ERCOT is seeking more time to hash out the details around a Nodal Protocol revision request that would establish notification responsibilities for the grid operator and its market participants during cybersecurity incidents.
During a workshop Tuesday, ERCOT staff said they will ask stakeholders to table NPRR928 in order to allow more time for comments on the proposal, which outlines a process for market participants to notify the grid operator about cybersecurity incidents. ERCOT is seeking to increase its awareness about the vulnerabilities of third-party systems that interact with its own systems, with an eye toward preventing interruptions to the grid.
A second workshop on the rule change will be scheduled in August or September, staff said.
ERCOT defines a cybersecurity incident as a malicious or suspicious act that “compromises or disrupts” a computer network or system belonging to ERCOT, a market participant or its agent that transacts with the grid operator that “could foreseeably jeopardize the reliability or integrity of the ERCOT system or … market operations.”
“Does an incident compromise or disrupt? Does it jeopardize the reliability or integrity of ERCOT systems or market operations?” Senior Corporate Counsel Brandon Gleason said. “We’re interested in things that are going to have an impact on something. ERCOT’s perspective is we want to know actual events that are occurring and have the potential to impact others.”
“We’re interested in anyone who has access into our system,” General Counsel Chad Seeley said. “We’ve tried to capture every access point into the system.”
Staff said that while ERCOT shares information with various government oversight groups “depending on the nature of the event,” it has no legal requirement to report cyber incidents as they are occurring.
Under NPRR928, the grid operator would send market notices, if necessary, to alert the market to an incident and actions being taken, while also disclosing the identity of any law enforcement agency notified about the event.
The protocol change will help cover those market participants that are not NERC registered entities. ERCOT has 939 market participants, less than 25% of which (191) are registered with NERC and subject to its reliability standards, including CIP-008.
ERCOT system access under NPRR928 | ERCOT
Non-registered entities “don’t have reliability nexuses, but they do have market nexuses,” Gleason said.
FERC on June 20 approved a new NERC cybersecurity rule that expands reporting requirements beyond just those incidents that actually compromise or disrupt reliability tasks on the bulk electric system.
CIP-008-6 now requires NERC entities to report any incidents that compromise, or attempt to compromise, electronic security perimeters, electronic access control or monitoring systems, or physical security perimeters associated with high- and medium-impact BES cyber systems and attempts to disrupt operation of a BES cyber system. (See FERC OKs Cyber Reporting Rule.)
In Texas, the state’s Public Utility Commission, Department of Public Safety, Department of Information Resources and Cybersecurity Council all have cybersecurity oversight over ERCOT. At the federal level, oversight agencies include the departments of Homeland Security, Justice and Energy, the FBI, and FERC, in addition to NERC and others.
The Texas Legislature recently passed three cybersecurity-related bills, none of which affected NPRR928:
Senate Bill 64, effective Sept. 1, directs the PUC to establish a program to monitor utilities’ cybersecurity efforts that provide guidance on best practices and facilitate the sharing of information between utilities. It also requires ERCOT to conduct an internal cybersecurity risk assessment and submit an annual compliance report to the PUC.
SB 475, effective immediately, establishes the Texas Electric Grid Security Council to facilitate the creation, aggregation, coordination and dissemination of best security practices. It is composed of the PUC chair, ERCOT CEO and Texas governor (or designated representative).
SB 936, effective Sept. 1, requires the PUC to engage a cybersecurity monitor to manage outreach, research, develop and facilitate best practices and training, review voluntary self-assessments, and report back to the commission on preparedness.
WASHINGTON — Senior executives of some the nation’s largest public power utilities came to D.C. this week to lobby Congress on tax policy and talk to the executive branch about federal reviews of infrastructure projects. They also squeezed in meetings with FERC.
One issue that was not top of mind was the Trump Administration’s announcement last week it was replacing the Clean Power Plan with less stringent emission rules for coal-fired generation.
So does the Affordable Clean Energy rule matter in the utilities’ long-term plans?
“No,” said Thomas Falcone, CEO of the Long Island Power Authority, during a press briefing with other executives in the delegation from the 27-member Large Public Power Council. “New York [last week] passed its own climate bill in the absence of federal energy policy. That climate bill seeks to have a carbon-neutral economy by 2050 and carbon-free grid by 2040. In New York, we have one coal plant … it’s supposed to shut down by 2020.”
Executives from public power companies in Texas, Washington, Nebraska and North Carolina agreed: Current federal policy is far less important to their decision-making than their states’ rules.
“I don’t spend a lot of time worrying about the ACE rule,” said Pat Pope, CEO of the Nebraska Public Power District.
No Lifeline for Coal
The ACE rule defines the best system of emissions reductions (BSER) as heat-rate efficiency improvements that can be achieved at individual coal plants, not the “beyond the fence line” generation-shifting, fuel-switching and state emission caps required under the CPP. (See EPA FinalizesCPP Replacement.)
Although some praised the policy as a rejection of the Obama administration’s “war on coal,” the ACE rule won’t be a lifeline for coal plants in North Carolina or Nebraska, officials said.
“We’re certainly moving ahead with ways to mitigate our carbon footprint,” said Pope, who noted NPPD is converting one of its smaller coal plants to burn hydrogen.
It’s also planning to offset greenhouse gas emissions by capturing methane from the state’s agriculture industry. “We’re actively exploring ways we can stop those emissions from occurring and credit that toward our coal emissions, and [we’re] still looking at carbon capture and sequestration,” Pope said. “We’re situated in an area where there’s probably more opportunities for sequestration than in other areas of the country. We’re going to take a hard look at that.”
Roy Jones, CEO of ElectriCities of North Carolina, said his company is also phasing out coal. “When I look at the ACE plan, the heat rate improvements in the plan — if they were economical, they’d have already been done,” Jones said.
