MISO says it will conduct a more thorough study of transmission capacity needs in the Upper Midwest after being approached by the utilities behind the independent CapX2050 planning study.
The move means the RTO will expand and protract an existing transmission study it’s carrying out under the 2020 MISO Transmission Plan (MTEP20). MISO Executive Director of System Planning and Competitive Transmission Aubrey Johnson announced the study expansion at a virtual June 26 planning meeting of the Minnesota Public Utilities Commission, where CapX2050 and Clean Grid Alliance representatives urged commissioners to make new transmission a priority.
Johnson said the RTO made the call to expand the profile of its current North Region Economic Transfer informational study in response to a May letter from — and discussions with — the 10 Minnesota utilities that produced CapX2050.
MISO’s study focuses on the increasing non-thermal limitations of the Minnesota-Wisconsin export interface, which is experiencing bottlenecks as renewable-rich northwestern portions of the RTO’s footprint seek to transport power to load centers in the Upper Midwest. (See MWEX Study Could Elicit New Tx Planning for MISO.)
MISO’s Aubrey Johnson appears at a June 26 virtual planning meeting of the the Minnesota PUC | Minnesota PUC
Johnson said work on an expanded study will begin later this year. Unlike the original informational study that served to explore non-thermal constraint modeling and is unlikely to result in a project, the expanded phase of the study could result in a project recommendation in the fall of 2021. MISO has never before included non-thermal constraints in its planning modeling.
“We’re already seeing resource choice limits … from a lack of transmission capacity,” Clean Grid Alliance Executive Director Beth Soholt told the Minnesota commission. “Whether we’re going to have that resource choice directly bears on whether we have the transmission to do that in a timely manner.”
Soholt invoked the findings in MISO’s own 2020 Interconnection Queue Outlook Report, which concluded that the RTO needs billions of dollars in new transmission to accommodate proposed generation projects in the MISO West planning region, which includes Minnesota, Iowa, parts of the Dakotas and western Wisconsin.
“Recent interconnection studies for new generation resources in MISO’s West sub-region have indicated the need for network upgrades exceeding $3 billion to accommodate the initial queue volume, and a similar trend is expected to occur in other areas with high wind and solar potential, including MISO’s Central and South sub-regions,” the RTO wrote.
Meeting New Needs
Great River Energy Chief Vice President and Transmission Officer Priti Patel said while MISO’s planning processes guarantee reliability projects are routinely built, the RTO puts little emphasis on planning for states and utilities to meet decarbonization and renewable generation targets.
“But what we asked ourselves is, ‘Are those planning processes producing efficient longer-term projects that accommodate this wholesale grid change?’” she said. “What we see is the system is changing faster than the processes can keep up.”
“We are unified on the need to act and the need to act now,” Patel said of the CapX2050 utilities.
Clean Grid Alliance’s Natalie McIntire agreed that MISO transmission planning is simply not keeping up to accommodate utilities’ decarbonization goals.
McIntire also said near-term fixes such as using dynamic line ratings and net-zero interconnections — which allow a wind generator and gas-peaking resource to split use of an interconnection site — could help free up some capacity to keep fleet transformation uninterrupted while new transmission is built.
Minnesota Commissioner Matt Schuerger, also president of the Organization of MISO States, said the RTO’s transmission line ratings are overly conservative, inconsistent and not transparently formed.
“Let’s get some consistent, transparent line ratings,” he said. “We’re not fully utilizing the transmission that ratepayers have paid for.”
In the meantime, MISO has made no indication that it’s preparing to embark on another long-term transmission package like 2011’s Multi-Value Project (MVP) portfolio.
Speaking at MISO’s virtual June Board Week, Vice President of System Planning and Chief Compliance Officer Jennifer Curran observed that there was a “fair amount of agreement” in 2011 that the MVP was necessary to facilitate state renewable portfolio standards and attract investment in wind generation. Now, however, opinions are mixed among the stakeholder community, she said.
This time around, new transmission seems to be driven by “consumer preference rather than state laws,” making beneficial long-range transmission more difficult to pin down, Curran said.
PJM transmission owners demanded Friday that the RTO refuse to submit to FERC the end-of-life (EOL) proposal approved by stakeholders, saying the bid to subject transmission replacement projects to regional planning violates the TOs’ rights under the Consolidated Transmission Owners Agreement (CTOA).
After the Members Committee approved the joint stakeholders’ EOL proposal with a 69% sector-weighted vote on June 18, PJM General Counsel Chris O’Hara said the RTO would file the proposal with FERC within two weeks, although it believes it exceeds the RTO’s authority under the CTOA. (See related story, Gen. Owners, Other Suppliers Key to EOL Win.)
“We are at a loss to understand why the board could agree to file a stakeholder proposal when the board itself agrees that the proposal exceeds PJM’s delegated authority under the CTOA,” the TOs said in a letter to the Board of Managers.
“While we understand that one of PJM’s duties under section 10.4(xiii) of the Operating Agreement is to file on behalf of PJM members amendments to that agreement and its schedules, that duty is not absolute,” the TOs continued. “Since there is no dispute between PJM and the undersigned transmission owners that the stakeholder proposal would require PJM to perform functions and undertake responsibilities that have not been voluntarily transferred to PJM under the CTOA, those commitments outweigh any duty to file the stakeholder proposal under section 10.4(xiii).”
The TOs noted that FERC requires PJM to act independently of its members as well as its TOs. “If that independence is to mean anything, PJM cannot be obligated to file unlawful amendments to the Operating Agreement or its schedules that it acknowledges would give PJM planning authority that transmission owners never voluntarily transferred to PJM. … In short, it is neither sufficient nor appropriate to simply ‘let FERC decide.’”
The TOs asked that members of the board or CEO Manu Asthana meet with them to discuss the filing. If PJM does file the proposal with FERC, the TOs said, it should inform the commission of its previously expressed views regarding its planning authority under the CTOA.
The TOs cited PJM staff presentations during the EOL debate and an October 2019 letter to members from Dean Oskvig, chair of the board’s Reliability & Security Committee, in which he said decisions on when a facility is at the end of its useful life or otherwise needs to be replaced “are the sole responsibility of the transmission owner.”
The joint stakeholders insist their proposal honors the TOs’ rights by letting them decide when a facility must be replaced — but then allows PJM to incorporate such projects in the Regional Transmission Expansion Plan.
It would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so the project could be included in five-year planning models and potentially opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.
American Municipal Power, Old Dominion Electric Cooperative, LS Power and the PJM Industrial Customer Coalition, who led the joint stakeholders’ proposal, responded with their own letter to the board Tuesday.
“The sector-weighted, supermajority of votes cast by the Members Committee is a clear indication of PJM members’ desire,” they said, adding that nothing in the CTOA prohibits the RTO from making the filing.
The TOs “are free to argue their position in a protest” to FERC, they said. “What the PJM transmission owners and the PJM board or a delegate may not do is meet to ‘discuss the decision to file the stakeholder proposal before PJM makes any such filing.’ Such an action is, by definition, an attempt by the PJM transmission owners to exert undue influence over the board’s decision-making. The transmission owners’ letter is a blatant attempt to exercise undue influence; the very request and tone is itself a threat to the board’s independence.”
FERC on Friday accepted a slew of settlements for violations of NERC reliability standards, with American Electric Power, DTE Energy, Eversource Energy, Portland General Electric and Exelon among the utilities hit with monetary penalties by their regional entities.
AEP’s violation carried the largest penalty at $1 million, followed by DTE ($375,000), Eversource ($120,000), Exelon ($110,000) and PGE ($112,000). Additional penalties were assessed against unnamed entities in the Western, Eastern, and Texas interconnections.
