Regan, ClearView pointed to EPA’s ability to tighten rulemakings for health-based and other pollution — such as mercury and wastewater — that “could make the operation of coal plants more expensive.” But ClearView cautions, in light of West Virginia v. EPA, Regan “may be well-served to downplay any potential climate ‘co-benefits’ associated with incremental tightening of those regulations and clearly articulate the wisdom and affordability of tightening each for their own sake.”
West Virginia v. EPA has also intensified calls for congressional action on clean energy, specifically the portfolio of clean energy tax credits from the failed Build Back Better Act, now being renegotiated in the Senate. With the midterms looming and gas prices and inflation still high, the likelihood of Senate Democrats hammering out a compromise that can gain the support of party conservatives — particularly Sen. Joe Manchin (D-W. Va.) — and House progressives seems tenuous at best.
Private Sector
The private and tech sectors, which invariably move faster than regulators or law makers, are now providing major momentum for the clean energy transition, a momentum Biden clearly wants to accelerate and leverage.
In another pre-decision fact sheet, the White House heralded more than $700 million in private sector investments in electric vehicle charging manufacturing in the U.S., which would produce about 250,000 EV chargers per year.
Such investments have been catalyzed, the fact sheet said, by the $7.5 billion for EV charging infrastructure in the Infrastructure Investment and Jobs Act and the president’s goal of having electric vehicles make up 50% of new car sales in the U.S. by 2030. State policy, like California’s target of ending all sales of new gas-powered vehicles by 2035, are also moving the market.
The fact sheet cited a $450 million investment by Electrify America to expand its network of fast chargers with a “rapid deployment of up to 10,000 ultra-fast chargers at 1,800 charging stations, more than the number of high-power chargers available in the United States today.”
Technology giant Siemens has also invested $250 million to increase its U.S. manufacturing capacity, with the goal of producing one million chargers over the next four years.
While policy can be a drag on the private sector, it has rarely stopped it. Or as McCarthy said on CNN, “The private sector isn’t sitting around twiddling its thumbs about one provision in the Clean Air Act. It is worried about moving forward to capture the clean energy market of today.”
MidAmerican Energy will pay $82,000 to the Midwest Reliability Organization for violating NERC’s reliability standards, according to a settlement between the utility and the regional entity approved by FERC on Thursday (NP22-25).
The settlement between MRO and MidAmerican was part of NERC’s monthly spreadsheet notice of penalty, filed on May 31. In its filing Thursday, the commission said it would not further review the agreement, or the others filed in the SNOP, leaving the penalties intact. Commissioner Allison Clements did not participate in the decision.
MRO Knocks MidAmerican for Misratings
MidAmerican’s violation concerns FAC-009-1 (Establish and communicate facility ratings), which was active from 2007 until 2012, when it was replaced by FAC-008-3 (Facility ratings); the latter standard was in effect when the utility discovered the violation.
Requirement R1 of FAC-009-1 makes transmission owners and generator owners responsible for establishing facility ratings for their “solely and jointly owned facilities that are consistent” with an established facility ratings methodology (FRM). MidAmerican reported in June 2018 that it was noncompliant with this requirement and had been since the standard became enforceable in 2007.
The utility reported that it had identified 21 facility ratings errors during an internal review, later expanded to 89 errors after an extent of condition examination. MidAmerican’s FRM required that it base facility ratings on the “most limiting element of a facility,” which was not done at the affected facilities because of oversights. In some cases, the utility “failed to consider industry standards for substation bus design … and for reducing equipment loss of life.” In others, MidAmerican changed its field equipment but neglected to update the documentation used for ratings.
MidAmerican’s mitigation steps included updating all its facility ratings. This resulted in reduced ratings for 62 facilities, including one whose summer normal rating was lowered 5% while its winter rating was reduced 20%. The other 27 ratings were increased. The entity also overhauled the checklists for its substation engineering quality assurance review, trained personnel on the changes, and implemented annual field reviews, starting in 2018.
MRO decided that the violations comprised a “moderate” but not a “serious or substantial” risk to BPS reliability. While the RE acknowledged that operating a facility above the rating of its most limiting element could damage that element and possibly lead to failure, in practice none of the misrated elements experienced enough flow to cause problems during the 12 years the utility was in violation. For the underrated elements the danger was even less, because the misratings “resulted in overly conservative operation of the facilities.” No harm has been attributed to the violation.
Army Corps Failed to File Models
The SNOP also included a settlement between SERC Reliability and the U.S. Army Corps of Engineers (USACE) for violations of reliability standards in USACE’s Savannah, Mobile, and Wilmington districts. No monetary penalty was assessed for these violations.
The same two standards were at issue in all three cases: MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/var control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions). SERC discovered that Savannah and Mobile were in violation of both standards during compliance audits in 2018; Wilmington notified the RE of its infringement in 2020.
Requirement R2 of MOD-026-1 requires GOs to provide transmission planners a verified excitation control system and plant volt/var control function model; under MOD-027-1, requirement R2 mandates that TPs be provided a verified turbine/governor and load control or active power/frequency control model. The implementation plans for the standards set deadlines for achieving certain percentages of compliance. Violations began in all three cases on July 1, 2018, when the GOs were to have provided the needed data for at least 30% of applicable units.
