WASHINGTON — U.S. Sen. Chris Van Hollen (D-Md.) said Wednesday that he and other Senate Democrats will seek to amend a bipartisan energy bill this week to undo FERC rulings on PJM’s minimum offer price rule (MOPR) and NYISO buyer-side market power mitigation (BSM).
Van Hollen told the American Council on Renewable Energy’s Policy Forum that the American Energy Innovation Act introduced by Sens. Lisa Murkowski (R-Alaska) and Joe Manchin (D-W.Va.), the top members of the Senate Energy and Natural Resources Committee, was an opportunity to reverse FERC’s Dec. 19 order expanding PJM’s MOPR. (See Murkowski, Manchin Offer Bipartisan Energy Bill.)
Speaking with reporters after his speech, Van Hollen said he, Senate Minority Leader Chuck Schumer (D-N.Y.) and Sen. Cory Booker (D-N.J.) will offer an amendment to reverse both the PJM order extending the MOPR to new state-subsidized resources and FERC’s Feb. 20 order narrowing the resources exempt from NYISO’s BSM rules in southeastern New York. The latter order requires the ISO to subject storage and demand response to a minimum offer floor in its capacity market. (See FERC Narrows NYISO Mitigation Exemptions.)
“We should get 51 votes,” said Van Hollen, who last month joined with colleagues in asking PJM CEO Manu Asthana to delay the next Base Residual Auction to give states time to react to FERC’s “rash decision.” (See PJM’s MOPR Quandary: Should States Stay or Should they Go?)
Murkowski said last week her 550-page bill, which incorporates some 50 bills previously approved by the Senate committee, “is our best chance to modernize our nation’s energy policies” since the 2007 Energy Independence and Security Act.
In addition to reauthorizing the Advanced Research Projects Agency – Energy (ARPA-E) through fiscal year 2025, the bill could provide new markets for coal and natural gas and add initiatives for carbon capture, ocean energy, next generation nuclear power and advanced vehicles. The legislation is being substituted for a geothermal bill previously introduced by Murkowski and Manchin (S.2657) with a Senate floor vote coming as soon as this week.
House Democrats also hope to put their imprint on the bill, Rep. Paul Tonko (D-N.Y.), a member of the Energy and Commerce Committee, told the ACORE forum.
Tonko said the bill is a step in the right direction but that the House of Representatives will seek to make “it even more robust” by seeking to amend it with an extension of the investment tax credit for wind and a standalone storage ITC.
The Senate voted 90-4 Wednesday to begin debate on the bill. Murkowski opened debate with comments on Title II, which includes cyber, grid and mineral security. She cited World Bank estimates that meeting the goals of the Paris Agreement would increase demand for battery storage minerals — lithium, cobalt and nickel — by 1,000%.
She said the bill “will help America become a leader in growing industries like battery and renewable manufacturing, along with the jobs and the economic growth that they represent. I think it also helps put the United States in the driver’s seat to prevent supply disruptions that could quickly derail our efforts to deploy renewables, energy storage, EVs and other technologies.”
More than 10 years after the failure of the Waxman-Markey cap-and-trade bill, carbon pricing’s time may be nearing — seemingly good news to those concerned about climate change.
But carbon pricing won’t solve the climate crisis by itself or persuade states to abandon their own clean energy policies, speakers said Tuesday at a forum in D.C. sponsored by New York University School of Law Institute for Policy Integrity and Duke University’s Nicholas Institute for Environmental Policy Solutions.
Former FERC Commissioner Suedeen Kelly
“We’ve seen political interest increase for doing something to reduce greenhouse gas emissions,” said former FERC Commissioner Suedeen Kelly, now a partner with Jenner & Block. “We’re seeing it in Congress. We aren’t seeing it in legislation likely to be passed by both houses yet. But people on the inside say it’s quite likely that we could do something in the next Congress around carbon or climate change.”
Kelly noted that the Obama administration deferred action on the Waxman-Markey bill, choosing to spend its political capital first on winning approval of financial market legislation and the Affordable Care Act.
She recalled that former Sen. Jeff Bingaman (D-N.M.), whom she served as a legislative aide, talked about the ability of carbon pricing to “create new wealth” by creating a commodity that didn’t exist before — a way to create funding for programs such as carbon sequestration that can win support from coal generators and other unlikely allies.
“If we had put it first, it would have sailed through,” she said. “That consensus, for political reasons, has fallen apart, but underneath it I think there are still the underpinnings that could give rise to a consensus again.”
Indeed, there is evidence that climate denialism may have reached its nadir.
On Feb. 26, the Electric Power Supply Association (EPSA), many of whose members own fossil fuel generation, announced its support for a carbon price.