Pope agreed. “The way we operate, we’re always going after these efficiency improvements. We’re all about lowering the cost to our consumers, running very efficient plants and operations. So the low-hanging fruit of those types of projects is long gone. … I think the incremental opportunities for others [are] going to be pretty small.”
Public power owns no coal in Washington state, said Steve Wright, general manager of the Chelan County PUD. Last month, Gov. Jay Inslee, who has made climate change the centerpiece of his longshot presidential campaign, signed the Clean Electricity Transformation Act, which bans utilities’ use of coal by 2025 and sets a 2045 target for emission-free power.
“The decision [away from fossil fuels] has already been made,” Wright said. “Now we’re trying to figure out how we’re going to make it work.”
Reinvesting in Hydropower
In Washington, that means a continued dependence on hydropower, which supplies 70% of the state’s electricity.
“It’s an aging hydropower system,” Wright said. “The challenge is how are we going to maintain that capability because as you add variable energy — non dispatchable resources — you need something to maintain reliability.
“It’s going to take a very large reinvestment in the system in order for it to be maintained because most of it was built as late as the 1970s, so the youngest plants are 40 years old. There’s a lot of work to do there, but with the right investments, we can make it work.”
‘Holistic’ View
With no stockholders, “having [our] finger on the pulse of community is very important,” said North Carolina’s Jones. “And as we talk to our community about climate change, without exception every one of them has individuals in the community that want to do more with renewables. Rooftop solar, community solar. Things they can do to make their homes more energy efficient and reduce their carbon footprint.”
Jones said North Carolina is almost a quarter of the way towards its goal of a 40% reduction in carbon emissions from 2005 levels by 2040.
To close the gap, Jones said the company is discussing ways to electrify the transportation system. “When we step back and look at the carbon footprint, we’re not just looking at the electric industry. We’re looking holistically in our communities. What are things we can do to reduce that carbon footprint.”
Austin Energy, which has been transitioning to renewable energy and emphasizing energy efficiency and demand-side management, will shut its last two large gas-fired steam units by 2021 and plans to exit from its coal position by 2022, said General Manager Jackie Sargent.
Because of ERCOT’s “robust” market and great transmission access, Sargent said the utility has been able to add wind and solar resources with locational diversity. “So, I don’t see the ACE rule impacting us in a significant way,” she said.
MISO’s exhaustive proposal for overhauling the cost allocations for market efficiency projects (MEPs) came a hair’s breadth from getting FERC approval on Monday — but for one key detail.
FERC rejected the plan — years in the making — after finding MISO’s cost allocation treatment for a new category of local economic transmission projects was at odds with the principle of cost causation (ER19-1124).
MISO filed the cost allocation scheme in February, part of a broader proposal to lower the voltage threshold for MEPs from 345 kV to 230 kV and eliminate a 20% footprint-wide postage-stamp cost allocation method for projects.
The plan also set out to create two new project benefit metrics in addition to the RTO’s existing adjusted production costs metric. One metric would have recognized the value of deferred or avoided reliability transmission projects, while the other would have considered the value of reducing power flows on the contract path on shared transmission from MISO Midwest to South. (See MISO MEP Cost Allocation Plan Goes to FERC.)
The proposal also would have provided limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability.
‘Inconsistent’
MISO’s proposal also sought to create a new project type — the local economic project — meant for smaller, economically-driven transmission projects between 100 kV and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line. The smaller project type would have replaced the current “economic other” project category, the costs for which were also allocated to the specific pricing zone in which they are located.
But unlike an “economic other” project, a new “local” project would not only have to meet a local benefit-to-cost ratio of 1.25-to-1 or greater within its pricing zone, it would also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs.
And therein lay the rub for FERC, which rejected the notion MISO could require a local project to demonstrate a solid regional benefit while still allocating 100% of its costs to the local pricing zone rather than across all zones standing to benefit.
“In this case, [MISO and its transmission owners] do not contend that they are unable to calculate the distribution of benefits for Local Economic Projects with the same granularity as Market Efficiency Projects,” the commission wrote. “Instead, Filing Parties’ proposal suggests the opposite conclusion — that, if MISO implements the proposed benefits metrics, it will be able to more precisely calculate the distribution of benefits … Thus, every time MISO approves a Local Economic Project in its [transmission expansion plan], it will first identify all benefitting zones in the same manner it does for Market Efficiency Projects.”
The commission went on to say MISO had proposed metrics to identify the regional benefits of local projects but “ignored the results of its regional benefit metrics analysis in order to allocate the costs only to the transmission pricing zone(s) where the project is located. This combination of elements within the proposal therefore is inconsistent with the cost-causation principle.”
Multiple protestors, including MISO Industrial Customers, WEC Utilities and the Michigan Public Service Commission, filed with FERC to criticize the misalignment of benefits and costs. Other protestors dubbed the regional and local 1.25-to-1 benefit-to-cost ratio requirement a “double hurdle.”
Competitive transmission developer LS Power went a step further and said the project type has “no ascertainable regional purpose, directly harms ratepayers and benefits only incumbent transmission owners.” LS Power also filed a separate MEP complaint in early June, asking FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)
But the ruling was not all bad news for MISO. FERC acknowledged the work the RTO and its stakeholders put into developing the cost allocation proposal, which “includes compromises resulting from a three-year discussion among diverse stakeholders with myriad competing interests.” The commission said most of the plan appeared to be reasonable and it urged MISO “to consider whether the proposal could be modified to address the cost causation issue … while retaining the benefits of other aspects of the proposal.”
MISO was counting on the new cost allocation for projects in the 2019 MISO Transmission Expansion Plan.
Interregional Filings Also Rejected
FERC on Monday also rejected two interregional cost allocation filings MISO made for PJM and SPP because they contained a cost allocation method like the one MISO proposed for local economic projects. (ER19-1156-000 and ER16-1959-005). MISO had proposed that its share of interregional economic projects with voltages below 230 kV but at or above 100 kV be allocated 100% to the transmission pricing zones where the project is located.