NERC submitted Notices of Penalty (NOPs) for AEP (NP20-16) and DTE (NP20-17), along with a spreadsheet NOP detailing the violations by Eversource and an unnamed entity in the Western Interconnection, on May 28 (NP20-18). An additional spreadsheet NOP for Exelon, PGE and unnamed utilities in the Eastern and Texas interconnections was filed on April 30 (NP20-14). In a notice Friday, FERC said it would not review the settlements, leaving the penalties intact.
Trees at Root of $1M AEP Settlement
The settlement between AEP and ReliabilityFirst stemmed from reliability standard FAC-003-4 (Transmission vegetation management).
On Aug. 21, 2018, AEP reported to the RE that its Kammer-Mountaineer 765-kV circuit in West Virginia had tripped and locked out for over 28 hours, starting on June 30 and ending the following day. The cause of the trip was later determined to be vegetation growth that had “caused a flashover to two trees within the [minimum vegetation clearing distance].”
The span between towers 202 and 203 on the transmission line, where the flashover occurred, is classed in AEP’s transmission vegetation management plan (TVMP) as a “valley span” based on assumptions about the amount of clearance beneath the line. However, following a post-event inspection, this classification was determined to be incorrect because of previously undetected hills that violated the minimum clearance requirements — including the hill with the trees involved in the flashover.
ReliabilityFirst concluded that the root cause of the event was reliance on “visual cues and professional and historical knowledge” to assess whether complete clearing was needed in a particular zone, constituting a failure by AEP to effectively design and implement a FAC-003 compliance strategy. The RE classed the risk posed by the violation as “serious,” as it could have led to overloading of nearby transmission lines and cascading outages.
According to NERC’s filing, AEP neither admitted nor denied the violation but agreed to the $1 million penalty along with additional mitigation actions. The mitigation plan includes removing all suspect trees and brush from the affected span of the Kammer-Mountaineer line, conducting additional inspections of other lines with long spans and deep valleys along with clearing vegetation as needed, and commissioning a third-party review of the TVMP.
Continued Oversights Heighten DTE Penalties
ReliabilityFirst also settled with DTE over violations of PRC-005-1 and PRC-005-1.1b (Transmission and generation protection system maintenance and testing) that occurred in 2017 and 2018.
The first violation was self-reported by DTE to ReliabilityFirst on April 17, 2017, and involved four combustion turbine generators (CTGs) at the Enrico Fermi Nuclear Power Plant in Michigan. DTE notified the RE that it had not maintained or tested relays for the CTGs since the late 1990s. ReliabilityFirst later determined that the oversight was caused by misclassification of relay maintenance requirements for the CTGs, along with insufficient detective controls and procedures and lack of communication between DTE’s engineering team and personnel at the facility.
In the second violation, DTE initially reported possible compliance issues to ReliabilityFirst during audit preparation in 2017. During the audit, the RE confirmed that nine components in DTE’s protection system “did not satisfy the requirements of PRC-005” because of insufficient testing and maintenance records; a further investigation by DTE concluded that the issues covered 325 components in all.
Unlike the earlier infraction — determined by ReliabilityFirst to pose a moderate risk to the bulk power system — the RE concluded that this violation constituted a serious risk. Several root causes for the problem were identified:
Incomplete and inaccurate equipment inventory records.
Ineffective test tracking systems.
Multiyear backlog of unchecked test records.
Failure to include certain components in the maintenance and testing program.
Failure to understand applicable standards and requirements.
DTE’s mitigation activities for both infractions included the development of a comprehensive inventory list and electronic work management system to maintain it, along with more effective process documentation.
In determining the penalty amount, NERC noted that ReliabilityFirst acknowledged that the first violation, although continuing for several years, was self-identified and reported by DTE, that the utility had accepted responsibility for its noncompliance, and that it was “highly cooperative” throughout the enforcement process. However, the RE also observed that DTE has prior violations of PRC-005, which served as an aggravating factor to the penalty determination.
Eversource Fails on Facility Ratings
The first of the two spreadsheet NOPs submitted by NERC covers a violation of FAC-009-1 (Establish and communicate facility ratings) by Eversource, and two violations of CIP-014-2 (Physical security) settled between WECC and an entity in the Western Interconnection. NERC did not identify the second offender because of security concerns.
Eversource’s $120,000 settlement resulted from a discovery made by the utility during preparation for an on-site audit in May 2018. In a self-log submitted to the Northeast Power Coordinating Council the following month, Eversource reported that it found that the facility ratings on three 345-kV transmission lines and three autotransformers in the Eastern Massachusetts Area (EMA) did not align with its rating methodology.
Enrico Fermi Nuclear Generating Station | Nuclear Regulatory Commission
Further investigation found 65 instances in the EMA where ratings did not match the methodology. The divergences were found to have been caused by various factors such as failure to update ratings after modifications to field equipment, failure to consider series-limiting components, and the incorrect use of legacy calculations based on industry rating practices but not authorized by the utility’s ratings methodology.
While NPCC determined that the violation posed a moderate risk to the safety of the grid, the RE found that Eversource had been cooperative throughout the enforcement process and thorough in its mitigation approach. Its responses included re-evaluating all 262 elements in the EMA area and updating their ratings if needed, along with expanding functions of the Thermal Ratings Coordinator into the EMA area and establishing a facilities rating update system.
WECC Escalates Unfinished Mitigation
WECC’s settlement with the unnamed entity carried no monetary penalty and was escalated from an infraction slated for NERC’s milder “find, fix and track” enforcement strategy.
At issue was the entity’s physical security plans, which lacked resilience or security measures to address potential threats identified in an earlier threat and vulnerability evaluation. The violation was determined to have begun on June 27, 2016, when the relevant requirement in CIP-014-2 became enforceable. WECC later found the entity had not effectively completed its mitigation activities and thus withheld certification of mitigation completion, escalating the matter to a formal NOP.
In response, the utility agreed to expand its mitigation plan and resubmit it. The final plan includes a number of major updates to its security posture:
Revisions to the primary control center threat and vulnerability assessment.
Updates to the substation physical security plan.
Interdepartmental meetings focused on protections needed at critical sites.
Creation of communication avenues for discussing critical infrastructure protection measures.
Establishing a new position to assist with issues relating to CIP-014-2.
Partnering with local first responders for an active shooter exercise testing its security plans.
WECC certified the entity’s completion of mitigation activities on Jan. 21.
Exelon Reports Testing Gaps in Nuclear Fleet
The final spreadsheet NOP approved by FERC details agreements between NPCC, ReliabilityFirst and Exelon for infractions of PRC-005-1.1b; between WECC and PGE for violations of COM-002-4 (Operating Personnel Communications Protocols) and VAR-002-2b (Generator operation for maintaining network voltage schedules); and between several unnamed entities and their REs for violations of NERC’s CIP standards.
Exelon’s violation, for which NPCC and ReliabilityFirst assessed a $110,000 penalty, arose from a self-report submitted to NPCC in April 2017 — and updated following subsequent review — that it had failed to perform testing required by its protection system maintenance program. The deficiencies occurred at the R.E. Ginna Nuclear Power Plant, the Nine Mile Point Nuclear Station and the James A. FitzPatrick Nuclear Power Plant. All three facilities are located in New York.
In addition, Exelon reported to ReliabilityFirst in April 2018 that it had uncovered deficiencies in testing at several nuclear stations. Two of the affected stations — Three Mile Island Unit 1 and Oyster Creek — have since been permanently shut down, which the RE considered to have mitigated the issue.
In determining the penalty, NPCC and ReliabilityFirst noted that the utility had inherited some of the units in question and thus did not deserve all of the blame for the missed testing. On the other hand, Exelon also has prior instances of noncompliance with PRC-005, and this was an aggravating factor. The REs will conduct a follow-up spot check of Exelon Nuclear in 2021 to confirm its compliance status.