That came two weeks after Minority Leader Kevin McCarthy (R-Calif.) announced Republican plans for addressing climate change through carbon sequestration and removal, prompting Jason Grumet, president of the Bipartisan Policy Center, to declare: “The climate science debate is formally over.”
But FERC Commissioner Richard Glick said carbon pricing won’t solve climate change by itself. Nor will it necessarily eliminate the tension over state and federal jurisdiction, illustrated most recently by FERC’s December order that PJM expand its minimum offer price rule (MOPR) to new state-subsidized resources, he said.
One issue, Glick said, is the price level.
Danny Cullenward, Stanford University
“If it’s too high, you’ll have some states reacting negatively to it. If it’s too low, a number of states are going to say, ‘Why should I [eschew] clean energy policies if FERC is going to impose a carbon price that we don’t think is going to have a significant impact?’”
Danny Cullenward, a Stanford University law lecturer, also is concerned about pricing levels, saying carbon pricing should “integrate” state policies rather than seeking to replace them. “The more this is done from the bottom up, the less of a risk that FERC will come in and say, ‘Here’s a $3 carbon price that applies to everybody and that’s the end of climate policy.’ Which I think is an awful outcome and — frankly in the hands of the wrong people — could be done.”
Won’t End State Policies
Jeff Dennis, general counsel for Advanced Energy Economy, said carbon pricing will be less effective in decarbonizing the economy outside of electric generation.
“There are reasonable [carbon] price levels that will get you significant benefits in the power sector today and that’s why we should do carbon pricing. When you’re thinking about economy-wide though, you need other policies, because you need some astronomically high carbon prices, from what I’ve seen, to get a lot of those hard-to-abate sectors to achieve carbon reductions,” he said.
“Are states going to have to rethink their own policies in response to markets and carbon prices? Sure. But I don’t think that’s going to obviate the need for states to continue to have policies — or frankly the desire of other states to continue to have policies.”
(From left) Burcin Unel, Institute for Policy Integrity; Jeff Dennis, Advanced Energy Economy; Travis Kavulla, NRG Energy; Casey Roberts, Sierra Club; and Abe Silverman, NJ BPU
Casey Roberts, senior attorney for the Sierra Club, said state energy policies have objectives including green energy jobs and priming the pump for technologies such as storage and offshore wind “that might otherwise not get off the ground but that are really needed to [reach the] 100% renewable energy future.”
“Because of that, I think the notion that carbon pricing is going to solve the MOPR [and] federal-state tensions is a bit misguided,” she said. “If the carbon price is intended to displace those other state policies, then that’s really a nonstarter for organizations like the Sierra Club, and I think many other stakeholders.”
Roberts said carbon pricing also poses an “opportunity cost” because of the limited resources of RTO stakeholder processes and FERC.
“We feel like there are bigger obstacles to clean energy deployment in the country and a major one of those … is the mandatory capacity market,” she said. “I’m worried that carbon pricing becomes a distraction from resolving those other problems.”
Gary Helm, lead market strategist for PJM, insisted capacity markets can enable emissions reductions, citing PJM’s generation shift following the Mercury and Air Toxics Standards (MATS), which resulted in the closing of many coal generators.
Pricing in Capacity or Energy Market?
NYISO Principal Economist Nicole Bouchez said the ISO determined its carbon price should be incorporated in the energy rather than capacity market because of transmission constraints that prevent upstate New York, which has 87% zero-emission generation, from delivering it to downstate, where only 27% of the mix is renewable.
“The problem with having it in the capacity market is in many ways [you have] some of the same problems as in renewable portfolio standards and different types of subsidies and payments from states to resources, which [are]: How do you make sure that what you’re getting is offsetting carbon production and not being replaced by something else; and how do you make sure you’re getting the most bang for your buck in that? Because location matters. … We all have constrained systems. There are times when you can’t get energy from point A to point B, and the impact on the dispatch matters at those times.”
FERC Commissioner Richard Glick
Glick also cited the importance of transmission in meeting clean energy goals.
“We need to spend a lot more time at the commission … on the issue of transmission. How are we going to help the states achieve these dramatic, aggressive clean energy goals? We’re not going to do it unless we build out the grid.”
Abe Silverman, general counsel for the New Jersey Board of Public Utilities, had a different perspective, saying that carbon prices as an LMP adder to the energy markets is “a very small part of the solution.”
“We need to start shifting that carbon price into the future; into the planning horizon and incorporating those carbon externalities into things like capacity markets, into our long-term planning,” he said.