With the rejections, a piece of MISO’s allocation compliance over the longstanding complaint by Northern Indiana Public Service Co. remains unresolved. (See FERC Signals Bulk of NIPSCO Order Work Complete.) FERC said MISO now has 90 days to let the commission know if it plans to use the existing MEP cost allocation method for MISO-PJM interregional economic transmission projects above 100 kV but below 345 kV or propose revisions for a separate cost allocation process. FERC’s 2013 NIPSCO order lowered the minimum voltage threshold for MISO-PJM interregional market efficiency projects from 345 kV to 100 kV.
Ohio lawmakers are being asked to trade ratepayer-funded renewable energy mandates for the jobs and carbon-free energy that would come from the continued operation of FirstEnergy Solutions’ Davis-Besse and Perry nuclear plants.
House Bill 6, titled the Clean Air Act, has confounded fossil fuel proponents and environmental groups alike, while state Republicans and labor unions insist the cost of losing the facilities overrides the need to invest in renewable resources and energy efficiency programs.
Under current law, the state’s electric distribution utilities (EDUs) must obtain 12.5% of their power from renewable sources by 2027, including 0.5% from solar. HB 6 would repeal those requirements and provide subsidies to “clean air resources” including nuclear power and some solar resources that had obtained siting certificates before June 1.
The Davis-Besse nuclear plant in northern Ohio | NRC
“Ohioans deserve so much better,” said Miranda Leppla, vice president of energy policy at the Ohio Environmental Council Action Fund. “HB 6 is nothing more than a ploy to bail out corporate utilities that want to continue to run old, dirty energy sources, under the guise of ‘clean air.’”
FirstEnergy argues its plants deserve the help. Davis-Besse and Perry produce 2,100 MW of electricity around the clock — 90% of Ohio’s carbon-free power — but the company says it can’t afford to keep the plants running based on its revenues from PJM’s wholesale market, which has seen prices fall because of renewables and cheap natural gas.
The bill, approved 53-43 by the House of Representatives on May 29, also has the support of Gov. Mike DeWine. “As I have previously stated, Ohio needs to maintain carbon-free nuclear energy generation as part of our energy portfolio,” DeWine said. “In addition, these energy jobs are vital to Ohio’s economy.”
The bill is now being considered by the state Senate.
Critics say FES doesn’t need help to keep the plants afloat and are playing a “shell game” in PJM’s capacity market auctions to convince lawmakers otherwise.
“The bottom line is that Ohio nuclear resources are in no danger of retiring anytime soon and to do so would not only be economically irrational but would financially harm the equity shareholders of these nuclear assets,” Paul Sotkiewicz, president of E-Cubed Policy Associates and PJM’s former lead economist, told the Ohio Senate Energy and Public Utilities Commission on June 4. He came to share the results of an American Petroleum Institute-funded study that accused the company of misleading lawmakers and the public about their intentions to deactivate the plants over the next two years.
“I must say, I was surprised with this result,” Sotkiewicz said. “Of all the nuclear assets in PJM, I viewed single-unit facilities such as Three Mile Island, Davis-Besse and Perry to be very much at risk for retirement given the Nuclear Energy Institute’s reported costs for single-unit sites.”
FES’ supporters say Sotkiewicz’s math is wrong.
“The natural gas industry is doing what all rivalrous generation resources do in these instances,” said Ray Gifford, former chairman of the Colorado Public Utilities Commission, who was brought to Columbus by FES to convince the Senate Energy and Public Utilities Committee to approve the bill. “It is protecting its turf and trying to handicap its rivals.”
FirstEnergy spokesperson Tom Becker said that Sotkiewicz’s profitability calculations are “deeply flawed” and correcting his “obvious” errors would show a loss in excess of $125 million for both plants over the next decade.
“After weeks of testimony in committee inaccurately criticizing the health, longevity and maintenance of our two nuclear plants in Ohio as unworthy of future investment, suddenly this last-minute report — funded by out-of-state oil and gas interests — proclaims that Davis-Besse and Perry are in excellent position to continue providing clean energy in Ohio,” he said. “Clearly the opponents of HB 6 cannot make the argument on both sides.”
Emissions and Reliability
FES says its nuclear plants’ contribution to the grid’s reliability and the state’s carbon-free electricity can’t be ignored.
“I see no good alternative, and these plants are too vital to Ohio to sacrifice because of the failures of a distorted regional wholesale market,” Gifford said.
He said it’s unrealistic to expect renewables and battery storage will replace the lost capacity if the plants close. Just ask Germany and Japan, where carbon emissions and energy prices increased after they severely curtailed their nuclear output, he said.
“You end up with a collective action problem where states that do not subsidize their failing units end up being chumps who forego the power, the resilience characteristics, the jobs and tax revenue,” he said, urging Ohio not to give up its plants and let natural gas fill the void. “I don’t know a good way to cut this Gordian Knot, but I do know that losing these plants would be bad for Ohio and bad for consumers.”
A PJM analysis released earlier this month concluded emissions will drop regardless of whether Perry, Davis-Besse and FirstEnergy’s Beaver Valley plant in Pennsylvania close or stay open — though the reduction would be significantly greater if the plants stay online. (See PJM: Nukes Keep Energy Costs Down, in Theory.)
The problem, according to PJM Independent Market Monitor Joe Bowring, is that the number of gas plants slated to come online in 2023 will likely decrease by more than half of what is currently in the RTO’s pipeline of approved projects, and less enthusiasm for nuclear subsidies in Pennsylvania means a scenario that saves all three plants is far from realistic. A combination of nuclear plant retirements and canceled gas projects would increase energy costs and push emissions in both states higher because of the reliance on less efficient coal-fired generation, PJM’s analysis concluded.