PGE Admits to Communication Failures
PGE reported its violation of COM-002-4 to WECC on June 29, 2017, regarding its behavior as a balancing authority during the outage of a generation facility on Dec. 8, 2016. During the outage, PGE’s BA operator and staff at generating facilities failed to follow communications procedures; specifically, the generating facility staff failed to repeat the operator’s instructions and the operator did not ask them to, both of which are required in the standard.
WECC assessed the infraction as a moderate risk because of the repeated nature of the violation and the large amount of generating capacity that was affected. PGE agreed to update its internal procedures to clarify the required responses to operating instructions and to apply the same changes to its training manuals and performance evaluations.
In addition, WECC determined that PGE had numerous issues with communicating status changes for voltage controlling devices at its wind and hydropower facilities, with incidents beginning in 2013 and continuing through 2017 when the utility updated transmission operators with the correct information as required by VAR-002-2b. These violations were included when assessing PGE’s $112,000 penalty in the spreadsheet NOP.
CIP Penalties for Unnamed Entities
Finally, NPCC and ReliabilityFirst reached a $42,000 settlement with an unidentified utility over servers that it had discovered were not correctly identified as Electronic Access Control or Monitoring Systems (EACMS), as required by CIP-010-2 (Configuration change management and vulnerability assessments). The entity had failed to identify the EACMS because of outdated inventory systems, as well as internal miscommunication as to who was responsible for implementing the proper CIP controls.
Texas Reliability Entity also flagged an unnamed entity for violating CIP-002-5.1 (BES cyber system configuration). The violations were discovered in an internal review in 2017, after a third-party study had raised concerns that some of the entity’s cyber systems were improperly rated as low-impact; the utility confirmed that the systems in question should be changed to medium-impact, with the appropriate security measures applied.
In response to the self-report, Texas RE assessed no monetary penalty, reasoning that the entity had demonstrated a strong internal compliance program and had implemented a number of mitigating activities and controls, which it verified had been completed by Feb. 25. The infraction was also acknowledged to have posed only a moderate risk to reliability.
ISO-NE External Market Monitor David Patton delivered highlights from his 2019 assessment of the RTO, comparing its markets with others in the Eastern Interconnection and making several recommendations.
Patton, president of Potomac Economics, related concerns about the current Forward Capacity Market and plugged the benefits of a prompt capacity in the context of improving coordinated transaction scheduling with NYISO.
“We think the pros of a prompt capacity market outweigh the cons,” Patton told the New England Power Pool Participants Committee on June 23. “In other words, we tend to think prompt capacity markets perform better than forward capacity markets, and the large demand forecast errors that have occurred In New England highlights one of the many concerns of a forward capacity market.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
Net revenue comparison across markets | Potomac Economics
However, he did not recommend eliminating the FCM because the benefits of doing so do not clearly outweigh the market disruptions it would cause. But he did recommend that ISO-NE replace the descending clock auction with a sealed-bid auction to improve competition in the Forward Capacity Auction.
Patton also recommended improving the minimum offer price rule by: eliminating performance payment eligibility for units subject to the MOPR; capping the minimum offer price at the net cost of new entry; and exempting competitive private investment from the MOPR.
A comparison of net revenue across various regional electricity markets showed that a well functioning wholesale market helps establish transparent and efficient price signals, which in turn influence the locations and technologies of new projects, according to the EMM’s report.
In New England, net revenues have been close to the levelized new entry costs for combustion turbines, but this will not continue in the future as capacity prices fall over the next few years, the report said. With tax credits and renewable entry credits, the markets are providing more than sufficient revenues for wind resources. Wholesale market revenues will continue to play a key role in motivating entry of flexible units that help integrate policy resources and prompt the retirement of inflexible units.
The EMM also recommended the RTO modify allocation of “economic” net commitment period compensation (NCPC) charges — the payment made to market participants that don’t recover their effective offer costs — to align it with cost causation, and pursue improvements to the price forecasting that is the basis for CTS with NYISO.
An uplift rate of $2 to $3/MWh over the past three years generates millions of dollars in day-ahead NCPC payments, but “the shocking number is the number of hours, almost half the hours of the year, when commitments are being made to supply spinning reserves,” Patton said.
“This signifies that both our prices and our compensation in the day-ahead is not very efficient when it comes to the types of units that are supplying the spinning reserve product,” he said. “It also tends to undermine the energy price because, to the extent that costs are being incurred to meet the spinning reserve requirements, those costs should be reflected in energy prices.” However, Patton indicated that the RTO’s Energy Security Improvements (ESI) initiative will address these concerns.
When asked about how recent reductions in load forecasts should be factored into the capacity market requirements, Patton said that “the general principle is that you should do everything you can to make your installed capacity reserves forecasts as accurate as possible, recognizing that there are Tariff requirements and tradeoffs where the ISO has to publish what the requirements are in advance of the auction so that people can … offer into the auction.”
Further recommendations are to modify the performance payment rate to rise with the reserve shortage level and not implement the remaining planned increase in the payment rate; and consider modifying the capacity compensation of energy-limited resources to be consistent with their reliability value.
The Monitor also recommended that the RTO require the use of the lowest-cost fuel or configuration for multiunit generators when they are committed for local reliability.
BPS Reliability Perspectives for 2050
NERC CEO Jim Robb gave the PC a look at various bulk power system reliability perspectives at midcentury, with key issues being the timing of technology development and deployment (especially batteries), the pace of deep electrification and the regulatory treatment of natural gas.
“The one challenge our industry has is that we’re enormously reactive,” Robb said. “We are great at responding to an event and figuring out what went wrong and changing it, but we are not great at heading events off before they happen, because it’s hard to motivate people to make hard choices when they don’t feel them very present.”
Distribution of outage risk by technology type | Potomac Economics
Bruce Ho of the Natural Resources Defense Council referred to the need for increasing system flexibility in which load follows generation — rather than just generation following load — as the country gradually moves to a fully decarbonized grid that relies on variable energy resources like wind and solar.
“I’m curious what you see as the role in the other direction, with more dynamic loads that follow supply,” Ho said, citing the importance of demand response. “What role do you see on the demand side, and do you have any thoughts on how markets and reliability standards might need to adapt to incorporate and compensate that dynamic load?”
“We need to rethink so many things, because I actually have a bias of thinking of the electric system serving load,” Robb said. “And you’re right; as Mark Lauby says — who’s our chief engineer and the smartest technical guy I know on this stuff — that concept is increasingly flawed.”
NERC CEO Jim Robb | ISO-NE
Planners need to expand their thinking about the grid beyond a linear relationship between the bulk power system, the distribution system and end users, he said. It would be wrong to describe them as being “integrated,” Robb said.
“Really, they’re all interdependent,” he said. “When I talk about the new models, the new operating paradigms, I think those issues need to be brought in as much as anything else. Demand response can play a really important role, but will it be there on the fourth day of the heat wave? I have a little bit of a [former PJM CEO] Terry Boston view of the world in that I like iron in the ground, because I know I can do something with it.”
Robb cited cybersecurity as a constant issue and said he does not like the term “Internet of Things,” preferring to think of it as the “Internet of Threats.”
Investing in the Future
Scott Kushner, managing director of Boston-based John Hancock Infrastructure Investments, discussed how he and his team decide where to invest in the electric power industry and how changing public policy affects such decisions.
Of the firm’s $30 billion in assets under management, approximately 30% is invested in private equity investments, while the remaining 70% is in investment-grade, long-term, fixed-income debt products, Kushner said.
“We lend to utilities; we’ve lent to projects, power plants of all technologies, all fuel sources; but certainly lately renewables has become a very big piece of what we’re looking at on both the debt and equity side,” Kushner said. “One of the main drivers of that, if you look at what an insurance company likes to invest in, is the lower-risk stuff, the stuff with longer-term contracts.”