“This is one of the fundamental questions,” he added. “Are we trying to incent investment in the lowest carbon grid tomorrow, or are we really trying to build the low-carbon grid of the future? Those are two very different policy outcomes. And they may require a different style of carbon pricing.”
Expensive RECs
Travis Kavulla, vice president of regulatory affairs for NRG Energy, said carbon prices may not matter “if states are just going to commandeer this market” with long-term resource procurements at higher prices.
He cited the cost of D.C.’s solar renewable energy credits (SRECs), which he said “exceed the social cost of carbon by an order of magnitude.”
“The rooftop solar developers of [wealthy] Georgetown thank the people of [low-income] Anacostia for their generous contributions to climate policy,” he joked.
FERC last week accepted settlements with Bonneville Power Administration and FirstLight Power, along with an unnamed entity in the Eastern Interconnection, for violations of NERC reliability standards. The commission said in a notice on Friday (NP20-7) it would not review the settlements, leaving NERC’s penalties intact.
NERC submitted the settlements to the commission in a spreadsheet notice of penalty (NOP) on Jan. 30.
$50,000 Penalty for Unnamed Entity
The unnamed entity accepted a $50,000 settlement with ReliabilityFirst over violations of reliability standard CIP-010-2 R2, relating to the management of configuration changes in its IT systems.
On Nov. 30, 2016, the entity’s IT team discovered that some of its device types — not specified in the NOP — were not being properly monitored for baseline configuration changes as required by CIP-010-2 R2. The standard requires the baseline for a group of devices to reflect every individual device within the group. However, staff at the entity had assumed that one device within a device type or group could be used to represent all devices within that type or group.
This approach is allowed under CIP-010-2 R1, but ReliabilityFirst found that the entity’s management had not clearly communicated the R2 requirements in procedures. As a result of the oversight, discrepancies developed in a number of device groups between individual device baselines and group baselines, leading to further errors, such as 11 devices missing port setting documentation, a violation of CIP-007-6 R1, and 10 potential missed change authorization instances, a violation of CIP-010-2 R1.
The IT team outlined the discrepancies in a self-report submitted to ReliabilityFirst on Feb. 16, 2017. The RE observed that “[not] monitoring baselines has the potential to affect the reliability of the Bulk Power System … by reducing the entity’s ability to identify unauthorized activity, changes, or vulnerabilities and by introducing system instability when making changes to assets.” It warned that the entity could have tried to make important decisions based on outdated information or missed unauthorized changes to ports needed for emergency operations (though this did not create an opportunity for unauthorized access).
However, the regional entity also credited the IT team for finding the discrepancy relatively quickly. The relevant requirement had gone into effect in July 2016, meaning the entity had been in violation for less than five months. In addition, ReliabilityFirst noted that the issue was discovered during a regular review of entity change management processes and device baselines. This, along with stringent defense-in-depth measures covering the affected devices, indicated that the entity had a robust safety culture.
Mitigating measures taken by the entity in response to the violation included:
Updating management training procedures regarding change management tools and compliance change management requirements;
Creating job aids for updates and monitoring and training employees in their use;
Investigating and documenting port ranges in baseline documentation;
Performing new baseline monitoring steps for IT and creating a baseline monitoring report and evidence for a cycle.
In determining the penalty level, ReliabilityFirst weighed these factors against the “severe” nature of the violation and “medium” risk factor. The RE also considered aggravating the penalty based on a previous incident of noncompliance with CIP-010-2 R2 but decided against this because the prior incident was attributed to a different root cause.
FirstLight Reports Ratings Error
None of the other violations in the NOP — one attributed to FirstLight Power and four to BPA — carried a monetary penalty.
The FirstLight Power settlement stemmed from a self-report filed to the Northeast Power Coordinating Council (NPCC) in 2019. The generator owner (GO) was seeking to register a violation of reliability standard FAC-008-3 R1, relating to the establishment of facility ratings. In a regular internal compliance review at the Cabot generating station on the Connecticut River in Massachusetts, the company had discovered incorrect ampacity ratings on several components. Correcting the relevant ratings limited the station’s overall rated capacity.
FirstLight determined that Cabot was the only station affected and that all of the components in question had been installed between 2001 and 2006 when the station was owned by the local transmission owner. When the GO discovered the discrepancy, it reduced the station’s maximum output to prevent unloading the limiting equipment.
Because of the age of the affected components, NPCC concluded that the violation spanned two versions of the relevant standard. FirstLight was in violation of FAC-008-1 R1 from Aug. 2007, when the entity registered as GO for the Cabot station, until the standard was retired on Dec. 31, 2012. The violation of FAC-008-3 R1 lasted from the standard’s introduction in January 2013 until the station’s output was reduced in July 2019.