‘Rise Like Lazarus’
Sotkiewicz insists the new law would just increase the profitability of the plants by as much as 240%, with no true reduction in carbon emissions on account of the bill’s last-minute carveout for two of Ohio Valley Electric Corp.’s coal plants.
Citing data compiled from publicly available sources, Sotkiewicz said the single reactors at Perry and Davis-Besse incur costs nearly 25% below the industry average. He estimated annual net operating profits over the next decade for Perry will reach $28 million, while Davis-Besse will collect almost $44 million.
As a result of FES’ bankruptcy proceedings, Sotkiewicz says the reorganized company will soon rid itself of crippling debt service and be poised “to emerge as a fully independent power producer.”
He also pointed out that the entirety of FirstEnergy’s generation portfolio, except for its 545-MW West Lorain fuel-oil and natural gas-fired plant, has submitted retirement notices. “That seems highly implausible … why would [bond holders] agree to become equity holders in a single peaking plant? Other resources slated for retirement are likely to ‘rise like Lazarus,’ but only those with the most to offer competitively. Perry and Davis-Besse are good candidates given their profitability.”
He further suggests that PJM auction data indicate that FirstEnergy plays “a shell game” by “hiding cleared capacity in units slated for retirement (or already retired) to eventually be transferred over to nuclear plants when they remain in service” — another sign that the Ohio nukes “are not going away anytime soon.”
Gifford says Sotkiewicz gets its all wrong.
“The API study does what all wish-fulfillment utility planning models do,” Gifford said. “It cherry-picks its numbers to overstate revenues and understate costs. By doing so, plants operating at a loss suddenly turn profitable.”
Specifically, Gifford accused the API study of using inaccurate price nodes and assuming plants receive capacity payments when they have not cleared auctions in several years. He also said the study underestimates operating costs for nuclear plants, including overlooking refueling years, equipment maintenance and the differences between cost structures at single- and multiunit facilities.
He also cited another API study that determined TMI would lose $466 million over the next decade.
“Three Mile Island and Davis-Besse are virtually twin facilities, and both are operated at the highest level of performance within the same PJM market construct,” he told the committee. “Yet, a study completed 60 days prior to the one submitted to you today reflects nearly a $750 million difference in profitability between the two units over the next 10 years. How can that be?”
Over-compliance on EE
HB 6 also would make major changes to Ohio’s energy efficiency incentives.
Under current law, EDUs assess a monthly $4.10 fee on customers. The Ohio Environmental Council Action Fund says about 74 cents support distributors meeting renewable resource standards and the remaining $3.36 is used for energy efficiency and peak demand reduction.
Over the last five years, Ohio’s EDUs have collected more than $1.3 billion from residential customers to meet the mandates, Public Utilities Commission of Ohio Chairman Sam Randazzo said. Utilities boost their take by reducing energy efficiency and peak demand response over and above the state requirement for the year.
“The EDUs have been over-complying with the statutory demand-side compliance requirements,” Randazzo told the committee on June 4. “Based on past experience and the incentives that each EDU presently is receiving, it is reasonable to expect that this over-compliance trend will continue into the future.”
PUCO spokesperson Matt Schilling said the primary driver for this behavior boils down to the millions in shared profits that utilities split for each megawatt-hour saved. Between 2014 and 2017, companies shared $233 million in savings, he said.
In fact, all the state’s EDUs will hit the statutory compliance peak of a 22.2% reduction in demand a full four years before the 2027 deadline, according to PUCO’s analysis.
“The escalating annual supply-side and demand-side compliance requirements were not based on any studies or analysis,” Randazzo said. “They were and are arbitrary. But more importantly, the compliance obligations were proposed and considered based on some assumptions about the future — assumptions that sharply conflict with our current reality.”
Randazzo said the compliance obligations incentivize entry of renewable generation sources while simultaneously encouraging EDUs to reduce the size of the overall electricity market — disproportionately impacting “non-preferred” technologies on both the supply and demand side. Because it’s unlikely they’ll stop collecting these fees, Randazzo said, it’s no wonder these older technologies, nuclear generation included, want financial assistance “to stay in the game.”
Rob Kelter, senior attorney with the Environmental Law & Policy Center, said existing efficiency mandates help keep costs lower for consumers.
“Because the efficiency programs reduce energy consumption across the state, energy prices are lower for all Ohioans,” he said, noting a Resource Insight report that determined ratepayers save an additional $2/month because of the fees. “Our Energy Efficiency Resource Standards are vitally important, not only for the environmental benefits that result from reducing our energy consumption, but because they keep energy prices low for all Ohioans.”
Sweetener for EDUs?
EDU Duke Energy Ohio testified in April that any elimination of the energy efficiency standard should be gradual, with “a reasonable period of time to allow affected stakeholders to adjust to the change.”
Two other companies, AES’ Dayton Power & Light and American Electric Power, indicated their support for HB 6 last month.
Duke, AEP, FirstEnergy and AES are the parent companies for all six of Ohio’s EDUs.
The companies also own almost two-thirds of OVEC, which would benefit from a provision in the bill that codifies a state Supreme Court ruling allowing it to charge customers up to $2.50/month to subsidize its Kyger Creek and Clifty Creek coal-fired plants.
Coal conveyer belt for OVEC’s Clifty Creek generating plant | OVEC
On top of the nuclear subsidy fee, which sunsets in 2026, electricity companies can also recoup costs lost on long-term contracts to meet Ohio’s renewable portfolio standard mandates until 2030. AEP, the Columbus-based utility that owns more than 40% of the state’s coal and natural gas plants, urged lawmakers to allow rate recovery for these existing contracts when moving the bill forward.
Tom Froehle, AEP’s vice president of external affairs, testified on June 12 that the bill allows the company to further invest in renewable resources, while simultaneously addressing Ohio’s increasing reliance on out-of-state generation and its legacy resource issues dating back more than a decade.