On lowering the cost of capital, James Daly, vice president of energy supply at Eversource Energy, asked whether Kushner preferred programs with more revenue certainty or those dependent on merchant revenues.
“It certainly helps from an institutional investor standpoint,” Kushner said. “I would say that SREC 1 and SREC 2 [solar renewable energy credits] in Massachusetts worked really well, but certainly when we’re looking at the cost of capital for the SMART [Solar Massachusetts Renewable Target] program, which has the longer-term feed-in tariff like contracts, the cost of capital has come down even lower.”
Scott Kushner, John Hancock | ISO-NE
Whether because of highly structured state programs or just the evolution of time and more investors starting to get comfortable in the clean energy space, “certainly the longer the contract, the more certainty in it, there’s no denying that will lower the cost of capital,” Kushner said.
“It seems that the capacity market in New England, with the seven-year lock rate available for new resources, is able to provide sufficient revenue certainty and risk reduction to make financing terms attractive for gas generation, but it doesn’t have the comparable impact for financing of renewable generation because those resources get the majority of their revenue from the energy market, which has no similar long-term certainty,” said Abigail Krich, president of Boreas Renewables.
“While state solicitations for long-term contracts and programs like SMART are filling in that gap to provide comparable revenue certainty to renewable resources, if the wholesale market were modified to be able to supply a similar level of revenue certainty to renewable resources, would those long-term contracts and policy commitments for renewables still be needed in order to be able to finance them?” Krich said.
There’s a place for both gas-fired generation and renewables in the market, Kushner said.
“If the market were to shift from these longer-term contracts to something like the capacity market for fossil fuels, which gives these projects price certainty for maybe five to seven years, the projects absolutely will get financed,” Kushner said. “It just depends on who’s going to actually finance them and what the ultimate cost of capital is.”
Problem Trio
Rutgers University professor Frank Felder, who teaches electricity policy and market structures, presented a thesis posing three types of problems that market operators and public officials must address: political economy, economic/regulatory and engineering.
Frank Felder, Rutgers | ISO-NE
“They are really three subsets of the same problem,” said Felder, director of the Rutgers Energy Institute and the school’s Center for Energy, Economic and Environmental Policy.
Deep decarbonization is a political economy problem because it concerns jobs, costs and economic policy, which interact with the economic and regulatory problem, he said.
“Whether an entity is regulated, or in a market environment, or in an integrated utility environment, there are economic and regulatory incentives that shape the decision-making, and in particular with long-term loan capital assets, you have a variety of problems, such as asymmetric information,” Felder said.
For example, an offshore wind developer knows more about the cost structure of a power purchase agreement than the regulator signing off on the deal, he said.
Engineering comprises both optimization and system-control problems, Felder said.
Political, economic and reliability difficulties are likely to arise unless these three types of problems are addressed in an integrated and consistent manner, he said.
“Massachusetts is really committed to trying to find a market-based solution to integrate clean energy,” said Matthew Nelson, chair of the state’s Department of Public Utilities. “We know that’s not going to be easy.
“Massachusetts has been very supportive of carbon pricing, so we’ve supported the Regional Greenhouse Gas Initiative. We have initiatives [that encompass more than] energy, like our state-specific Clean Energy Standard, and the Transportation Climate Initiative, but we’re not so interested in a FERC-jurisdictional carbon pricing — that concerns us,” Nelson said.
Massachusetts wants to ensure that a carbon price brings clean resources online and that it works with existing state policies, he said. Meanwhile, “other states in New England are in very different places on this one as well.”
“Where we’re all aligned, at least on carbon, is we don’t have any interest in a federal-based carbon price that would prevent states from achieving their individual goals,” Nelson said. “How is the price set? How is it priced accurately? Those are big, fundamental questions that bother individuals.” (See Study: $25 Carbon Price Needed to Meet Goals.)
Speaking to RTO Insider after the meeting, Nelson said, “Specifically here, what I think is important is who is setting the price and that process, because obviously that’s a big decision and will influence the outcome. I feel that’s a question we need to answer before states would be supportive.”
Some states don’t have clean energy targets and don’t think that increasing the price of carbon is actually what they want to achieve, he said.
“At this time, I just don’t think that a new carbon price adder outside of RGGI is politically feasible for all six states,” Nelson said. “But we’re not scared to talk about the data, what that data achieves, where the price is set. I think we have to have the conversation around what the numbers are and what we’re paying through different processes, to understand the different policy decisions we’re making.
“We have aggressive clean energy targets in Massachusetts,” he said. “I know that we’re going to need more clean energy to come online, and most of the need will be met through load growth through some of our policies around decarbonization of transportation, of buildings. And continued out-of-market contracts still have some inherent drawbacks, especially in the long-term scale we’re talking about.”
Pennsylvania Republican senators said last week that Gov. Tom Wolf’s plan to join the Regional Greenhouse Gas Initiative will accelerate the closure of the state’s coal-fired generating plants, dealing another economic blow on top of the coronavirus pandemic.
Committee Chairman Gene Yaw (R) said joining RGGI will exacerbate the disruption Pennsylvania’s energy sector has suffered during the pandemic. “There are many questions that remain with regard to the governor’s executive order instructing the Pennsylvania Department of Environmental Protection [DEP] to participate in RGGI,” Yaw said.
Yaw and Committee Vice Chairman Joe Pittman (R) led a group of legislators that signed a letter in April asking Wolf to rescind his executive order out of “respect for the oversight process,” noting the committee had to cancel four public hearings on the issue because of the pandemic.
During the hearing, Pittman grilled DEP Secretary Patrick McDonnell, saying that three coal-fired plants in his district — Conemaugh Generating Station, Homer City Generating Station and Keystone Generating Station — will likely be shut down if the state joins RGGI, causing thousands of job losses.
“I’m not naive to the market conditions,” Pittman said. “I recognize the challenges that exist already. But my goodness, allow the market to work. And if you really want us to adjust as communities, then show us the examples of what you’re going to do to rectify the damage being done to our communities.”
McDonnell said people are “going to be standing outside shuttered plants” within the next 10 years regardless of whether Pennsylvania joins RGGI because of the direction of the energy market. He said utility-scale solar generation is becoming the cheapest resource available within the PJM market and that coal generation is quickly disappearing.
“The reality is the market is driving these decisions,” McDonnell said. “The market is driving decisions around moving to renewable energy, clean energy and energy efficiency.”
Minority Chairman Steven Santarsiero (D) said he “wholeheartedly” supported Wolf’s plan, saying RGGI will allow the state to meet its carbon emission goals and provide economic benefits to residents.
“This is an important change in Pennsylvania policy, and as a consequence, it does require thorough public input and thorough input to this committee as we move forward,” Santarsiero said.
First Climate Goals for Pennsylvania
Reducing CO2 emissions is a top priority for the Wolf administration. In 2019, according to the DEP, only 5% of Pennsylvania’s 231,245 GWh of electricity production were from renewables. Nuclear contributed 36%, natural gas 42% and coal 17%.
In January 2019, Wolf signed an executive order setting Pennsylvania’s first statewide climate goals: reducing greenhouse gas emissions by 26% by 2025 and by 80% by 2050 compared to 2005 levels.
Generation portfolio mix estimates if Pennsylvania and Virginia join the Regional Greenhouse Gas Initiative | PJM
Wolf followed with a second executive order instructing the DEP to begin the regulatory process to join RGGI. On June 22, citing the pandemic, Wolf provided the department with a six-week extension to deliver a proposed rulemaking to the Pennsylvania Environmental Quality Board, extending the previous July 31 deadline to Sept. 15.
Wolf said RGGI states have reduced power-sector CO2 pollution by 45% since 2005 while returning $2.31 billion in lifetime energy bill savings to more than 161,000 households and 6,000 businesses that participated in programs funded by RGGI proceeds through its first six years of existence.
