ORLANDO, Fla. — Tim Fritch, vice chair of NERC’s Synchronized Measurements Subcommittee, said June 4 that his panel’s research into the Jan. 11 Eastern Interconnection oscillation event has identified the need to improve data sharing and provide guidance for responding to such events.
Fritch briefed NERC’s Planning Committee on a survey the subcommittee created to determine whether utilities were aware of the event and how they responded. NERC reported earlier that the event lasted about 18 minutes, with power swings of 200 MW around Florida and 50 MW around ISO-NE.
Eleven utilities responded to the survey, including both transmission operators and reliability coordinators, and nine said they were aware of the event. Only two utilities reported taking action in response, both taking some of their units out of automatic generation control when they were oscillating, Fritch said.
Seven of the utilities agreed there is a need to develop both a phasor measurement unit data-sharing requirement for RCs, and a real-time regional oscillation and source detection tool. The same number agreed the SMS should identify and address gaps in existing reliability standards on RC-to-RC coordination.
The event was illustrated in a video by the University of Tennessee’s FNET/GridEye tool.
“It was hard to tell, unless you saw the very beginning of that video, who was creating the oscillation and who was responding,” said Fritch, an electrical engineer for the Tennessee Valley Authority. “And then going back and listening to RC calls, it was hard for the RC operators to understand where this all originated. So, I think we all agree this is something that needs to be addressed because a lot of these operators were essentially flying blind. Fortunately here, there were only two utilities that took action. … We know that, depending on what units were taken offline, it could have made the oscillation worse. … We need to address that and provide guidance to our operators about what to do when we have these type of events — or what not to do.”
Rob Cummings, NERC’s senior director of engineering and reliability initiatives, said that using FNET/Grid Eye “within 15 minutes I knew that it was a forced oscillation … and I also pinpointed the beginning and end to be in Tampa, Fla. So, if I could do that … the operators could too. And I’m more than willing to put together tutorials on how to determine this for the RCs.”
Fritch said the SMS would “essentially hand [the issue] off” to the Operating Reliability Subcommittee for additional discussion.
ORLANDO, Fla. — NERC’s task force on electromagnetic pulses (EMPs) will hold its first face-to-face meeting at the ERO’s offices in D.C. on June 12, but if you’re not already signed up, it’s too late to attend in person.
Director of Engineering and Standards Howard Gugel told a joint meeting of the Operating, Planning and Critical Infrastructure committees here on June 4 that the meeting was already full but that the daylong session will be accessible via WebEx.
Gugel said NERC is planning a workshop on the subject for late July that will be held in a larger venue.
The task force was formed in response to the Electric Power Research Institute’s April report on EMPs, which concluded that a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers have warned of. The EPRI report focused on the grid and transformers and did not examine potential impacts on generation. (See “NERC Task Force to Build on EPRI EMP Study,” NERC Standards News Briefs: May 8-9, 2019.)
“As we knew this report was coming out, we decided we needed to get a better understanding of how EMPs could affect our grid and if there were any potential actions that needed to be taken,” Gugel said. “So we reached out to the trade organizations to ask for a small representative number of individuals who had some expertise in the area that could look through the report and determine if there were any immediate actions that needed to be taken and to provide some direction.”
Gugel said the task force has not been formalized with a reporting relationship to any standing committees but that its structure could change in the future.
The task force, which is broken into three committees, will make any recommendations to the technical committees by the third quarter. Guidelines or best practices is one potential result, he said.
“Of course, everyone hates to use the dreaded SAR [standard authorization request] word. We’re certainly not jumping to any kind of standards solution,” he said. “But if, when that team is looking at that, they feel there’s something that needs to be addressed — whether it’s through our existing body of standards or a new [one] they develop — then that SAR would be presented to the Standards Committee, if applicable, in the fourth quarter of this year.
“I don’t want to raise everyone’s standards radar at this point,” he added. “I want to assure you that this is not the priority that this team is looking at.”
Supply Chain Data Request Coming
Gugel also said NERC staff are collaborating with the Supply Chain Working Group to develop a data request on supply chain cybersecurity that should be issued about July 2.
The data request is in response to a recent staff report that recommended additional study on whether low-impact systems with external routable connectivity should be covered by reliability standards. (See “Supply Chain Report Recommends Expanding Standards,” NERC Standards News Briefs: May 8-9, 2019.)
Gugel said staff drafted “strawman” questions for debate by the working group. “Any time we, as staff, try to develop something like that, we always seem to ask the wrong questions. So I’m very grateful that we get industry weighing in on this and helping us get the right questions.”
The responses will be due July 22, in time to share results with the Board of Trustees at its August meeting, Gugel said.