Due to the duration of the violation, NPCC decided against compliance exception processing. However, in light of FirstLight’s quick mitigation activities — along with the low level of risk and lack of history of noncompliance, the RE ultimately declined to assess a penalty. Mitigation measures included the reduction of the facility’s output; revisions to its facility rating sheet; and updates to its procedures regarding tracking, documenting and approving changes to ratings.
BPA Files Transmission, Protection System Violations
Three of BPA’s violations concerned the MOD-029-2a, the NERC standard governing transfer capability calculations — but because two of the incidents occurred in 2016, they were found to involve the earlier version of the standard, MOD-029-1a.
For the first violation, BPA submitted a self-report to WECC in July 2016 that it had incorrectly allocated the total transmission capability (TTC) for one available transmission capability (ATC) path while responding to an outage in the Western Interconnection. Because of an agreement with another transmission operator, the entity was required to reduce the TTC pro-rata along with the other TOP during an outage. Instead, it took the entire reduction but corrected the allocation the same day.
The second case occurred on June 4, 2018, when it correctly posted the TTC on one ATC path but did not correctly allocate between affected transmission owners while assessing a seasonal limit as required by its allocation agreement. Instead, BPA allocated an additional 16 MW to one entity while reducing another’s allocation by the same amount. It corrected the issue the same day and submitted a self-report regarding the violation on June 15, 2018.
In response to both incidents, BPA allocated the correct TTC and clarified its desk-level procedures regarding the relevant issues. For the earlier incident the entity also tested its systems to ensure that operators can update ownership shares correctly.
The entity’s third violation, related to MOD-029, took place between March 27, 2016, and Sept. 6, 2016, and involved a 450-MW transmission reliability margin (TRM) for one ATC transmission path that was implemented on Feb. 3, 2016. The TRM was intended to ensure reliable system operation when the system operating limit across the ATC transmission path exceeded 2,000 MW. However, BPA set its TTC too low on March 27, April 2 and April 8, resulting in an incorrect TRM methodology.
The entity corrected its TRM calculation on Sept. 6, ending the violation. It then completed a series of mitigating steps, including the creation of a system to automate TRM submissions, updating its production environment to incorporate the new system and training staff on the new functionality. Mitigation was completed on Oct. 30, 2018.
BPA’s final violation concerned reliability standard PRC-005-2(i) R3, relating to “the maintenance of protection systems affecting the reliability” of the BES. On Dec. 23, 2016, the entity reported that four days earlier it had found that a control battery at one substation had not been inspected for unintentional grounds as required in the standard. BPA had incorrectly thought that maintenance was not required because the battery did not have automated ground detection equipment and that the battery was not subject to the standard because the substation did not support BES elements.
“However, in December 2016, BPA corrected its assumption because the VLA control battery at the substation supported distributed Under Frequency Load Shedding (UFLS), which qualified the VLA control battery as a BES element and subject to the requirements of PRC-005,” the NOP said. “As a result, BPA found one VLA control battery that did not have the required maintenance activities as far back as October 1, 2015, for its required four-month calendar intervals.”
WECC identified the root cause of the violation as BPA’s incorrect assumptions regarding the requirements for BES elements and about the significance of the lack of automated detection equipment. Mitigation actions undertaken by the entity included completing inspection and maintenance on the control battery and confirming the application of relevant inspection forms for all batteries subject to the standard. In addition, BPA added the missing control battery to the work management system and added its voltage readings to other monthly readings.
The entity is not subject to monetary penalties due to a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal entities.
The Senate Energy and Natural Resources Committee on Tuesday once again voted 12-8 to advance FERC General Counsel James Danly’s nomination to the commission for consideration by the full Senate.
Just as he did last November, ranking member Joe Manchin (D-W.Va.) joined Republicans in voting for Danly, who would serve a term ending in 2023. (See Danly, Brouillette Advance to Senate Floor.) And, as he did last year, Manchin voiced displeasure that President Trump had not nominated Democrats’ choice — Allison Clements, clean energy markets program director for the Energy Foundation — to fill a seat left open by the departure of Cheryl LaFleur in August.
This time, however, several senators — Ron Wyden (D-Ore.), Martin Heinrich (D-N.M.), Angus King (I-Maine) and Maria Cantwell (D-Wash.) — also expressed their frustration with the White House and what they called the politicization of FERC, referencing its recent orders on PJM’s minimum offer price rule and NYISO buyer-side mitigation as evidence.
King was particularly critical of the vote and interrupted Chair Lisa Murkowski (R-Alaska) before she could move on to an Energy Department budget hearing with Secretary Dan Brouillette.