SERC determined the cause of the violations to be ineffective resource management in the case of USACE-Savannah, and management oversight for the other two districts. But the description of the error was the same for each district: The managers “failed to allocate sufficient manpower and resources dedicated to track and maintain NERC compliance.”
The districts also implemented the same mitigation strategies. Each one created a team dedicated to compliance monitoring; established a central electronic repository for evidence and documentation; performed model verification testing for the relevant standards; and submitted model verification data to their TPs.
SERC had planned to resolve the violations as compliance exceptions, which can be recorded and mitigated without triggering formal enforcement actions. However, the RE decided to elevate them to settlement agreements and file the infringement with FERC because the utilities were unable to meet their initial goal of completing the mitigation plan by December 31, 2021, and requested a 12-month extension.
VALLEY FORGE, Pa. —American Electric Power (NASDAQ:AEP) has identified vegetation as a likely cause of the transmission line failures that left more than 240,000 customers in Ohio without power for up to two days following violent storms in June, PJM officials said last week.
PJM ordered load sheds on three of AEP’s 138-kV lines to prevent overloads and cascading outages June 14 after a storm identified as a derecho downed power lines. (See AEP Under Fire as Load Sheds Persist in Ohio.)
Although the cause of the line tripping remains under investigation, AEP said vegetation was a contributing factor, Paul McGlynn, PJM executive director of system operations, told the Markets and Reliability Committee on Wednesday. “Whether vegetation was blown into the lines or whether there were encroachment issues, we don’t have the answers yet,” he said.
Monday, June 13: Load Forecast Falls Short
McGlynn and other PJM officials gave the MRC an in-depth briefing on the RTO’s challenges in mid-June, which began Monday, June 13, when load peaked around 136 GW, well above the forecasted 128 GW. McGlynn said PJM’s under-forecast was 1,800 MW during the “valley” overnight, rising to 8,000 MW by noon.
The load forecast fell short because of weather that was warmer and more humid than expected, and storms expected to provide cooling did not arrive until after the evening peak. “If we had perfect weather knowledge, [the load forecast] would have been spot on,” McGlynn said, citing backcasts the RTO did after the event.
The RTO also saw generation losses of about 1,150 MW and a constraint, followed by an overload, on the 500-kV Peach Bottom-Conastone line that impacted what resources the RTO could bring online. It responded by taking transmission loading relief procedures, “something we don’t do all that frequently,” said McGlynn.
It also called on little-used combustion turbines to maintain reliability. The RTO activated almost 26,000 MW of CTs, versus the 16,000 MW it had expected to use.
“It was tighter than we anticipated, but we were reliable through the whole operating day,” McGlynn said. The result was “some fairly high prices through the peak period.” LMPs peaked at $2,643/MWh in the 4-5 p.m. ET hour.
Independent Market Monitor Joe Bowring said PJM exported about 4,000 MW to MISO “when it was economically illogical.”
“We will investigate the reasons,” he said in an email after the meeting.
PJM dispatch also approved 35 shortage intervals between 2:55 and 6:05 p.m., said Phil D’Antonio, director of energy market operations.
“I’m surprised we would dispatch so tight to the timing of a thunderstorm,” said Public Service Enterprise Group’s Gary Greiner.
“Storms are sometimes a challenge to predict as to when they will occur” and where, McGlynn responded.
Tuesday, June 14: Storms Down Lines, Poles
When the storms finally arrived late Monday night and continued into Tuesday morning, they were violent and set off tornadoes in Ohio, McGlynn said. AEP Ohio reported wind gusts as high as 95 mph, which downed poles and lines across its service territory.
Between 1 and 2 p.m. June 14, nine 138-kV facilities tripped in the AEP zone, with loads on several facilities above their load dump rating.
Timeline of performance assessment intervals, June 14-16. | PJM
Beginning at 2:02 p.m., PJM issued the first of several load-shed directives to AEP, triggering performance assessment intervals (PAIs), in which capacity resources face penalties for shortfalls in output.
Fearing multiple cascading overloads, the RTO also called on pre-emergency and emergency demand response in the Marion area of AEP at 3:50, followed at 7:21 by an additional load-shed directive to prevent a potential N-5 cascading outage on the 138-kV Beatty-Bolton line.
Wednesday June 15: More Line Failures
In the early morning hours of June 15, AEP returned to service several lines that had tripped the previous day. PJM cancelled its load-shed directive at 3 a.m.
But over a 10-minute period ending at 10:40 a.m., three 138-kV lines in AEP tripped. PJM issued a load-shed directive to relieve an overload on the 138-kV Gahanna-Hap Cremean line at 10:41, just a minute before that line also tripped, triggering another PAI.
At virtually the same time, AEP restored service to the 345-kV HyattCS-Hayden line, which had been recalled on Tuesday from a maintenance outage. McGlynn said the timing of the restoration was a coincidence and that officials don’t know whether an earlier restoration might have prevented the Gahanna-Hap Cremean overload. “It’s certainly something we’re looking at,” he said.