ORLANDO, Fla. — NERC’s Planning Committee acted on three reliability guidelines during meetings June 4-5, prompting SPP’s Shannon Mickens to ask how standards enforcement officials will treat entities that do not choose to follow them.
He noted that the guidelines state that ERO Enterprise Compliance Monitoring and Enforcement Program (CMEP) staff will give examples endorsed in such documents “deference when conducting compliance monitoring activities.”
“You say this is one way to meet your compliance. So, doesn’t an entity technically have to adopt that document?” Mickens asked.
Tim Fritch, vice chair of the Synchronized Measurements Subcommittee, said he shared Mickens’ concern. “We have gone round and round on this,” Fritch said. “So, if I don’t follow this, am I in compliance or not? … I guess the other way to do it is to try and cover every aspect [of compliance in the guidance document] and that’s” unrealistic.
PC Chair Brian Evans-Mongeon said entities should take up such questions with their regional entity’s compliance department. “There’s no way an implementation guidance document will answer every question,” he said. “We already know there are regional differences from time to time on subject matters, so your region may be willing to consider it differently than others.”
Evans-Mongeon also said the PC can submit implementation guidance to the compliance monitoring group. “So, if people have particular items that they would like to have passed on through, we’d be happy to assign it to a group and take a look at it.”
The chair also said that at its next meeting, the PC Executive Committee will consider creating a schedule for reviewing and updating existing guidelines about every three years.
Voting Actions
The committee:
Approved the application guide for Modeling Turbine-Governor and Active Power-Frequency Controls in Stability Studies to ensure turbine-governor models produce accurate angular stability, frequency stability and primary frequency response simulations. Applicable to: generator owners (GOs), generator operators (GOPs), transmission planners (TPs), planning coordinators (PCs) and power plant modelers as well as balancing authorities, transmission operators (TOPs) and reliability coordinators when performing stability studies.
Authorized posting of reliability guideline DER_A Model Parameterization for a 45-day comment period. The guideline is intended to avoid incorrect parameters that can prevent the DER model from capturing the frequency, voltage or trip settings needed to represent system performance accurately. Applicable to: PCs, TPs, TOPs and RCs.
Approved the Modeling Notifications process document, which explains the work of the System Analysis Modeling Subcommittee. The process allows SAMS to receive modeling information from power system modeling subject matter experts and simulation tool users and develop modeling notifications as needed.
Approved the Electric-Gas Working Group scope. The group will initially focus on developing guidance or guidelines for considering fuel-related risks in planning studies and system analysis.
Philosophical Question on Inverter-based Resources
ERCOT’s Jeff Billo, vice chair of the Inverter-based Resource Performance Task Force (IRPTF), raised what he called a “philosophical” question posed by the challenges of asynchronous generation displacing synchronous machines.
“As we move forward to more and more inverter-based generation, do we need to require the inverter-based generators to behave more like synchronous machines or do we change our philosophy of how we operate the system and make the system more accommodating to inverter-based [machines]?” he asked. He said he had not settled on an answer.
Billo cited studies showing that the grid cannot run on 100% “grid-following” inverters, whose control systems rely on strong 60-Hz signals from synchronous machines. “I really don’t like the term ‘grid forming’ inverter technology but that seems to be becoming the buzz phrase that people are using,” he said.
“You really need some of those to be grid-forming inverters. … I don’t think we’re at a point where we can specify technically what grid-forming means but there’s a lot of good discussion going on about that.”
Battery and Energy Storage Workshop Planned
NERC, the North America Generation Forum and the Energy Systems Integration Group are planning a workshop on battery and energy storage in September or October, John Moura, NERC director of reliability assessment, told the committee.
Chair Evans-Mongeon said the goal of the workshop will be to identify the impact of storage on the bulk power system and determine “if there is something of growing significance that warrants our attention.”
“I’m told there are two 400-MW battery systems that are slated for the West to come online this year. There is another proposal that I just saw earlier this week for a 1,000-MW compressed gas storage facility in the salt caverns of Utah,” he added.
Billo said that a workshop the Texas grid operator held on the subject in April attracted the biggest crowd of any stakeholder event in the last 10 years. “So, there’s a lot of interest,” he said. (See “Workshops Discuss Storage, Inverter-based Resources,” ERCOT Briefs: Week of April 22, 2019.)
Moura said the NERC session will likely be in D.C., with web access.
PC Chair Re-elected; MOD-32 SAR Reviewers Appointed
Evans-Mongeon (Utility Services) was re-elected as PC chair for a two-year term. Joe Sowell (Georgia Transmission) was elected vice chair, replacing Noman Williams (GridLiance).