“Madame Chair, I don’t quite understand … the way to get to the other nominee is to say ‘no’ to this one until we get the other nominee,” King said. “Why didn’t we hold and say, ‘We as a committee want both nominees together, and we’re not going to hold hearings and not going to move them until then?’” By advancing Danly alone, “there’s no incentive on the White House for putting anyone forward.”
Murkowski and King went back and forth, with Cantwell interjecting, until Manchin jumped in.
“‘No’ was the right vote for the purpose that you stated, Sen. King,” the ranking member said. He explained that he had personally assured Danly he would support his nomination with the expectation that the White House would move forward with Clements and that he did not want to go back on his word. He then committed himself to opposing any Republican nomination unless it is paired with that of Clements. Commissioner Bernard McNamee’s term ends June 30, but he has committed to staying until there is a replacement for his seat.
“I don’t care who they give me the next time, no matter how qualified that person is, I’ll make [it] known, if there isn’t a pairing, we’re not voting,” Manchin said.
As the discussion was going on, the committee’s Republican majority tweeted, “The process for filling FERC seats was designed to avoid the need to pair. That is why the terms are staggered by a year. #GetTheFacts”
ClearView Energy Partners noted that Senate Minority Leader Chuck Schumer (D-N.Y.) last year threatened to filibuster any energy legislation without a pair of FERC nominees. “That struck us as a bit of an idle threat, as no bill seemed destined for imminent floor consideration back in September,” ClearView said.
“We are not quite convinced that the minority leader is prepared to bring the Senate to a near stop over FERC nominations, but the option appears available to him, assuming he could hold his caucus together to maintain a filibuster,” ClearView said.
(Updated March 4 to include latest developments at CAISO.)
The nation’s grid operators are taking their first steps to respond to the spreading COVID-19 coronavirus, issuing travel restrictions, limiting access to their facilities and conducting stakeholder meetings through webinars and conference calls.
ERCOT, ISO-NE and NYISO have all emailed their stakeholders to say they are closely monitoring the outbreak and following guidance from federal, state and local health agencies to mitigate COVID-19’s further spread. CAISO followed suit Wednesday when it announced its own measures to prevent spread of the virus.
ERCOT notified stakeholders on Tuesday that, “out of an abundance of caution,” it has scrapped all in-person meetings through March 15 and replaced them with webinars or conference calls, effective Wednesday. The ISO has also instituted restrictions for visitors to all of its facilities and is canceling non-essential business travel by staff and contractors for the same period.
The Texas grid operator is also monitoring staff and their family’s international travel, instructing staff with illness or symptoms to stay home, and deep cleaning its facilities.
The COVID-19 coronavirus has infected more than 90,000 and killed more than 3,000 globally.| Shutterstock
The ISO said it will review its restrictions on a weekly basis and alert stakeholders to any changes.
“ERCOT provides a critical service to Texans, and we are taking an abundance of caution to ensure the health and safety of our staff during this time,” spokesperson Leslie Sopko said in an email.
NYISO was first to email its stakeholders, doing so on Feb. 28. ISO-NE, like ERCOT, messaged its members on Tuesday.
NYISO “strongly encouraged” members’ personnel that travel to the ISO’s facilities to minimize the spread by following The Centers for Disease Control and Prevention’s guidelines. It also asked that it be notified if members’ staff attended recent in-person meetings or met with NYISO staff and later reported symptoms or tested positive for the coronavirus.
NYISO said its requirements are effective immediately for its personnel and will remain in place until further notice.
ISO-NE suggested members’ employees not meet with its staff or visit its facilities if they feel ill or show symptoms. The ISO referenced CDC’s expectation that the number of coronavirus cases will continue to grow and recommended stakeholders consider following the its guidelines.
“It is important to stress that, at this time, the risk to [ISO-NE] business operations remains low,” the grid operator said in its email.
COVID-19 has infected more than 90,300 people worldwide, killing more than 3,000.
PJM told its members earlier that its Incident Response Team is monitoring the outbreak and the guidance from the CDC, World Health Organization, the U.S. State Department and local health officials.
The RTO said it has suspended all international business travel and canceled all international visits to the PJM campus. It is requiring staffers to obtain a physician’s clearance to return to work after travel to affected geographic areas. It also is conducting “an enhanced cleaning process” with hospital-grade disinfectant and said staffers are equipped to work remotely if necessary.
CAISO alerted stakeholders Wednesday that “to protect the health of the company’s staff, and prevent possible disruption to critical business operations ” it has issued temporary restrictions on all in-person meetings through April 1 — or until further notice. In-person meetings hosted by CAISO and its Western Energy Imbalance Market will be conducted as teleconferences or webinars when possible, the ISO said.