“HB 6 provides ongoing certainty for an important and longstanding baseload generating asset,” he said. “The bill also includes rate caps for customers while allowing for the continued operation of OVEC generating units, which will provide certainty for AEP Ohio’s customers and Ohio jobs.”
Critics said this OVEC carveout serves one purpose alone: bolstering support among EDUs.
“The only reason these plants are in HB 6 was to enlist support for HB 6 from the other Ohio utilities, because the bailout for the nuclear plants would only benefit FirstEnergy,” said John Finnigan, lead counsel for the Environmental Defense Fund.
Ratepayer Impact
HB 6 would eliminate the $4.10 fee and charge residential customers $1/month, starting in 2021, to support the nuclear plants through 2026. Commercial customers will pay $15/month, industrial customers will pay $250 and large-scale users consuming more than 45 million kWh at one site annually will pay $2,500 monthly. The anticipated $198 million in revenue will be collected by the state treasury and distributed back to the defined “clean air resources” at a rate of $9/MWh. The subsidy would be reduced if the “market price index” — based on energy futures contracts for the PJM AEP-Dayton hub and projected capacity prices using PJM’s Rest of RTO market clearing price — exceeds $46/MWh. Wind and new solar generators are ineligible for the credit.
Ohio Sen. Steve Wilson (R), chairman of the Energy and Public Utilities Committee, told RTO Insider the issue is certainly “complicated” for lawmakers.
“I’ve been working hard to be the guy in the striped shirt blowing the whistle and giving everyone a chance to explain their position,” he said. “But we are working hard to get FirstEnergy an answer by their June 30 deadline.”
The committee completed its fourth hearing on the bill June 19 and has scheduled a fifth for Tuesday.
FERC last week reversed its position in a more than decadelong dispute over line-loss refunds, ordering PJM to surcharge load to recover overpayments resulting from earlier commission rulings.
Acting on a voluntary remand of a case before the D.C. Circuit Court of Appeals, the commission’s ruling Thursday reversed orders it issued in 2011, 2012, 2015 and 2016. It ordered PJM to pay refunds of misallocated line-loss overcollections to some financial marketers and to surcharge load to recover refunds from parties that previously had received overpayments (EL08-14-012).
Last week’s ruling, which could require PJM to collect millions from load, was actually the third reversal by FERC in the complicated dispute.
The case originated from a complaint by financial marketers — including Black Oak Energy, EPIC Merchant Energy and SESCO Enterprises — who argued they weren’t getting their fair share of line-loss refunds for up-to-congestion (UTC) transactions. PJM includes line losses in its LMP calculations to ensure correct pricing signals and efficient dispatch, a procedure that results in the RTO collecting more in line losses than it pays to generators.
After initially ruling that the marketers were not entitled to line-loss refunds, the commission reversed itself, leading PJM to pay the marketers $37 million in 2010. FERC reversed itself again in orders in 2011 and 2012, leading PJM to issue invoices in 2012 requiring the marketers to repay the refunds. As of 2014, PJM told FERC, only $9 million of the $37 million had been returned.
The commission’s latest reversal came in response to a challenge by financial marketer Energy Endeavors to commission rulings in 2015 and 2016. During briefings before the D.C. Circuit, the commission submitted an unopposed motion for voluntary remand, citing court rulings finding that the Federal Power Act gives the commission “broad remedial authority, including the ability to act retroactively to correct unjust situations and to ensure that what ‘should have been done’ is done,” FERC explained.
“The commission in the past has referenced a general policy of not ordering refunds in cost allocation and rate design cases. However … we find that the commission has greater discretion with respect to this refund-related issue under sections 309 and 206b of the FPA than was indicated by those statements.
“In light of these precedents, the commission will consider whether to require refunds in cost allocation and rate design cases based on the specific facts and equities of each case, even where such refunds must be funded through surcharges on certain parties.”
In addition to directing PJM to pay line-loss overcollections to financial marketers for UTC transactions, FERC also ruled that the RTO should treat customers that export energy from it to MISO “on an equal basis to PJM load.”
It said PJM has authority to impose surcharges if needed to implement the refunds but should not surcharge the MISO exporters because the exporters had made business decisions based on “a reasonable expectation of receiving at least some credit for line losses.”
“Certain exporters pointed out that they would not have engaged in significant numbers of export transactions had they had notice that they would no longer be eligible for a pro rata share of marginal line-loss allocations,” the commission noted. “DC Energy, for example, calculated that it would not have engaged in 350,000 MWh of transactions.”
The commission directed PJM to calculate the refunds, with interest, owed to the financial marketers; the amounts of refunds previously paid, and not returned, that may be retained by the financial marketers; and the surcharges owed by PJM load and the exporters based on their proportionate share of the marginal line-loss allocations taking into account the payment of refunds.
“This resolution provides the most equitable result, as it permits those engaging in up-to-congestion transactions to participate equally in the distribution of line-loss credits while not unduly upsetting settled expectations,” the commission said.
Pierce Atwood attorney Randall S. Rich, who represents several of the financial marketers, declined to comment on the ruling and said he did not know how much money is at stake.
PJM spokesman Jeff Shields said the RTO will implement the order but does “not have an estimate of a dollar figure at this point.”
“There will be challenges associated with how many years have elapsed, during which time participants now deemed by FERC to owe money have left the market,” Shields said. “PJM is disappointed by the order for a number of reasons, not the least of which is the financial burden it will place on consumers who actually use the grid to buy and sell energy.”
The Pacific Northwest’s March 1 price spike “should serve as a wake-up call” of the region’s coming capacity shortage, power industry consultant and former Bonneville Power Administration chief Randy Hardy warned in April.