Hayley Book, senior adviser on energy and climate for the DEP, said Pennsylvania’s RGGI implementation date of Jan. 1, 2022, remains in place. Book said the department plans to hold stakeholder and public meetings on RGGI throughout the summer.
RGGI, which includes New York and the six New England states, currently has three PJM states: Delaware, Maryland and New Jersey. Virginia also is planning to join RGGI under the Clean Economy Act that passed its legislature in February and goes into effect Jan. 1. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)
In her testimony June 23, Gladys Brown Dutrieuille, chairwoman of the Public Utility Commission, said about 24% of the electricity produced in Pennsylvania is exported out of the state. Dutrieuille said the cost of RGGI compliance for exported electricity will be paid by electric customers in the states where that electricity is ultimately used.
PJM Testimony
PJM stakeholder opinions regarding RGGI and carbon pricing have been mixed, with many members encouraging the RTO to take a more active role in facilitating carbon pricing as states decide to join the environmental collective. (See Stakeholders Urge PJM Action on Carbon Pricing.)
In a letter sent to the PJM Board of Managers on Friday, 29 companies and renewable industry groups called for the RTO to continue its efforts to consider the integration of carbon pricing in its markets.
“With continued and heightened focus by states in the PJM market on reducing carbon emissions from power generation, PJM should continue to work with stakeholders to explore the relative roles that its competitive wholesale markets and state policies should play in shaping the quantity and composition of resources needed to meet such carbon emission reduction goals while cost-effectively meeting future reliability and operational needs,” they said.
Stephen Bennett, PJM manager of regulatory and legislative affairs, speaks via video conference at the June 23 Pa. Senate hearing regarding the Regional Greenhouse Gas Initiative (RGGI). | Pa. Senate
Stephen Bennett, PJM manager of regulatory and legislative affairs, took a neutral stance on carbon pricing in his presentation during last week’s committee hearing, but he said, “A price on carbon emissions generally integrates well with PJM’s current markets.”
PJM’s Carbon Pricing Senior Task Force has received briefings from RTO staff on its modeling of carbon pricing scenarios and ways to address emissions “leakage” occurring when certain states choose to apply a carbon price and others do not. One of the strongest conclusions drawn from PJM’s modeling to date, Bennett said, is that the mix of states included in the carbon pricing region are a “driving factor in determining the overall impact that carbon pricing has on net PJM carbon emissions and electricity prices.”
Bennett also reiterated PJM’s stance that it does not propose to establish a carbon price and does not take advocacy positions on state legislation.
“PJM recognizes and respects Pennsylvania’s prerogative to determine its policies regarding environmental protection and emissions management,” Bennett said. “PJM also recognizes that state policy plays a significant role in determining the assets and fuel mix used to meet the state’s resource adequacy needs. Rather than advocate, PJM seeks to be a neutral party and provider of factual information on the planning and operation of the bulk electric power system, the operation and evolution of the wholesale power markets that help ensure reliability at the lowest reasonable cost, and the value PJM provides as an RTO.”
Chairman Yaw asked Bennett whether PJM will purchase generation from outside of the state if Pennsylvania’s generation capability is reduced because of RGGI.
Bennett said one of the biggest benefits of PJM is its geographic diversity, with a market spanning 13 states and D.C.
“If there is a generator or a generation source that has very high cost of prices, they’re likely to be displaced either in state or out of state by resources that have a lower cost,” Bennett said. “And that’s how across the footprint we’re able to provide that power at the lowest reasonable cost.”
Leakage Concern
Sen. Scott Martin (R) cited PJM’s opportunity statement on carbon pricing, which said that “without addressing leakage, rising emissions can eliminate the environmental benefits that carbon pricing policies are intended to produce.” He asked if environmental benefits touted by the DEP would be offset by other fossil fuel generation units in non-RGGI PJM states, as the department’s draft CO2 trading program regulation contains no provisions to address leakage.
Bennett said he couldn’t “categorically” say that any emissions or environmental benefits would be offset, citing the complexity of the modeling PJM has conducted.
“Depending on the cost of carbon and things of that nature, you do have differing outcomes as far as the impact of leakage on the overall net price and emission intensity outcomes,” Bennett said. “Leakage is certainly something that can have that impact.”
Republican Legislation
The Senate hearing was not meant to be a consideration of Vice Chairman Pittman’s Senate Bill 950 or its companion House Bill 2025 sponsored by state Rep. Jim Struzzi (R), which require RGGI to be “vetted through the legislature,” though both were mentioned during testimony.
Tom Schuster, clean energy program director for the Sierra Club in Pennsylvania, said SB 950 would prevent Pennsylvania from regulating electric sector carbon pollution and revoke the DEP’s existing authority under the Air Pollution Control Act to regulate greenhouse gas emissions in any sector.
Shawn Steffee, executive board trustee and business agent for Boilermakers Local Lodge 154, said he has joined with community, business and labor leaders in the Power PA Jobs Alliance to support both the Senate and House bills. Steffee said Pennsylvania coal-fired power plants and older gas plants will lose their ability to compete with similar units in West Virginia and Ohio, two states that are not examining joining RGGI.
“Our plants will abruptly close, and new power generation growth will happen in West Virginia and Ohio, costing us thousands of good paying, blue collar jobs,” Steffee said.
NYISO will need to expand its bulk transmission and some low-voltage lines to meet New York’s 2030 climate goals, according to the latest Congestion Assessment and Resource Integration Study (CARIS).
Jason Frasier, the ISO’s new manager of economic planning, presented the study to the Business Issues Committee on Wednesday, which recommended it be approved by the Management Committee.
2019 CARIS study groupings | NYISO
Business as Usual
The report, the first phase of the ISO’s two-phase economic planning process, contains a “business as usual” base case that includes only incremental resource changes based on known planned projects with a high degree of certainty. It simulated hourly grid operations from 2019 through 2028, based on the 2019-2028 Comprehensive Reliability Plan, which includes the Western New York and AC Transmission Public Policy Transmission Projects scheduled to enter service on June 1, 2022, and Dec. 31, 2023, respectively.
The model simulated how investments in transmission, generation, demand response and energy efficiency would impact congestion in the three most congested transmission corridors: Central East, Central East-Knickerbocker and Volney-Scriba.
As in past studies, the base case found “limited opportunities for transmission buildout based solely on production-cost reductions” reflecting the current “generation-rich” system, the ISO said.
“The solutions … offered a measure of congestion relief and production costs savings but did not result in projects with benefit/cost ratios in excess of 1.0. Following the energization of the AC Transmission projects, the congestion is substantially reduced and shifts to the Central East-Knickerbocker corridor.”
The study does not attempt to project changes in energy consumption caused by the COVID-19 pandemic. “The study provides in-depth analysis of long-term system usage trends and of system congestion and curtailment patterns over the next decade that are likely to persist notwithstanding the lower energy forecasts for 2020 and 2021 that the NYISO produced for the 2020 Gold Book,” the ISO said.
‘70×30’ Scenario
CARIS’ primary focus, however, is on the “70×30” scenario, reflecting the 2019 Climate Leadership and Community Protection Act (CLCPA) requirement that 70% of the state’s end-use energy be generated by renewable energy systems by 2030.
The scenario, which modeled two hypothetical buildouts of renewable energy facilities, identified transmission-constrained pockets that could prevent renewable production from being fully deliverable to customers. Unlike the base case, it did not include a benefit-cost analysis.
The CLCPA included technology-based targets for distributed solar (6,000 MW by 2025), storage (3,000 MW by 2030) and offshore wind (9,000 MW by 2035), with a goal of making the electric sector emissions free by 2040.
The system model for the scenario added about 110 sites of land-based wind, offshore wind and utility-scale solar, along with additional behind-the-meter solar across the system.