The policy applies to a series of key meetings scheduled for this month, including those for CAISO’s Board of Governors; the Western EIM Governing Body and Governance Review; the Market Surveillance Committee; the Market Performance and Planning Forum; and the 2021 Local Capacity Requirements process. The decision will also impact CAISO’s March 11 Resource Interconnection Fair.
The ISO has also restricted visitor access to its facilities and suspended non-essential business travel for employees.
“We understand that the new protocol may be an inconvenience, and we apologize for any changes in travel plans, but continued reliable operation of the electrical system is our company’s first priority,” CAISO CEO Steve Berberich said.
SPP told RTO Insider it is continuing to work with health officials to monitor COVID-19 and influenza threats and respond appropriately. The RTO said it would use its communication channels and social media to alert its stakeholders of any steps being taken.
“We have a robust emergency management and business continuity plan that exists to maintain uninterrupted provision of our critical services,” SPP’s Derek Wingfield said. “Our goal is to ensure both the health and safety of our employees and the continued reliability of the grid.”
Facing opposition from state regulators and consumer advocates, PJM said Monday it will suspend an initiative that could tighten fuel requirements for black start resources.
PJM’s David Schweizer told a special meeting of the Operating and Market Implementation committees that the initiative will go on “hiatus” for several months to allow the RTO to do additional analysis on the potential benefits of requiring some or all black start resources to have a secondary source of fuel in addition to their primary source.
Citing potential capital costs of up to $513 million, the Organization of PJM States Inc. (OPSI) told PJM in a letter Feb. 13 that “with no clear measure of benefit or risk reduction … there is not a strong foundation at this time to support any of the options” under consideration. It recommended “stakeholders consider refocusing their efforts towards exploring risk-informed measures that would be used to better define black start resource availability expectations.”
Based on OPSI’s feedback and discussions with other stakeholders, Schweizer said PJM concluded the “best approach is to step back and further assess the impacts” of the proposals before bringing any of them to a vote. The MIC had been planning a vote on the packages in a special session before its regular March 11 meeting. That special meeting has been canceled.
PJM called for the initiative in 2018, noting that the only fuel assurance requirement for black start resources is that they maintain enough for 16 hours of run time.
During the hiatus, Schweizer said the RTO will pursue a “three-pronged” research project, including expanding a previous study on the impact of delayed restoration resulting from the unavailability of black start units lacking fuel.
“We may look at expanding that analysis to look at more transmission operator zones or a different type of analysis with different assumptions,” he said.
RTO staff also “will look at something with respect to gas pipeline assessment impact analysis” and seek to estimate the economic impact of a delayed restoration “to address the concerns that the state commissions have raised,” Schweizer said.
He said the studies will take “several months to six months.” Staff will provide more details on the studies and timeline at the Market and Reliability Committee’s March 26 meeting.
In the meantime, he said, PJM also will propose a new problem statement and issue charge on the “rather urgent” need to update black start testing requirements. It also would consider updating black start termination and substitution rules and the capital recovery factors for compensation to reflect current tax laws and interest rates.
“ODEC will be very pleased to hear this news,” Old Dominion Electric Cooperative’s Adrien Ford said of PJM’s decision to conduct additional analysis on fuel security before seeking a vote.
Before adjourning the meeting, stakeholders heard summaries of two alternatives to the PJM/Calpine proposal that 100% of black start units have a secondary fuel source. PJM estimates its proposal would require $513 million in capital spending, increasing annual revenue requirements by $67.2 million over the current $65 million.
Alternative Plans
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), offered a proposal that would limit fuel assurance requirements to one resource per TO zone. “I didn’t see the votes [of consumer advocates and load interests for] going any higher than that. That’s why I put this together,” he said.
Poulos said the proposal was based on discussions with “a couple” of state advocates’ offices but was not an official CAPS proposal, which would require a vote of members. PJM estimated the capital cost of the proposal at $13 million, or $1.9 million per year.
PJM stakeholders are considering proposals that could add $1.9 million to $67 million in annual spending on black start resources. The RTO currently spends $65 million a year. | PJM
After the Feb. 5 MIC meeting, Exelon and the D.C. Office of the People’s Counsel joined on a proposal that each TO zone have at least one fuel-assured black start resource, with additional fuel-assured resources being awarded based on a cost/benefit analysis performed by PJM with input from the TO. (See “States, Advocates Unsure of Black Start Fuel Assurance,” PJM MIC Briefs: Feb. 5, 2020.) PJM estimated the cost would fall between Poulos’ and the RTO’s plan.