Evans-Mongeon and Sowell also were appointed as reviewers for the System Planning Impacts from Distributed Energy Resources Working Group’s (SPIDERWG) draft standard authorization request to revise MOD-032-1 (Data for Power System Modeling and Analysis) to improve modeling of DER in planning studies.
Joining them will be Billo; Jason Spitzkoff (Arizona Public Service); Carl Turner (Florida Municipal Power Agency); Wayne Guttormson (SaskPower); Christine Ericson (Illinois Commerce Commission); Phil Fedora (NPCC); and Enoch Davies (WECC).
The current standard addresses the collection of modeling data for interconnection-wide base cases but has no provisions regarding DER data. The SAR proposes to include data requirements and reporting procedures for DER and replace the term load-serving entity with distribution provider (DP) because of the removal of LSEs from the NERC registry criteria.
Electronic Vote Set for PRC SAR
The committee will conduct an electronic vote on a SAR to amend PRC-019-2 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection) to address distributed power resources.
The standard, which addresses the reliability issue of miscoordination between generator capability, control systems, and protection functions, was developed for synchronous generation and “does not sufficiently outline the requirements for all generation resource types,” the SAR says. The initiative would seek to correct or clarify issues regarding synchronous generation to remove ambiguity.
Member Roundtable
In the member’s roundtable that closed the meeting, Williams and Turner expressed concern about the ERO’s ability to keep up with the accelerating rate of change in the industry. “Some of it’s driven internally, but I think a lot of it is driven by policymakers that are making decisions that are forcing us to do things that drive change, but they also stretch reliability and resiliency,” Williams said.
Turner noted the increasing involvement of manufacturers in NERC’s process as a result of changing technology. NERC should not stifle innovation, he said, but it must take the time to ensure that new technologies are properly vetted. “We have a duty, first and foremost, of providing safe, reliable power,” he said. “And we can’t just have it be a gold rush here: Some people got rich; some people got hurt. … I worry about that. Let’s stay vigilant as we try to keep up with all this.”
CHEYENNE, Wyo. — Commissioners from a dozen Western states gathered here to share their concerns and discuss the challenges of their jobs. At the top of the list was the role politics is playing in their decision-making.
Two panels at the annual Western Conference of Public Service Commissioners meeting held June 2-5 were set up to allow regulators to pose questions to their colleagues from neighboring states and prompt discussions.
Some asked if regulators should advocate for legislation or cheerlead for their utilities on Wall Street. Others questioned whether policy agendas — not reliability or affordability needs — are driving the rapid increase in wind and solar power in the West. And still others talked about the way state politics affect their internal processes.
In the case of California, for instance, lawmakers have been pushing the Public Utilities Commission to act with greater speed in the face of catastrophic wildfires and the Pacific Gas and Electric bankruptcy. They’ve frequently criticized the PUC for acting too slowly, Commissioner Clifford Rechtschaffen said during the first commissioners’ panel Monday. (See Lawmakers Grill CPUC President on PG&E, Fires.)
“The criticism intensified over the past year with the PG&E bankruptcy,” Rechtschaffen said. It’s true the CPUC moves slowly, he said. It’s set up to make big decisions slowly and deliberately based on the record before it, he said.
“A lot of people want us to make our processes more informal and quicker,” he said. “How do we do that … while still ensuring the integrity of our process?” Or, he asked, should the PUC maintain its plodding formality while responding to hundreds of rate cases?
“We’re deciders, not policymakers,” Rechtschaffen said. Without clear guidance from the legislature, it will be difficult to change course and speed, he said.
Megan Decker, chair of the Public Utility Commission of Oregon, empathized.
“Having deadlines mandated on us is a pet peeve for me,” she said. And “not having clear expectations from the legislature means having more work at the commission level.”
Idaho Public Utilities Commission President Paul Kjellander said, “Lawmakers say they want to see regulation at the speed of technology.” In many cases, new technology presents cases without legal precedent, requiring more time, he said. “How do we get that message across to policymakers trying to speed things up?”
There should be no regulatory lag, he said, but cases should be decided in the “time it takes to make a good decision, and then call it a day.”
He also took issue with Western policies driving green energy projects, which he described as “policy-driven economics.”
PacifiCorp subsidiary Rocky Mountain Power last year came forward with a proposal to add 1,150 MW of new wind power, but Idaho won’t have an electricity deficit until 2026, Kjellander said. Under the longstanding principle requiring new utility assets to be “used and useful” to ratepayers before they’re made to foot the bill, the three new wind projects would have been a “no go,” he said. Yet the commission approved the projects, located in Wyoming, last year, he said. The utility, which serves parts of Idaho, Utah and Wyoming, needed to get them into service by 2020 to take full advantage of the federal production tax credit.