NYISO identified five “renewable generation pockets” where insufficient bulk and local transmission network capacity could prevent renewables from being delivered to consumers statewide. | NYISO
Sufficient renewables were added to the system to equal 70% of state energy consumption, taking into account the “spillage” of generation when renewable production exceeds load within the New York Control Area — power that could either be exported or would have to be curtailed.
To study the impact of one potential renewable resource mix that could meet the 70×30 goal, the model included about 15,000 MW of utility-scale solar, 7,500 MW of behind-the-meter solar, 8,700 MW of land-based wind and 6,000 MW of offshore wind in addition to existing hydro generation. ISO staff also included a sensitivity analysis assuming the policy target of 3,000 MW of energy storage.
The study used a new screening tool to identify five “renewable generation pockets” where insufficient bulk and local transmission network (115-kV and some 230-kV lines) capacity could prevent renewables from being delivered to consumers statewide. The study concluded that about 11% of total potential renewable energy production of 128 TWh/year would be curtailed without transmission improvements.
The North Country pocket saw the highest curtailment by percentage, the highest curtailed energy by gigawatt-hours and the most frequent congested hours. Offshore wind also would be constrained in New York City (Zone J) and Long Island (Zone K) because of constraints on the land-based grid.
Technology and nodal discounts in 70×30 case | Potomac Economics
The increase in intermittent renewable generation meant lower production from the state’s fossil fuel generators compared to the base case.
“In many cases, however, the reduced output is accompanied by an increased number of generator starts, indicating the need for dispatchable and flexible operating capabilities in the future. Fossil fleet operation can also be highly dependent on transmission constraints,” the report said. “In particular, comparison of operations in the relaxed and constrained cases makes apparent that simple cycle combustion turbines may run more and start more often due to transmission constraints.”
The conclusion: “Additional transmission expansion, at both bulk and local levels, will be necessary to efficiently deliver renewable power to New York consumers.”
The report also found that energy storage could decrease congestion and help to increase the use of the renewable generation, particularly solar generation, when “dispatched effectively.”
“The targeted analysis showed that energy storage likely cannot by itself completely resolve the transmission limitations in the pockets analyzed.”
MMU Review
Pallas LeeVanSchaick of Potomac Economics presented the Marketing Monitoring Unit’s review of the report, saying the transmission constraints identified in the 70×30 hourly resource modifiers (HRM) scenario “also substantially affects investment incentives” for intermittent renewable generation and battery storage. Under HRM, renewable resources are modeled to allow their outputs to change on an hourly basis.
Wholesale market incentives will encourage developers to locate assets where the transmission system is not already saturated with a particular renewable technology, the MMU said.
While renewable generation and battery storage projects may rely on revenues from sources outside the wholesale market, “the wholesale markets are as important as ever in channeling investment,” LeeVanSchaick said.
Many renewable generators seek to reduce market risk by signing long-term (20- to 25-year) contracts for “index” renewable energy credits, which pay a price per megawatt-hour equal to a fixed strike price minus the index price for a nearby pricing hub. A generator with a strike price of $65/MWh located near a trading hub that averaged $30/MWh over a month would receive $35/MWh for its RECs for that month.
But index RECs don’t eliminate all risks in the 2030 scenario, the MMU said.
The MMU cited the “technology discount” — the difference between the simple average zonal LBMP in the day-ahead market and the generation-weighted average zonal LBMP in the real-time market by technology. This affects technologies that tend to produce electricity at times when zonal LBMPs are below the day-ahead average.
Generators also face a “nodal discount” — the generation-weighted average differential between the zonal locational-based marginal prices and the nodal LBMP for a particular technology and location. This reflects reduced revenue when local transmission constraints further discount the energy revenue to a particular technology and location.
Neither of the discounts are much of a factor in 2020, LeeVanSchaick said. “But you see those tend to grow over time as [intermittent renewable] penetration increases.”
In the 70×30 scenario, the MMU found technology discounts of 27 to 87% of average zonal LBMPs for solar generation in Zones A to G, with solar in Zone K facing a potential 14% revenue reduction. Land-based wind would face a 2 to 21% discount in Zones A to E, with a 6 to 13% discount for offshore wind in Zones J and K.
Nodal impacts could range, from a 79% discount to a 29% premium for solar. Land-based wind could see between a 56% discount to an 8% premium, with offshore wind ranging between a 68% discount to 23% premium.
The MMU emphasized that the 70×30 scenario does not constitute a prediction of the resource mix in 2030, and its analysis is not a prediction of future market outcomes. It said the scenario does provide useful information about market incentives as the state works toward the 70×30 goal.
“If additional entry into saturated areas is motivated by raising index REC prices in the future, it will result in large financial risks to renewable generation developers that invest sooner (i.e., before the area has become saturated with a particular intermittent generation technology),” the MMU said. “Thus, a stable and predictable policy regarding index REC price levels may facilitate progress towards the state’s goals.”
It also said the high renewable penetration in the 2030 scenario would result in “strong incentives” for entry by unsubsidized battery storage developers.
“This market response would moderate energy prices and reduce market risks for renewable generation investors. Hence, a competitive wholesale market for energy, ancillary services and capacity will ultimately facilitate state policy objectives.”
Next Steps
CARIS Phase 1 will be brought to a vote at the July 1 Management Committee meeting and is expected to be considered by the NYISO Board of Directors at its July meeting.
The ISO said it will build on the CARIS results in the upcoming 2020 Reliability Needs Assessment and the Climate Change Impact and Resilience Study.
After CARIS Phase 1 is approved by the board, NYISO will begin Phase 2 of the economic planning process, in which developers will be invited to propose projects to alleviate the identified congestion.
The ISO will evaluate proposals to determine their impact on congestion and whether the projected economic benefits make the project eligible for cost recovery under the ISO’s rules.
“While the eligibility criterion is production cost savings, zonal LBMP load savings (net of transmission congestion contract revenues and bilateral contracts) is the metric used in Phase 2 for the identification of beneficiary savings and the determinant used for cost allocation to beneficiaries for a transmission project,” the ISO said.
PJM has revised its proposed review of its auction revenue rights (ARRs) and financial transmission rights markets as stakeholders decide whether to put their work on the issue on hiatus until a report is completed.
At Friday’s ARR/FTR Market Task Force meeting, PJM’s Dave Anders presented the revised draft scope of work to be done by an external consultant in its review of the ARR-FTR construct, a project recommended in last year’s independent consultant report on the GreenHat Energy default.
Anders said PJM received “significant feedback” after last month’s task force meeting and decided to take a “higher-level view” to ask broader structural questions than the RTO had originally proposed.
While the overarching question of whether load is receiving optimal value from the ARR/FTR markets remains the same, Anders said, the revised questions seek to avoid conflicts between load-serving entities and financial traders over what is to be examined. (See PJM ARR/FTR Review Could Pit LSEs vs. Financial Traders.)
“This thinks about the big-picture questions first and then gets down to the more granular considerations,” Anders said.
The new work scope requests that the consultant examine ARRs and FTRs both separately and as a system working together and make recommendations for potential improvements. The questions include a look at the reason the markets were created; whether they are producing the desired outcome; and whether there are alternatives to achieving the desired results.
Anders said the request for hiring the consultant should be posted by the end of this week. He said the RTO hopes to have the consultant start work by the end of July and to have a report done by October.
Sharon Midgley, Exelon’s director of wholesale market development, said PJM’s work scope changes were “excellent” and “raised the level of conversation” instead of assuming any outcomes. She asked if PJM will have the consultant look at the technical platforms running the ARR-FTR markets to ensure the technology is up to date and able to be expanded or changed if needed. “I would hate for us to go through the process and not be able to implement certain things because we don’t have the systems to support it,” she said.
Anders said the consultant may not be able to scrutinize the IT platforms because PJM is searching for someone who understands “the economics” of the market and not necessarily the technology running the programs.