Hardy reported that bilateral March 1 day-ahead peak prices at the Mid-Columbia trading hub broke $900/MWh, driven by natural gas prices of $160/MMBtu. By comparison, CAISO day-ahead prices that day ranged from about $38 to $82/MWh, holding that high for only one evening interval. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)
On Wednesday, the Western Electricity Coordinating Council Board of Directors received a briefing from Operating Committee Chair Richard Hydzik on preliminary findings of the OC and the Market Interface Committee regarding the event. “The question was, was there a capacity issue related to this?” asked Hydzik, principal transmission operations engineer with Avista.
The answer is still up in the air. Hydzik noted the region had adequate reserves during the event, and his presentation focused on the temporary supply constraints.
The event occurred during the first week of March, with unusually low temperatures that were closer to those in a typical January. The cold snap led to high demand for natural gas and electricity. At the same time, utilities were doing maintenance or had taken assets out of service during a time that normally sees lower demand.
Hardy’s report noted that the high prices “and the capacity shortage that they reflected, occurred despite all the soon-to-be retired PNW coal plants operating at maximum capacity.”
Hardy cited research by analysts E3 that predicts load growth and announced coal plant retirements could leave the PNW with an 8-GW capacity deficit by 2030 without new dispatchable capacity. That would increase the region’s loss-of-load probability (LOLP) to 48%, he said, noting that WECC utilities’ normal reliability standard is a 5% LOLP.
Hardy said the situation is complicated by moves by Oregon and Washington lawmakers to prevent the building of new gas-fired generation. Hardy said the region could be limited to wind and solar for new energy resources and batteries and pumped storage for new capacity.
Shoulder Month Surprise
Hydzik told the WECC board the March 1 price spike was attributable in part to a lack of south-to-north transfers on the DC Pacific Intertie, which was down for maintenance. A major gas pipeline moving fuel from British Columbia into Washington was running at 80% capacity because of an explosion last fall, and one 730-MW unit at the coal-fired Centralia (Wa.) plant had been taken offline. Balancing authorities were serving native demand and limiting exports.
“So, this is March. Typically, it’s a shoulder month,” Hydzik said. “Six months earlier you plan all of your maintenance to be out of this stuff [before summer demand hits]. Once you take some of these facilities down, you cannot quickly restore them, and you’re simply out of service.”
But the BAs and the Northwest Power Pool Reserve Sharing Group had ample reserves. No emergency alerts were called, and transfers were flowing into the region. BC Hydro “saw this coming,” Hydzik said, and sent an additional 2,000 MW into the U.S. from Canada, reversing the predominant flows on the BC Intertie as the utility’s Powerex marketing arm reduced purchases and boosted exports to take advantage of the surging market.
“Good for them,” he said. “Maybe not so good if you’re south of the border. …
“So, what did we find so far?” he said. “Everyone in the Northwest had more than adequate reserves. … Just because something was expensive doesn’t mean it wasn’t available.”
Gas supplies were constrained, and coal plants and other resources have been retired. Additional findings will be presented at a future meeting, he said.
Director Jim Avery said the situation had raised concern at WECC and may be a sign of things to come.
“Here we are in the shoulder months experiencing some of the bigger problems,” Avery said. “These are going to become the new norms.
“We’re going to have different resources that perform differently in different seasons,” he said. “And yet we’ve been operating the system the same, and that is, ‘Well, shoulder months, that’s when we do our maintenance.’ We’re going to have to rethink that because during peak load conditions in the middle of the day, we may have an abundance of resources [such as solar] that we’ve never had before. And that’s just the new norm.”
Hydzik said he agreed with Avery’s comments.
Hardy offered several potential actions to respond to the capacity shortage, including adding transmission to access Montana or Wyoming wind power; an overhaul of “fossil fuel era” planning and operating metrics; and incentives for ramping resources.
A lack of action would leave the region praying “for rain and mild weather,” Hardy said.
“Murphy’s law predicts that the next low water year in the PNW will arrive in 2025 as peak coal plant retirement occurs and the PNW [integrated resource plans] defer decisions on construction of new resources waiting for the next cost reduction in carbon-free capacity.”
HOUSTON — Beth Garza’s annual visit to the Gulf Coast Power Association’s Houston chapter Thursday once again drew a roomful of electric industry insiders and observers hoping to glean insights into the state of the ERCOT market.
But first, Garza, director of ERCOT’s Independent Market Monitor, had to remind her luncheon audience what her role is. Asked about her expectations of the market’s performance during the summer, Garza responded, “The cool thing about my job is that it’s the Market Monitor, not the market predictor.”
Garza did allow that forward prices do show a “moderation of expectations” for the summer. She shared a slide that showed ERCOT’s North Hub futures for August at around $120/MWh and the July futures at around $70/MWh.
A year ago, August futures briefly eclipsed $250/MWh in May, when the reserve margin was 11%. It is now down to 8.6%.
“It’s been a wet spring, and wet springs tend to portend not-that-hot summers. I think we will see similar outcomes in the summer of 2019,” she said, echoing ERCOT’s weather forecast. (See “Staff Prep Directors for Summer Expectations” and “IMM Market Report: Load Continues to Climb,” ERCOT Board of Directors Briefs: June 11, 2019.)
ERCOT says it expects to use emergency measures this summer to meet a record forecasted peak demand of 74.9 GW, more than last summer’s all-time system peak of 73.5 GW. The grid operator has an available capacity of 78.9 GW.
The Monitor’s State of the Market report notes ERCOT’s load grew at a 5.3% clip last year. ERCOT expects the growth to continue at a 2.5 to 3% rate through 2022, when peak demand is projected to hit 84.1 GW.
“This continued growth puts us on a path of being short,” Garza said. “If you look at installed capacity … the resources we have today will be insufficient to serve projected load in 2021.”
One luncheon guest asked Garza whether batteries and other forms of energy storage could play a major role in the market.