Commissioner Ann Rendahl said the Washington Utilities and Transportation Commission had gotten plenty of instructions from state lawmakers. “We got two gifts from them this year,” she said with a hint of sarcasm.
One directs the UTC to implement a new state policy mandating that Washington go carbon-neutral by 2030 and 100% carbon-free by 2045.
Another change affects ratemaking, allowing utilities to begin recovering costs for their four-year clean energy implementation plans in advance of acquiring or building out the needed resources to meet the targets under those plans. That’s a big change for Washington, which traditionally has granted returns only on past investments, Rendahl said.
“We’re a historical state,” she said.
In her question to colleagues, Decker asked about having to integrate sectors in which regulators don’t traditionally have expertise, such as emergency preparedness.
Rendahl said her commission had been given oversight of party boats, provoking audience laughter.
Rechtschaffen said California regulators had dealt with a lack of experience by signing memoranda of understanding with sister agencies. “The area we’re seeing it most acutely is … wildfire safety.” The PUC signed MOUs with the state Department of Forestry and Fire Protection and Office of Emergency Services. It’s been “shameless” about partnering with federal agencies and seeking help from Silicon Valley, he said. (See Silicon Valley Tackles Wildfire Prevention.)
Montana Public Service Commission Chairman Brad Johnson said he had been working with a colleague to build a regional structure through the Council of State Governments to foster communication between lawmakers and regulators.
“We need to be careful we don’t come across as lecturing our legislative counterparts,” Johnson said. “I think if we don’t approach this carefully, we could create some real pushback.”
‘My Little World’
A second panel of commissioners on Tuesday raised questions about talking to Wall Street analysts.
Washington UTC Commissioner Jay Balasbas said he had once accepted an invitation to an analyst talk, though he had deep misgivings.
Utah Public Service Commissioner Jordan White said he would most likely decline such an invitation. “With rate cases before me, I would probably say no.”
The commissioners also questioned whether regulators should be seen as endorsing bills.
“You have to measure how much is appropriate risk and how much is risk you can take,” said Jeff Ackermann, chairman of the Colorado Public Utilities Commission. For instance, when being asked to testify as a subject matter expert on a bill, “It’s unclear whose team, if any team, I’m on or trying to be an adjunct player for. What is an appropriate role?”
Generally, commissioners aren’t supposed to advise lawmakers on policy development, he said. The old saying is that regulators are “policy takers, not policymakers,” he said. “But as energy policy gets more complex, we’re going to be drawn into it.”
White said there are times regulators should address lawmakers in a “very mechanical, technical” manner to provide expertise, but that speaking with policymakers usually makes him uncomfortable.
“It gets dangerous when they try to pull us into their lane,” White said. “As much as I can, I try to stick to my little world.”
FERC gave PJM stakeholders just 90 days to settle all disputes about how to best liquidate financial transmission rights left over from the GreenHat Energy default before kicking off a paper hearing on the RTO’s request to clarify a previous ruling related to the debacle.
In an order issued Tuesday, FERC encouraged conflicting parties to hammer out disagreements ahead of the hearing under the guidance of a settlement judge, who will report progress on the discussions to the commission at the 45- and 90-day marks (ER18-2068). A one-time extension may be granted for 30 days, FERC said.
The order also granted PJM’s motion for clarification on its denied petition to waive its liquidation rules, which has complicated the RTO’s efforts to minimize the damage of the default and potentially increases costs to members by $300 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
In the absence of a rehearing, PJM had requested clarification on six different issues arising from the rejected waiver order that would force the RTO to unwind five months of FTR settlements and rerun the cleared July 2018 auction.
“The issues raised in the PJM motion for clarification and the subsequent answers demonstrate that there are multiple complexities associated with implementing the waiver order directive that should be addressed in a paper hearing where all parties will have an opportunity to present written evidence and argument,” the commission wrote.
Apogee Energy Trading and Elliot Bay Energy Trading both filed answers to PJM’s motion, with the former urging the RTO to follow Tariff provisions as closely as possible when rerunning the July auction using uncleared bids that do not violate the simultaneous feasibility test. The company argued the RTO’s motion favors one group of stakeholders over another “in terms of the allocation of the GreenHat default and by misrepresenting and potentially overstating the impact of the GreenHat default on the PJM market.”
Elliot Bay likewise complained that PJM’s proposed implementation steps would violate the filed rate doctrine and the related rule against retroactive ratemaking. “The PJM motion for clarification raises numerous issues of material fact that should be addressed in a technical conference, hearing or stakeholder process,” the company wrote in its March 13 filing.