Tom Hyzinski of GT Power Group said that even doubling black start costs would add only $2.50/year to his electric bill for an all-electric home. “It’s been asserted that the benefits [of the PJM/Calpine proposal] haven’t been shown,” he said. “The cost of even the most expensive option is relatively modest.”
Erik Heinle of the D.C. OPC noted that the costs would not be spread evenly over the RTO’s footprint. “Some zones wouldn’t pay anything; others would be hit more substantially,” he said.
Thus, he said, PJM should allow state regulators to determine their “risk tolerance.”
“It would be their ratepayers who would be responsible for coming up with that difference,” he said.
FERC last week approved PJM’s updated annual cost responsibility assignments for projects in the Regional Transmission Expansion Plan (RTEP) over the objections of Old Dominion Electric Cooperative (ODEC), which said the RTO should be required to provide more information (ER20-717).
Included in the approvals are assessments for regional facilities, necessary lower-voltage facilities and merchant transmission facilities with firm withdrawal rights, based on the zones’ and facilities’ peak load in the 12 months ending Oct. 31, 2019.
ODEC asked FERC to order PJM to specify each zone’s peak megawatt value and the date and time of the peaks, which were not included in the RTO’s Dec. 31 cost allocation filing. The commission said ODEC should seek the information through the Transmission Expansion Advisory Committee and noted the data are “readily available” on the RTO’s website.
$237M in RTEP Additions
The ruling came a week after the PJM Board of Managers added almost $237 million in baseline transmission projects to the RTEP: FERC Form 715 transmission owner criteria projects totaling $202.37 million and RTO baseline reliability projects totaling $34.6 million.
American Electric Power is responsible for $188.4 million in Form 715 improvements, including projects to correct N-1 and N-1-1 thermal and voltage violations in the western Fort Wayne, Ind., area for contingencies in the Carroll, Sorenson, Columbia and Whitley stations.
PJM’s board approved AEP’S $188.4 million project to correct N-1 and N-1-1 thermal and voltage violations in the western Fort Wayne, Ind., area for contingencies in the Carroll, Sorenson, Columbia and Whitley stations. | PJM
Another AEP project will correct N-1-1 thermal and voltage violations on the Bradley-Sun 46-kV line section and Tams Mountain-Glen White 46-kV line section.
Also making Form 715 improvements is American Municipal Power, which is spending $7.5 million for a new 0.3-mile 138-kV, double-circuit line tapping the Beaver-Black River 138-kV line and expansion of the Amherst No. 2 substation.
Two TOs are making investments driven by reliability or baseline load growth.
Delmarva Power & Light is spending $20.5 million to rebuild 12 miles of the Wye Mills-Stevensville 69-kV line and reconductoring the Silverside-Darley 69-kV line and replacing terminal equipment.
FirstEnergy’s American Transmission Systems Inc. (ATSI) is spending $14.1 million to reconductor an 8.4-mile section of the Leroy Center-Mayfield Q1 line between Leroy Center and Pawnee Tap.
The spending approved Feb. 20 is in addition to $163 million in projects, mostly to address baseline reliability criteria violations, which the board approved Dec. 3.
Previously approved baseline projects to replace three 230-kV breakers in the PSEG zone in Bergen County, N.J., totaling $3 million are no longer required and have been canceled.
Since 2000, PJM has authorized $37.8 billion in RTEP projects.
A U.S. district court last week dismissed with prejudice a lawsuit seeking to overturn a Texas law giving the state’s incumbent utilities the right of first refusal over transmission projects (1:19-cv-00626).
The District Court for the Western District of Texas on Wednesday effectively ended an attempt by a number of NextEra Energy subsidiaries to repeal the legislation (Senate Bill 1938), which they said discriminated against out-of-state transmission developers.
The court also denied intervention requests by nearly a dozen parties.
Passed last May, the law grants certificates of convenience and necessity to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
District Judge Lee Yeakel said the plaintiffs, NextEra Energy Capital Holdings (NEECH) and four other NextEra transmission owner/developer entities, failed to demonstrate that the law discriminates against out-of-state transmission providers or has a discriminatory purpose or effect.
NEECH, NextEra Energy Transmission (NEET), NextEra Energy Transmission Midwest and Lone Star Transmission alleged that SB 1938 discriminates against interstate commerce by giving electric utilities that already operate in Texas the sole right to build transmission lines with an end point in the state. They based their reasoning on the Constitution’s Commerce and Contracts clauses. (See NextEra Takes Texas to Court over ROFR Law.)