“The difficulties and challenges around batteries are numerous and hard,” she said. “ERCOT is not alone in the RTO world in wrestling with those questions and trying to figure out what the right answers are. I don’t have easy answers, because there are no easy answers.”
74-MW Wind Farm to Retire in November
ERCOT on Thursday approved West Texas Wind Energy Partners’ request to shut down a 74-MW wind farm in Southwest Texas. The grid operator said its reliability analysis indicated the facility was no longer needed to support system reliability.
The Southwest Mesa Wind Energy Center | NextEra Energy Resources
Southwest Mesa began commercial operation in 1999. With nearly 22.1 GW of installed wind in ERCOT’s footprint as of April, the facility’s retirement will represent a 0.33% cut in wind capacity.
SPP may ask FERC to lower its exit fee in response to the commission’s April order that the RTO eliminate the fee for members who are not transmission owners or load-serving entities.
Staff told the Corporate Governance Committee on June 17 that they believe FERC’s order (EL19-11) suggested the commission may approve a lower amount. SPP faces an Aug. 1 deadline to make a compliance filing and has already submitted a rehearing request to clarify the definitions of TOs and non-TOs. (See FERC Tells SPP to End Exit Fee for Non-TOs.)
The committee agreed in executive session to recommend a fixed $100,000 exit fee to the Board of Directors when it meets on July 30. The current exit fee is estimated at $631,915, nearly twice the $327,191 fee that FERC approved in 2006, when it last required the RTO to impose an exit fee on all members.
Load-serving members would be subject to an additional share of SPP’s financial obligations and future interest based on their net energy for load percentage. LSEs would be defined as distribution or electric utilities that have a service obligation and/or secures energy and transmission service to serve its end-use customers’ demand and energy requirements.
Staff noted the commission’s order said “some level of exit fee that does not act as a barrier to membership and is not excessive could be appropriate in SPP.”
By making the fee a fixed amount, SPP said it would be addressing the commission’s concern that the exit fee can move up or down.
FERC’s order came in response to a complaint filed by the American Wind Energy Association and Advanced Power Alliance, formerly the Wind Coalition. The groups charged that SPP’s exit fee results in unjust and unreasonable rates and creates “a barrier to membership” for non-TOs and non-LSEs.
“What’s being proposed here does not seem to track with cost-causation principles. Such an exit fee that’s not based on any … principles would likely be opposed,” APA’s Steve Gaw said. “We would like to see something that is more in line with what other RTOs have found to be appropriate for membership and stakeholder participation.”
CGC member Denise Buffington, director of federal regulatory affairs with Evergy companies Kansas City Power & Light and Westar, cautioned against the move considering the pending rehearing request.
“If FERC gets this as an alternative … it’s an easy pass for them not to deal with this issue. My preference would be to wait until we get an order on the rehearing request,” she said. “If I were giving legal advice on behalf of the client, I would stick close to what FERC has ordered.”
SPP CEO Nick Brown said staff debated the timing of the alternative proposal but said the recommendation was “to help FERC get the right answer.”
“We’ve continued to debate this [issue] at the request of non-members or members who wished to withdraw but couldn’t afford the exit fee,” he said. “In putting this proposal on the table, we specifically wanted to influence FERC’s thinking and help them to make a decision. We consider this just and reasonable.”
Other committee members favored the lower exit fee. Dogwood Energy’s Rob Janssen said the reduced fee would solve the problem of “zombie members”: those who stayed members “because it was easier than paying the exit fee.”
“I think this change will make them come out of the woodwork and make a decision one way or the other,” Janssen said.
The CGC will also recommend approving the compliance filing, which would change SPP’s governing documents in response to FERC’s order. Staff said it will include what it believes are errors in FERC’s order, for which they are seeking rehearing.
If the board approves the committee’s recommendations in July, they will be promptly filed at FERC to meet the Aug. 1 deadline.
RENSSELAER, N.Y. — NYISO presented the Business Issues Committee the final market design for pricing carbon emissions into its wholesale electricity markets on Thursday, the same day the New York State Assembly passed a bill that will put many of Gov. Andrew Cuomo’s environmental targets into statute.
The Climate Leadership and Community Protection Act (A8429) will require 70% of the state’s electricity be generated by renewable resources by 2030, nearly quadruple its offshore wind energy goal to 9 GW by 2035 and require the economy to be carbon-neutral by 2040. The law also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)
| NYISO
Stakeholders were divided on whether the bill — expected to be signed into law by Cuomo — necessitates increased skepticism on carbon pricing or urgency on the effort.
“It will take time to digest the new information, but having carbon pricing helps reach these goals, said Rana Mukerji, NYISO senior vice president for market structures. “If [load-serving entities] are required to buy renewables, the procurement prices will reflect the benefit renewables derive from having carbon priced into the energy market.”
Representing the Independent Power Producers of New York, Matt Schwall said, “IPPNY continues to be very supportive. … Carbon pricing is now more important than ever. There’s been a lot of time spent developing the idea, and this will help us reach the targets.”
Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers, said he was “skeptical” of how consumers could benefit from carbon pricing under the new law.
Couch White attorney Kevin Lang, speaking for New York City, said he shared Breidenbaugh’s concerns: “Carbon pricing isn’t going to get us incrementally more generation … and I agree that NYISO needs to look at the new law before moving forward.”
Mark Younger of Hudson Energy Economics said, “You can put targets, but that doesn’t mean they’re effective. You can put 7,000 MW of wind in the North Country and meet a target of 7,000 MW of additions, but not get much benefit of zero-carbon megawatt-hours in the state.”
“Action needs to start happening immediately, and we need to be sending price signals that reflect the value, or the damage, of carbon emissions,” said Howard Fromer, director of market policy for PSEG Power New York. “How? The closest thing is the mechanism we’ve come up with here, and carbon pricing is even more important now than it was a year ago.”