PJM said, “There’s nothing simple about rerunning an auction and settling market positions” and contended that the accusations of discrimination were unsupported.
“While we are setting these matters for a paper hearing, we encourage the parties to make every effort to settle their disputes before the paper hearing commences,” FERC wrote, noting the paper hearing will be delayed to give enough time for negotiations. “Although the paper hearing is limited to PJM’s motion for clarification, we are not establishing similar limitations on the scope of the settlement discussions, and the parties are encouraged to address all disputes arising out of this proceeding.”
“We’re pleased that the commission set the matter for settlement,” PJM spokesperson Jeff Shields said Wednesday. “And we are hopeful that we will reach a resolution of the issues.”
LS Power filed a complaint Wednesday asking FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV and change its approach to estimating the benefits of smaller projects.
The complaint under Federal Power Act Section 206 requests the commission to order reforms on a 60-day deadline that establish cost allocation for market efficiency projects (MEPs) below 345 kV (EL19-79).
Currently, MEPs must meet a voltage threshold of at least 345 kV and cost at least $5 million. However, MISO earlier this year filed a Tariff revision to lower the threshold to 230 kV, a change that RTO staff have said will reflect the reality of a footprint where 230-kV lines are prevalent. (See MISO MEP Cost Allocation Plan Goes to FERC.)
FERC has yet to rule on the requested change, and LS Power has also filed its complaint in the docket for the associated proceeding (ER19-1124).
Comparison of lower voltage facilities in MISO | MISO
In its complaint, LS Power argues that reducing the voltage threshold to 100 kV would “remedy flaws in MISO’s economic planning process” and also expand the number of projects eligible for competition, consistent with FERC Order 1000.
“The commission should require MISO to resolve this issue quickly as it has been aware of this deficiency in its economic planning process for several years and failed to solve it in a just and reasonable manner,” LS Power said.
The company contends that MISO’s planning process fails to provide a “clear path” for regionally beneficial economic projects at lower voltages, resulting in “unnecessary congestion costs and unjust and unreasonable rates.”
Not Far Enough
MISO’s filing does seek to address at least some of LS Power’s concerns by creating a new category for economic projects below 230 kV and above 100 kV for which 100% of costs would be allocated to a local transmission pricing zone, rather than across multiple zones. Such transmission projects were previously categorized as “other” projects without clear allocation rules.
But the company said the RTO’s cost allocation proposal doesn’t go far enough and argued that economic projects below 345 kV can relieve congestion in multiple transmission pricing zones.
“There are not clear criteria or procedures for identifying and evaluating economic projects outside of the Market Efficiency category to determine whether they provide regional benefits and thus should be selected in MISO’s regional transmission plan. As a result, economically beneficial projects may not be identified or may otherwise stall during the planning process to the detriment of ratepayers,” LS Power said.
| LS Power
The company’s complaint goes a step beyond the cost allocation issue, asking FERC to find MISO’s current MEP planning process unjust and unreasonable because it doesn’t outline a path for planning regionally beneficial economic projects that don’t meet MEP criteria. The company also pointed to a substantial amount of 100- to 200-kV facilities in the MISO footprint, saying it’s likely the RTO has overlooked similar smaller projects that would reduce congestion across the footprint.
LS Power also charged that the MEP voltage threshold undermines Order 1000 because such a strict voltage criteria “effectively grants incumbent transmission owners in MISO a federal right of first refusal to build regionally economic enhancements that do not meet the market efficiency project thresholds.”
“It is time for the commission to send a clear message that it will not allow such end runs around Order No. 1000,” LS Power said. While it is difficult to gauge the financial harms related to MISO’s 345-kV voltage requirement for MEPs, the company said it is making a “good faith effort” to estimate the number of projects it may have lost out on.
The company also said it has already raised its MEP-related concerns with both MISO staff and in the RTO’s Regional Expansion Criteria and Benefits Working Group, where cost allocation decisions are made.
LS Power’s Republic Transmission is currently in the process of building the Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky, the RTO’s first competitive transmission project. (See Texas ROFR Law Clouds Hartburg-Sabine Future.)
Three nuclear plants facing early retirements in Pennsylvania and Ohio would keep wholesale energy market net-load payments lower — in most cases — if they stay online, a PJManalysis released Tuesday concluded.
But there’s one caveat: The study’s projections don’t include the costs of potential subsidies.
That point is an important one for critics of out-of-market payments designed to prop up certain forms of generation. Supporters argue, however, that nuclear power’s benefits of reliability and zero-carbon emissions make it stand apart and deserve special consideration.