At 10:50, PJM again called for pre-emergency and emergency DR in the Marion area, followed 50 minutes later by another load-shed directive issued to prevent a potential N-5 cascading outage for the 138-kV Kenney-Roberts line.
It wasn’t until 10:25 p.m. that several lines returned to service and load decreased enough to end the load-shed directives and the PAI.
Thursday June 16: Hot Weather Alert
On Thursday, June 16, PJM issued a hot weather alert for the western part of the RTO. At 10:36 a.m. the 138-kV Corridor-Blendon line, which had tripped the previous day, tripped again, but there was sufficient generation to control the constraint.
PJM used contingency switching where it was able to manage thermal loading. But as load continued to increase, PJM — with no generation or switching available — issued several post-contingency local load relief warnings.
After the 138-kV Corridor-Morse line tripped about 12:18 p.m., PJM again called on DR for the Marion area about 12:30, initiating another PAI. The DR was canceled about four and a half hours later, following the return to service of the 138-kV Bexley-St. Clair and Morse-Spring Rd-Genoa lines.
In total, about 100 MW of DR was called to reduce load, but because operators had not defined a closed-loop interface, DR did not set LMPs. Instead, price was set by the worst contingency in PJM’s security-constrained economic dispatch.
McGlynn said the load sheds began with 160 MW and grew to “several hundred” megawatts.
Rebecca Carroll, senior director of market design, said there were 345 PAIs over about 11 hours during the week — the first PAIs since 2019, when 24 occurred.
Under PJM’s confidentiality rules, officials said, balancing ratios will not be posted for the PAIs because there were a small number of generation owners with capacity resources in areas affected by the emergency actions.
Mike Bryson, senior vice president of operations, said AEP, PJM, NERC and ReliabilityFirst are investigating and will produce “lessons learned” in four to 10 weeks, with updates at monthly Operating Committee meetings.
As the story goes, Shoeless Joe Jackson was leaving the Cook County Courthouse in 1920 amid the Black Sox scandal when a kid yelled, “Say it ain’t so, Joe!” [1]
I felt like that kid when I read that FERC proposes to wipe out competition in transmission.[2]
What’s the public policy case for this? The oft-repeated claim that transmission competition isn’t working. I call this truth by repetition.[3]
The reality, as I pointed out five years ago,[4] is that transmission competition works great — when and where it’s allowed to work. The problem is that it’s been hobbled since its advent in FERC Order 1000. As Professor Paul Joskow concludes: “The progress has been slow but promising.”[5]
Transmission Competition Works
Let me give you an example of how transmission competition works. PJM biennially identifies highly congested facilities and has a competitive solicitation for solutions. The table below shows the most recent PJM evaluation of proposed solutions to one source of congestion.[6]
PJM selected Proposal 756, which called for spending $770,000 on terminal equipment upgrades at the French’s Mill and Junction 138-kV substations, to improve market efficiency in the APS zone. Proposal 547, a new 500-kV line found to be slightly less effective, would have cost more than $136 million. | PJM
Proposal 756 above is 100% effective at mitigating congestion and costs $770,000; Proposal 547 is 99.97% effective and costs $136,070,000. Which should consumers have to pay for?
Here’s the rub: Absent a transparent, competitive process, how would anyone know about the $770,000 solution? And no one being the wiser, if the notice of proposed rulemaking is correct that adding rate base is what incents transmission owners,[7] why wouldn’t a TO want the $136,070,000 solution?
Please note that consumers are not well protected by regulatory oversight. As Joskow observes: “FERC does not have a well-developed process to scrutinize the costs presented to it for inclusion in the transmission owners’ revenue requirements or a history of disallowing unreasonable costs.”[8]
Even when the competition is not in solutions, but simply in procurement of the same basic project, national and international experience suggests cost savings in the 20 to 30% range.[9] And this is capital cost savings, which does not include the additional savings from a lower cost, competitive capital structure for determining the annual revenue requirement.
Exceptions to Competition: NOPR Misdiagnosis and Misdirection
The NOPR says the problem with competition is that TOs are motivated to avoid it through exceptions, which leads to smaller, less expensive solutions.[10] As I said in my last column,[11] that can be a good thing! Why build large greenfield transmission lines when a simple upgrade relieves the problem (like the PJM example in the prior section)?
If there really is a problem with an incentive for less expensive solutions because of exceptions, the right answer is to minimize the exceptions. Not go the other way and eliminate competition!
The NOPR’s Substitute is Escher Stairs Leading to Synthetic Monopoly
Finally, a few words about the NOPR’s proposed substitute for competition: Requiring some sort of joint ownership of a given project. For anyone concerned about delays in getting new transmission built, please read NOPR paragraphs 358-382, and contemplate the endless squabbling and litigation that this concept portends. The possibilities are endless!
As for the NOPR notion that joint ownership could somehow provide “at least some of the potential cost-related benefits of competitive transmission development processes,”[12] let’s recognize that each joint owner would have a shared interest in building the most expensive project possible. That is a coordinated oligopoly, and it performs no differently than a monopoly.[13] Not to be confused with competition!
In Short
FERC, please preserve and expand competition, a better angel of our nature.