Robert Pike, NYISO director for market design and product management, said, “We’re here today just to recognize the culmination of the work that’s taken place over a considerable amount of time.”
Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), said, “A long time ago, we said that a market without a carbon component is inconsistent with our environmental goals. Carbon pricing can help the state reach its goals.”
On Monday, third-party consultant Analysis Group presented to the Installed Capacity/Market Issues Working Group preliminary results of a supplemental analysis examining the impacts of pricing carbon. The study is intended to augment the Brattle Group report process that concluded in December. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Broader Regional Markets Update
Pike presented the monthly Broader Regional Markets report and highlighted item No. 26, noting that the Management Committee in May approved a new external supplemental resource evaluation (SRE) penalty regime.
Approved by the BIC in April, the SRE penalty provisions will boost the ISO’s ability to call on external resources that have sold capacity to New York. Pending FERC approval, the proposal is anticipated to become effective in August.
Pike also highlighted BIC and MC approval last month of revisions to the NYISO-PJM joint operating agreement to address coordination on flowgates similar to the East Towanda-Hillside Tie Line.
Manual Revisions
The BIC approved revisions to several manuals, with most of the changes required by implementation of the Zone J (New York City) reserve region.
Ashley Ferrer, NYISO energy market design specialist, reported that the changes would affect the Ancillary Services, Day-Ahead Scheduling and Transmission & Dispatch Operations manuals.
ISO staff engineer Harris Miller detailed additional revisions unrelated to the Zone J reserve requirements being proposed within the affected manuals.
Ferrer said the proposed New York City reserves would go into effect Wednesday, assuming approval by FERC.
LBMPs, Gas Prices Drop
NYISO locational-based marginal prices averaged $23.10/MWh in May, down about 17.5% from April and about 19.7% from the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $37.57/MWh, a 25% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in lower compared to April. Average daily sendout was 373 GWh/day in May, higher than 371 GWh/day in April and lower than 397 GWh/day in the same month a year ago.
Transco Z6 hub natural gas prices averaged $2.27/MMBtu for the month, off slightly from April and down 11% from a year ago.
Distillate prices were down 8.5% year over year and mixed from the previous month, with Jet Kerosene Gulf Coast averaging $14.64/MMBtu, up a penny from April, while Ultra Low Sulfur No. 2 Diesel NY Harbor dropped to $14.54/MMBtu from $14.72/MMBtu in April.
May uplift increased to 13 cents/MWh from -15 cents in April, while total uplift costs, including NYISO’s cost of operations, came in higher than the previous month.
The ISO’s 23 cents/MWh local reliability share in May was up from 20 cents the previous month, while the statewide share climbed to -11 cents/MWh from -35 cents in April.
The Thunderstorm Alert cost was 19 cents/MWh, up from the usual zero to 1 cent.
Phase 2 of NERC’s Standards Efficiency Review has narrowed its focus to four tasks, tabling two others for potential work by other committees, members of the Phase 2 team said last week.
In a June 17 conference call, the team said it would focus its work on the four initiatives that received the highest response from stakeholders in polling that concluded March 22. (See “Team Reviewing Feedback on SER Phase 2,” NERC Standards News Briefs: May 8-9, 2019.)
The team’s decision followed a June 11 meeting with the SER Advisory Group and FERC staff.
“There was a discussion with the Advisory Group on how [SER] Phase 2 is much different than Phase 1. We’re looking more holistically and long-term at ideas that can streamline things going forward, not necessarily individually at the requirement level,” said SER Phase 2 Chair John Allen, manager of reliability compliance for the City Utilities of Springfield (Mo.). “I thought there was good support from the Advisory Group and at least no indication from FERC staff that we were heading down a road that was not viable.”
The top two priorities — changes to the evidence-retention rules and consolidating information/data exchange requirements — are expected to be completed this year.
The team also will tackle a proposal to move “competency-based” requirements from standards to guidance documents and developing a risk-based standards template; those efforts are likely to extend into 2020, team members said.
“There’s a lot of work that was already done on … evidence retention, so there was a good baseline to start on that. On the data and information consolidation, it’s pretty cut and dried, straightforward,” Allen said.
“These other two are shifts. We’re putting these ideas out there to say, ‘Here’s how we do it today. How can we do it more efficiently going forward?’ To make that successful, we’ve got to get all the right stakeholders together.”
The SER team declined to work on relocating competency-based requirements to the certification program/controls review process, which will be transitioned to the Compliance Certification Committee or the Organization Registration and Certification Programs (ORCP).
It also is dropping an initiative on consolidating and simplifying training requirements. A subgroup of the Phase 2 team “is talking about potentially drafting a [standards authorization request] for the training concept,” said Chris Larson, NERC manager of standards information.
Reducing the Scope of Work
In working on the prototype standards, Allen said, the SER team should “find some way to try to reduce the need or the scope of the work for a future Standards Efficiency Review or Paragraph 81 or whatever you want to call it — a cleaning up of the standards.”
Paragraph 81 is a reference to FERC’s March 2012 order on NERC’s Find, Fix and Track process, in which the commission told NERC it would welcome proposals to revise or remove reliability standards or requirements that are redundant or add little protection to system reliability (RC11-6, et al.).
“If we can put ourselves on a better path going forward where we don’t have to do this every five years, we’ve done some good work,” Allen continued. “That’s really what we’re going to look to in the prototype standard — is how to put some tools out there going forward to help have a more efficient product where we don’t have to go and clean them up every few years.”
“I’ll second that concern,” said John Pespisa, an Advisory Group member from Southern California Edison. “[The] key to not doing this again in the near future is bringing that key concept into this process.”
Randy Crissman, senior reliability and resilience specialist for utility operations at the New York Power Authority, said there is a need for a “communications strategy.”
“How do we help facilitate the adoption and implementation of that type of an approach? It’s going to be a pretty big lift, but if we don’t try it, it will never happen.”