“The PJM report confirms that consumers and the environment benefit by preserving existing nuclear plants and replacing aging, carbon-intensive coal generation with new renewables and natural gas,” said Paul Adams, spokesperson for Exelon, owner of the nation’s largest nuclear fleet — including the soon-to-be shuttered Three Mile Island near Harrisburg, Pa. The company’s attempt to make the plant profitable through a state-imposed subsidy failed in that state’s legislature last month. (See Exelon to Close Three Mile Island.)
Adams said the report reaches the same conclusions of multiple other analysts and consultants that found “retaining the nation’s existing nuclear plants is the cheapest way to maintain environmental progress and would cost consumers billions less than allowing them to retire.”
But it seems lawmakers and regulatory bodies in both Pennsylvania and Ohio have remained unconvinced that extending the lives of nuclear plants overrides the need to maintain a competitive wholesale electricity market. Both the Pennsylvania Public Utility Commission and the Ohio Consumers’ Counsel requested the PJM study to better grasp the cost and emissions impacts of retiring reactors at Beaver Valley, Davis-Besse and Perry nuclear plants as proposals to enact subsidies for all three still pend before lawmakers.
“It was counter to logic when FirstEnergy Solutions testified in the Ohio House of Representatives that electric consumers would pay more if its antiquated nuclear plants are shut down,” said J.P. Blackwood, spokesperson for the OCC. “PJM’s findings for consumer savings from power plant competition confirm that a competitive generation market is better for millions of Ohio consumers than charging them for bailouts and subsidies under House Bill 6.”
PJM Simulations
PJM obliged the requests by creating six scenarios against which to compare what the RTO considers its base case: all three plants retire, and scheduled gas and renewable generators with an in-service date of 2023 come online, reducing net-load payments by $1.6 billion. Carbon dioxide emissions would likewise decrease by 4.3 million tons, while nitrogen oxide and sulfur dioxide emissions would fall by 37,900 tons and 18,200 tons, respectively, the analysis concluded.
Should all three nuclear plants stay operational and new generation enters the market as planned, net-load payments would decrease by an additional $474 million from the base case. In Pennsylvania, emissions of CO2, NOx and SO2 would decrease from the base case by 4.7 million tons, 5,000 tons and 3,300 tons, respectively. In Ohio, the additional emission reductions total 3.7 million tons, 2,400 tons and 3,500 tons, respectively.
The results are similar — net-load savings increase and greenhouse gas emissions decrease — when either just Beaver Valley or the Ohio plants stay online, PJM found.
Simulation results summary | PJM
Tom Becker, a spokesperson for FirstEnergy Solutions, the bankrupt company that owns Davis-Besse and Perry, said Wednesday that the simulations confirm that their plants provide valuable benefits to Ohio, including $30 million in annual state and local tax revenues, a diversified resource mix, 4,300 jobs and 90% of the state’s zero-emission energy.
PJM went a step further, however, and modeled the impact of a 50% reduction in new gas-fired generation coming online as a reaction to nuclear subsidies entering the market.
If all three plants remain operational and planned gas projects decline by half, net-load payments would decrease by $91 million from the base case.
“This is because the retention of all the nuclear plants and their associated energy production is sufficient to offset the impact of the reduced new entry,” the study noted. “This reduction in customer payments, however, is not netted against the cost of a potential subsidy to consumers in a particular state.”
Under that scenario, carbon emissions would likewise plummet from the base case by more than 9.5 million tons in both states combined with smaller decreases in NOx and SO2.
If either state retires their plants while the other’s stay online, however, net-load payments increase from the base case by between $164 million and $240 million. Emissions would still decrease in Ohio, but Pennsylvania’s NOx and SO2 emissions would both rise, because of the reliance on less efficient coal-fired generation in the absence of new gas units.
Joe Bowring, PJM’s independent market monitor, said Thursday the latter scenarios — losing only a few of the plants and at least half of the planned gas generation — are far more likely than the other simulations.
“Those models are a lot more realistic,” he said. “I would have discounted the new gas units even more than 50% [to account for impacts of potential subsidies].”
Subsidy Plans Alive in Both States
It’s not clear how PJM’s analysis will move the needle — if at all — in the state legislatures, where plans to subsidize all the plants still remain active.
Ohio’s proposed Clean Air Program was still pending before the Senate as of Wednesday, one week after the lower chamber approved the controversial measure to effectively gut the state’s renewable portfolio standards in favor of ratepayer fees for FirstEnergy’s nuclear plants. (See Ohio Plan Subs Nuke, Fossil Fuels for Renewables.)
Meanwhile, a bill to expand Pennsylvania’s Alternative Energy Portfolio Standard to include nuclear power languishes in the House Consumer Affairs Committee while lawmakers tend to the annual budget, due June 30. The delay meant the bill couldn’t save TMI, but state officials said that doesn’t mean the issue is dead. (See Nuclear Subsidies Still on the Table in Pennsylvania.)