Jim Davis of Dominion Energy said the consultant questions represent what his company had in mind when discussions about the markets were being proposed. Davis said the consultant should spend “sufficient time” considering market design changes to optimize the value or lower the risk to load.
“The scope of work is well defined yet flexible as well,” Davis said.
PJM vs. IMM
After Anders presented the updated scope of work, he discussed potential pathways forward for the task force while the consultant completes its review. Anders said stakeholders have expressed varying opinions, ranging from putting the group into hiatus to looking at some limited-scope items over the next few months.
PJM’s recommendation is to put the task force on hiatus until the consultant completes its work, Anders said, because the broad range of work to be completed may result in changes to aspects of the market construct. He said continuing work on anything that could contradict the consultant’s report would not be a good use of stakeholder time.
“PJM and stakeholders don’t want to give the impression that they’re driving towards some solution at the same time the consultant is doing a broad review,” Anders said.
Howard Haas, chief economist for Monitoring Analytics, PJM’s Independent Market Monitor, said he appreciated the work that went into formulating the work scope but disagreed with the hiatus recommendation. He said conducting a third-party review of the markets was only one aspect of the recommendation that came from the GreenHat report and that it asked PJM, the Monitor and stakeholders to do a “holistic review” of the entire ARR-FTR process.
Slowing down the pace of the task force’s work makes sense during the consultant’s review, Haas said, but the amount of information stakeholders need to cover requires continuous effort. Haas suggested continuing discussions and a presentation of methodologies, analysis and data needed to facilitate a discussion of any needed changes to the current ARR/FTR market.
“There’s a lot of work that has to be done with or without the consultant’s report,” Haas said.
Anders said the Market Implementation Committee will vote July 8 on whether to put the task force on hiatus or continue work. The MIC will vote after receiving the results of a nonbinding poll of task force members on the same question.
Stakeholder Opinions
Davis said he agreed with Haas’ recommendation to continue the task force work at a slower pace. He also suggested that the consultant provide interim updates to the group as it conducts its review to have a better understanding of the issues being examined.
Susan Bruce of the PJM Industrial Customer Coalition said she was “of two minds” when thinking about how the task force should proceed. She said that although she understands PJM’s interest in allowing the consultant to do its work without outside influence, she is open to continuing conversations on market dynamics to avoid losing the sense of momentum that has built during task force discussions since January.
“This is a complicated nut, and I think there are a lot of issues here to discuss,” Bruce said.
Several stakeholders expressed support for a hiatus. Jim Benchek of FirstEnergy said he is concerned that the continuing mixture of data production and presentations by PJM and the Monitor at task force meetings could influence the content of the independent report.
Gary Greiner, director of market policy for Public Service Enterprise Group, said stakeholders need to recognize that the GreenHat report indicated PJM’s markets are not fundamentally broken and did not constitute a “house on fire” situation that needed immediate attention. He said taking more time and being thoughtful in deliberations would be beneficial for stakeholders and at the same time allow the consultant to do its work unimpeded.
“If the consultant comes back and we dismiss everything they’ve done out of hand, then we’ve done a pretty poor job on our part,” Greiner said.
Representatives of three of the dominant utilities in New England on Wednesday briefed Northeast Energy and Commerce Association members about their companies’ aggressive decarbonization efforts, suggesting that many other utilities will need to step up their games to reach net-zero emissions by 2050 — the year by which climate experts say the world must stop emitting carbon entirely or find some way to remove it from the atmosphere to prevent catastrophic environmental changes.
Officials from Avangrid, National Grid and Eversource Energy spent most of their presentations triumphantly pointing to the progress they have made toward their decarbonization goals. The strategies laid out by the officials ran the familiar gamut: aggressive investment in renewable resources, upgrading the transmission system to make it more efficient and co-locating new renewables with storage.
Driven by legislation passed by states in their service territories, the utilities are indeed well on their way to reaching their targets — for now. National Grid last year, for example, upped its goal from an 80% reduction by 2050 from 1990 levels to net-zero emissions by then. Its also increased its interim goals, having already achieved its previously 70%-by-2030 target this year; it’s now targeting 80% by 2030.
Having achieved its 70% emissions-reduction goal 10 years earlier than its original target, National Grid last year upped its goals. | National Grid
Avangrid’s generation mix is made up almost entirely of wind energy, with 7.4 GW of onshore resources in operation, and another 9.6 GW in development, both on- and offshore. It expects to be carbon-neutral by the end of 2035 — the year its last remaining fossil fuel plant, the Klamath Cogeneration Project in Oregon, will reach the end of its useful life.
But the speakers cautioned that these strategies will get utilities only so far in reaching net-zero emissions by 2050. Nascent technology such as long-duration energy storage, carbon capture and sequestration, and renewable natural gas will be needed not just to offset emissions but to balance the intermittency of renewable resources, they said.
“High penetrations of renewables are going to need some truly flexible power plants to balance them … which means, for many utilities, natural gas,” said Javier Ceña, Avangrid’s executive director of sustainability. “So the electric sector might need to rely on carbon capture or carbon-free fuels, like green natural gas or green hydrogen, to reach carbon neutrality by 2050.”
Clockwise from top left: Javier Ceña, Avangrid; Catherine Finneran, Eversource; Michele Leone, National Grid; and VHB Senior Environmental and Sustainability Planner Donny Goris-Kolb, who moderated the discussion. | NECA
He pointed to Avangrid parent company Iberdrola’s demonstration project in Puertollano, Spain, that will use a combination of solar and electric storage to produce hydrogen.
National Grid is also in the early stages of developing a program to counter emissions. “As much as our primary focus is to reduce our emissions, we do believe that we will have to do some offsetting in 2050,” said Michele Leone, director of sustainability and environment. “So right now we’re looking to develop a program … looking at local partnerships, looking at co-benefits of various offsetting options.”
Eversource’s Catherine Finneran said that line losses actually account for most of the company’s emissions and that it is focused on replacing aging transmission infrastructure as part of its decarbonization strategy. | Eversource
Eversource has perhaps one of the most aggressive targets in the U.S.: carbon neutrality by 2030. Its strategy is to first reduce its own greenhouse gas emissions “to the maximum extent possible,” according to Catherine Finneran, vice president of sustainability and environmental affairs. “And then … we’ll offset those emissions, whether through the purchase of offsets or the development of initiatives that produce the offsets.”
Both National Grid and Eversource said they’re also focusing on reducing leakages of methane from their natural gas pipelines and of sulfur hexafluoride (SF6) — an extremely potent greenhouse gas rarely mentioned compared to carbon dioxide and methane — which is used in switchgear as an insulator.
SF6 “might look like a small amount of our footprint, but it is a very big focus for us,” Finneran said. The company is working with its suppliers to phase in SF6-free equipment over the next five years. The challenge, however, is that such equipment is only available for lower-voltage equipment, “and we really need it also at higher voltages as well,” she said.
The world changed for American Electric Power’s Scott Smith in early March when the coronavirus pandemic forced Ohio Gov. Mike DeWine to partially shut down Columbus’ annual professional bodybuilding event.
“The Arnold,” as it’s called locally, is no ordinary strongman competition. Named after Arnold Schwarzenegger, the Arnold Sports Festival annually attracts more than 20,000 competitors from more than 80 countries to Ohio’s capital.
“It was a watershed moment for us,” Smith, AEP’s senior vice president of transmission field service, said last week during an online Gulf Coast Power Association panel discussion.
“It’s the largest convention in Ohio, other than [Ohio State University football],” he added.
AEP leadership quickly dusted off a plan it had developed after the H1N1 pandemic in 2009 and by mid-March had sent much of its corporate staff home. Now, AEP’s executives are wondering whether they’ll even have some staff return to the office.