The future of MISO’s second-ever competitively bid transmission project could be in jeopardy after passage of a Texas law that grants incumbent utilities the right of first refusal (ROFR) to build projects within the state.
MISO last year selected NextEra Energy Transmission Midwest to construct the Hartburg-Sabine Junction 500-kV project in East Texas. NextEra proposed to spend $115 million to build the project, which would consist of a new 23-mile single-circuit 500-kV line, four 230-kV lines and a new substation. The company sought a $95 million transmission revenue requirement (TRR), and its winning proposal scored 97 out of a possible 100 points in the bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)
| NextEra
But the new Texas law casts doubt on NextEra’s ability to proceed with the highly anticipated market efficiency project. Gov. Greg Abbott signed the ROFR bill into law May 17 after the state House of Representatives voted 139-5 to pass it and it cleared the Senate 31-0.
Referring to ERCOT’s historical exemption from FERC oversight, Rep. Dade Phelan (R), a sponsor of the bill, told legislators in May that the bill will “ensure the Public Utility Commission, and not the federal government, will have jurisdiction over Texas transmission rates.” (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
But opponents contend the law will undercut competition by prohibiting anyone but incumbent utilities to build Texas transmission and prevent the PUC from licensing new entrants to the transmission market.
MISO says it is reviewing the developments but still expects construction will proceed on the congestion-relieving line.
“MISO is committed to delivering the benefits of the Hartburg-Sabine Junction 500-kV transmission project in East Texas in accordance with its regional transmission plan and in compliance with applicable laws and regulations,” Director of Strategic Communications Julie Munsell told RTO Insider. “MISO is reviewing the applicable Tariff provisions and will determine the appropriate steps.”
The RTO emphasized that its studies show the project will “alleviate longstanding energy congestion issues and import limitations, allowing lower-cost generation to serve customers in the area.”
MISO representatives declined a request for further interview on the matter.
In 2016, MISO respected Minnesota’s existing ROFR when it declined to open the $80.9 million Huntley-Wilmarth 345-kV line project to competitive bidding. At the time, MISO’s legal team said the RTO must respect state and local laws. (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)
Big, Swift Change
In testimony in April, NextEra Energy Transmission President Aundrea Williams said that if the Texas ROFR legislation passed, it would “without question” force customers in East Texas to “pay more for this key transmission project and lose out” on benefits because of the lack of competition. Williams also said the MISO competitive process found that NextEra’s proposal would save customers tens of millions of dollars when compared to other proposals. She cautioned that the bill would have “real detrimental” consequences for Hartburg-Sabine.
“This bill is a big change to Texas transmission markets, and a swift change. A change so big it that it will have an impact on every single Texan and so fast that there is insufficient time to have an opportunity to fully evaluate all the possible negative implications that will ripple across the state. The bill will impair a longstanding market fundamental that underpins the overall structure of the Texas electricity market that has served Texans well for many years,” Williams said.
Incumbent transmission owner Entergy was one of 12 developers to bid on the project under its EasTex TransCo subsidiary. While MISO does not release specific details about losing proposals in competitive solicitations, general data released by the RTO regarding Hartburg-Sabine showed submitted bids ranged from $95.4 million to $133.9 million, while TRRs ranged from $88.2 million to $166.3 million.
Entergy did not respond to an inquiry about its proposal or its intentions regarding the project in light of the ROFR law. NextEra also declined to comment for this story.
In March, FERC granted NextEra an abandoned plant incentive, allowing the company to cover 100% of its investment if the Hartburg-Sabine project is canceled for reasons outside the company’s control. (See NextEra Gains Incentive for Hartburg-Sabine Project.)
A three-judge D.C. Circuit Court of Appeals panel said last week the Surry-Skiffes Creek transmission line in Virginia can remain operational — for now — while the legal battle over the U.S. Army Corps of Engineers’ permit for the $400 million project ensues in a lower court, where judges could ultimately force Dominion Energy to tear it down.
In March, the panel said the corps violated the National Environmental Policy Act by not issuing an environmental impact statement (EIS) and vacated the permit for the project, which crosses the James River and passes in close proximity to several historic parks and trails “dating back to the birth of our nation.”
In an appeal, the corps and Dominion did not dispute that the permit was illegal, but they requested the court remand the project back to the corps without vacating the permit, saying the court did not “have before it the recent factual developments regarding completion of construction and the disruption that vacating the permit could cause.”
“That, of course, is because neither petitioner bothered to advise us that construction on the project had been completed and the transmission lines electrified the week before we issued our opinion,” the judges said in their March 31 decision.
The National Parks Conservation Council and National Trust for Historic Preservation had originally appealed the permit in the D.C. District Court. Opponents have contended the line will ruin the view at Jamestown and other nearby historic sites, dismissing as a scare tactic Dominion’s warning that failure to build will result in blackouts in Virginia’s middle peninsula. (See Opposition to Va. Tx Line May Trigger Unintended Consequences.)
The corps and Dominion argued the permit should stand and the 500-kV line should stay in service to maintain reliability and provide power to the 600,000 residents on Virginia’s peninsula. PJM first greenlit the project in 2012 as the best solution to fill the gap left behind by the retirement of two coal-fired plants in Yorktown deemed incapable of meeting federal emissions standards. Dominion electrified the line in February and wants to keep it operational while the corps conducts the court-ordered EIS, slated to take at least a year to complete.
The D.C. Circuit remanded the case back to the district court to decide whether the request is even feasible. It admonished the utility company and the corps for not notifying it that the project was finished before it made its decision.
“Had the corps and Dominion said all along what they say now, either the district court or this court might have enjoined tower construction, in which case our consideration of ‘disruptive consequences’ … would focus not on shutting down and removing the towers, but rather on prohibiting their construction — a very different balance indeed,” the panel said. “Moreover, having completed construction, petitioners now attempt to use it to place an even heavier thumb on the scale.”
The plaintiffs argued that by not disclosing that the project was operational before the court made its decision, the corps and Dominion had waived their right to argue that vacating the permit would be too disruptive. They noted that to defeat their motion to prevent construction, the corps and Dominion had assured the lower court if it required the corps to issue an EIS, the project could be dismantled without a problem. The circuit court said this was “more than a little troubling.”
However, “we nonetheless believe the best course of action is to remand the case to the district court to consider … whether vacatur remains the appropriate remedy, including whether [the corps and Dominion] have forfeited or are judicially estopped from now opposing vacatur,” the D.C. Circuit said. “That court is best positioned to order additional briefing, gather evidence, make factual findings and determine the remedies necessary to protect the purpose and integrity of the EIS process.”
Paul Edmondson, interim president and CEO for the Nation Trust for Historic Preservation, applauded the ruling in a statement last week, noting the decision underlines “the historic significance of the James River.”
“There are feasible alternatives to this transmission line, but there’s only one Jamestown,” he said. “With vast resources at its disposal, Dominion should do the right thing by deconstructing these towers and working to provide reliable power in a way that does not come at the expense of America’s birthplace.”
Analysts with ClearView Energy Partners believe the lower court — or the results of the EIS — could indeed force Dominion to dismantle the project and reroute it, spawning a cascade of possible service disruptions and reliability concerns. On a broader scale, analysts warn the project’s outcome sets a precedent for what happens when federal agencies do not follow statutes and regulations, ultimately increasing the risks for transmission project developers.
NYISO said Wednesday it expects to have adequate resources on hand to meet slightly above-normal demand this summer, with 42,056 MW of capacity available to meet a forecasted peak of 32,382 MW.
The figures show the ISO will far exceed its capacity requirement of 35,002 MW, which includes an operating reserve requirement of 2,620 MW.
“The state’s grid is well-equipped to handle forecasted summer demand,” said Wes Yeomans, NYISO vice president of operations, said in a statement. “We have performed on-site visits of key generating stations to discuss maintenance, testing and adequacy of fuel supplies for hot-weather operations.”
The ISO’s projected summer peak is 1.5% above the 10-year average and outpaces last summer’s actual peak of 31,861 MW recorded on Aug. 29 (and the 2017 peak of 29,677 MW) but is down from the 2018 peak forecast 32,904 MW. Demand topped 31,000 MW on six days last summer.
New York statewide generating capacity by fuel type | NYISO
The peak is calculated to reflect normal summer conditions, but under more extreme weather scenarios peak demand could increase to about 34,186 MW, NYISO estimates. The ISO’s record peak of 33,956 MW occurred in July 2013 at the end of a heat wave.
The total capacity of power resources available to New York this summer include 39,295 MW of generating capacity from in-state power plants, 1,309 MW of demand response resources and 1,452 MW of imports from neighboring regions. The forecast factors in the expected impact of distributed resources and energy efficiency programs.
NYISO staff and the New York Department of Public Service last month informed the state’s Public Service Commission on summer electricity preparedness. (See “Grid Prepared for Summer,” NYPSC Modifies Standby Rates for DERs.) The department forecasts summer energy prices will be down 1 to 3% compared with last year, depending on load zone and weather conditions.