“We originally thought we would come back to work the same as before, but it’s not business as usual,” Smith said during the discussion Thursday. “There’s going to be the new normal. We’re in the beginning stages of figuring out that and the protocols around it.”
Scott Smith, AEP | GCPA
Smith was joined on GCPA’s panel, “The Future of Work in the Age of Pandemics,” by ERCOT CEO Bill Magness, who said he has the same thoughts. The Texas grid operator also sent its corporate staff home in mid-March. Their stay-at-home orders have since been extended through September.
“We ended up with about 95% of our people working off-site, and there they remain,” Magness said.
ERCOT and AEP have since been using federal guidelines and social-distancing and hygiene practices to determine how best to safely bring back employees. Today’s open-office concepts mean companies will have to rely on shields for workspaces and faces if staff are going to return to their workspaces.
“We’re not going to be able to keep 6-foot distancing for everyone in their cube,” Smith said, noting he sits in an office that is 80% open space.
“We’re thinking hard about this,” Magness said. “Is it better to maintain the performance of the people on your team by keeping them where they are in a remote environment, or bring them back to the way we used to be? From a business perspective, what’s going to help the business the most? What helps the most is productive employees.
“If we only have a somewhat limited number of people in the footprint, we may not be able to bring people back to sit where they use to sit. We may have A Team/B Team arrangements. We’re learning a lot about what the future is going to look like. It’s been fascinating.”
A recent Upwork survey of hiring managers revealed that more than half the nation’s workforce is working remotely. Managers are planning for almost 22% of their workforces to be entirely remote in five years and for the expected growth rate of full-time remote work during that time to more than double, from 30% to 65%.
It may seem counterintuitive, but the survey also found 32% of managers say remote work has increased productivity. That’s because of a lack of commute, less nonessential meetings and fewer distractions than in the office, according to the survey.
“We’ve learned that we have a lot of employees who can get their work done remotely. We’ve traditionally never thought that way,” Smith said. “We’ve found the production of a lot of folks is up because they can get things done at home. Their days may extend to 6:30, 7:30 at night because of all the phone calls and time differentials. It’s actually very interesting. There are going to be a few persons who have to be at work, but we’re questioning who does really need to come back in the office.”
“Part of what’s challenging is people want to get back to work,” Magness said. “We’ve never stopped working, but people want to get back to their environments. Those environments are not what [they were].”
Staying the Path
In contrast, protecting employees in the field or control rooms is much easier. Smith said AEP’s work crews complete health self-assessments each day on an app. If an employee answers positively to one of the questions, their supervisor gets an email that indicates the employee needs to stay home.
“That’s our first line of defense: the employee staying home,” he said. “We’re asking employees, as best they can, to separate themselves with their vehicles. If there are three or four of them working on an issue, we may have three or four trucks at the jobsite, just to maintain social distancing.”
ERCOT CEO Bill Magness during a GCPA webinar on the future of work | GCPA
Austin-based ERCOT has isolated controllers in its two operations centers in nearby Taylor and Bastrop. When a 12-hour shift ends in Taylor, the next shift begins in Bastrop while the Taylor ops center is sanitized.
Smith said the remote work environment has revealed a need for different ways of communicating. Zoom and Microsoft Teams can only go so far in bringing together staff from disparate locations and instilling a sense of camaraderie.
“It’s very hard to replicate face-to-face time with electronic tools,” he said. “One of the things we find, like staff meetings on the web, is someone makes a joke, but no one hears anyone laugh. Everyone’s on mute. That kills camaraderie right there.”
“That’s right! That’s a terrible thing,” Magness responded.
Turning serious, Magness said the current environment has left him pleased with staff’s ability to get their work done in a difficult setting.
“From ERCOT’s perspective, we’re really gratified with the way people have stepped up,” he said. “We have to remember this is unusual. This is odd. People will have different reactions to this. We need to constantly think about who we were when we started this, who do we want to be, and how do we stay on that path until this is over.”
Nuclear Energy Institute CEO Maria Korsnick is always upbeat and optimistic about the future of nuclear energy when she makes her annual State of the Industry address, emphasizing plants’ emissions-free nature, high capacity factors and reliability.
Korsnick’s address this year, conducted online as it has been for the last two years, was no different. (See NEI CEO: FirstEnergy Emergency Request a ‘Bridging Strategy’.) But after the usual quick, bright and positive speech and soft question-and-answer with NEI spokeswoman Monica Trauzzi, NEI on Wednesday hosted a panel discussion featuring Union of Concerned Scientists President Ken Kimmell and Renewable Energy Buyers Alliance (REBA) CEO Miranda Ballentine. Both expressed general support for nuclear’s role in a future, zero-carbon generation mix, though both couched it with contingencies.
NEI CEO Maria Korsnick | NEI
In her opening speech, Korsnick positioned nuclear not as a competitor with renewables but as a partner. Though she noted that nuclear provides more than half of all carbon-free generation in the U.S. (as she did last year), “I want to be absolutely clear: We need to develop every source of carbon-free energy that we can. The world is counting on carbon-free resources to complement one another, not just compete. Our choice isn’t between nuclear power or wind and solar. It’s between a status quo of rising emissions from fossil fuels or a low-carbon future from all available sources, including nuclear.”
As evidenced by its name, REBA members — consisting of large corporations such as Facebook, Google and Walmart — have focused their procurement targets on renewable resources, particularly utility-scale wind and solar. But Ballentine said that “there has been a fairly significant transformation in the mindset of large clean-energy buyers, actually quite recently I would say … from goals of 100% renewable energy, to now companies thinking about 24/7/365 zero-carbon power, where renewable energy is one means to that end.”
REBA members “are beginning to think about other forms of zero-carbon power” besides large wind and solar projects, Ballentine continued. She listed geothermal, landfill gas and hydropower, “which is the one that tends to get left out of the discussions so frequently.”
ClearPath Executive Director Rich Powell (top left) moderates a discussion with REBA CEO Miranda Ballentine and UCS President Ken Kimmell. | NEI
But she said nuclear presents unique concerns for the organization: “What do we do with the waste, how do we handle proliferation, and how do we handle safety? … To the extent that new nuclear [technology] addresses some of those three core challenges of the existing fleet … I think you’re going to start seeing large consumers of power being more interested in the potential role that new nuclear can play.”
Kimmell emphasized “the herculean challenge” of not only using 100% clean energy but electrifying transportation and building heating. “This is a gigantic challenge that implies a pace of expansion of our electric grid in a way that we’ve never come close to doing in history,” he said.
Ballentine agreed. “I would say that many of the members in REBA … have a sense of urgency around the timeline that even 2050 for the power system is too late because there are so many other parts of our economy that are much harder to decarbonize.”
“To meet a challenge like” avoiding permanent climate change, Kimmell said, “all of us need to be prepared to abandon a tribalistic attachment to particular solutions.”
Monica Trauzzi, NEI | NEI
ClearPath Executive Director Rich Powell, who moderated the panel, echoed those sentiments. “I think that lesson of stopping being against the things we’re not specifically for — and eventually becoming for the things we’re not specifically for — is … just a crucial mental frame to adjust [to] as we respond to a challenge this enormous.” ClearPath, formed in 2014, seeks to “develop and advance conservative policies that accelerate clean energy innovation.”
Kimmell warned, however, that UCS’ support for nuclear power was conditioned on maintaining the Nuclear Regulatory Commission’s strict safety regulations for plants. “And I should say this is an area where it’s hard for us to work cooperatively because we don’t support efforts to relax those standards, and to the extent that those standards do get relaxed, we’re going to need to reconsider that criteria” of support, he said.
He also said any financial support through legislation should be reserved for plants that “meet or exceed the NRC’s highest safety standards.” He pointed to UCS’ 2018 report that recommended policies such as a national carbon tax or clean energy standard that would prevent existing nuclear plants from retiring earlier than their expected useful life.