The court found SB 1938 was not “analogous” to the cases the NextEra companies cited, “all of which involve the flow of goods in interstate commerce or burdensome requirements as a precondition for allowing the flow of goods in interstate commerce.”
“SB 1938 does not purport to regulate the transmission of electricity in interstate commerce,” Yeakel wrote. “It regulates only the construction and operation of transmission lines and facilities within Texas, which distinguishes it from the cases upon which plaintiffs rely.”
Hartburg-Sabine Junction project | MISO
Yeakel said the law does not single out Texas transmission providers “as the sole beneficiaries of the right of first refusal over out-of-state providers” and does not “overtly discriminate” by granting incumbent transmission providers the ROFR “because that preference does not discriminate against out-of-state providers.”
“Indeed, most incumbent providers in Texas are owned by out-of-state companies, and SB 1938 allows out-of-state providers a means to enter the Texas market for transmission services by buying a Texas utility,” Yeakel said.
The plaintiffs had claimed standing because the law jeopardizes its Hartburg-Sabine Junction competitive project in southeast Texas. NEET Midwest in 2018 won a competitive bid from MISO for the project, which would consist of a new 500-kV line, four 230-kV lines and a 500-kV substation.
MISO executives have acknowledged that the congestion-relieving project “may face challenges” as a result of the law, casting its future into doubt. (See Uncertainty Deepens for Hartburg-Sabine Project.)
Katie Coleman, counsel for the Texas Association of Manufacturers, said the industrial lobbying group agrees with the decision.
“Industrial companies in Texas see theoretical benefits to a bidding process for transmission but have yet to see a workable model,” she said. “If and when the state wants to move in that direction, it needs to be done deliberately and with appropriate customer protections. Until then, having the current endpoint owners build new lines makes the most sense for customers and the state.”
PJM stakeholders on Friday got their first look at the price floors that could be applied for capacity resources under the expanded minimum offer price rule (MOPR).
PJM shared what it called “informational” net cost of new entry (CONE) values, while The Brattle Group, which was hired by the RTO, gave a presentation on its work to develop avoidable-cost rate (ACR) values, the default minimum price for existing units.
The Brattle Group’s preliminary gross avoidable-cost rate (ACR) for existing generating resources, showing low, high and “representative” costs ($/MW-day) | The Brattle Group
PJM’s informational net CONE numbers range from a low of $235/MW-day for a combined cycle plant to a high of $3,261/MW-day for offshore wind.
PJM’s Gary Helm said the RTO was terming the net CONE values “informational” because they include “placeholder” energy and ancillary services (E&AS) offsets from a 2018 FERC filing. “We feel pretty good” about the gross CONE values, he said.
Brattle’s preliminary gross ACRs for “representative” plants ranged from a low of $40/MW-day for solar PV to $892/MW-day for a single-unit nuclear plant (using 2022 dollars).
PJM’s capacity prices have never exceeded $245/MW-day, a peak set in the EMAAC region for delivery years 2013/14. The RTO’s most recent Base Residual Auction, held in 2018, saw a top price of $204/MW-day in the PSE&G zone.
Resources seeking to offer below the net ACR or net CONE values would have to seek a unit-specific exemption.
Both PJM and Brattle representatives emphasized during the special meeting of the Market Implementation Committee that their numbers were preliminary and would be refined before the RTO makes its compliance filing, due March 18.
Energy & Ancillary Services Offset
PJM’s Pat Bruno began the session with a presentation on the differences between the use of forward-looking and historical E&AS revenues. The E&AS will be subtracted from generators’ going-forward costs to determine unit-specific net ACRs.
The RTO and its Independent Market Monitor currently calculate unit-specific offer caps with a simple average of net E&AS revenues from the three most recent calendar years.
PJM’s preliminary net cost of new entry (CONE) values, including energy and ancillary service (E&AS) revenue offset | PJM
Bruno said PJM intends to allow use of both historical and forward-looking E&AS revenues in determining MOPR offer floors for both new and existing units, consistent with its previous policy on new units.
He acknowledged this could result in an existing unit’s net ACR floor price being above its net ACR offer cap. In such cases, he said, the seller will be required to offer at the floor price.
Becky Robinson of Vistra Energy said the possibility of the floor price exceeding the price cap “is creating a dartboard for people to criticize the justness and reasonableness” of MOPR floor prices. But she said it was unlikely to happen. “Why would anyone use forward-looking [prices] if it would make their MOPR floor price higher?”
‘Irrational’ FERC Ruling on Maintenance
Monitor Joe Bowring gave a short presentation on the IMM’s ACR template and discussed the development of E&AS offsets, including the treatment of major maintenance.
Bowring cited what he called the “unintended consequences” resulting from an April 2019 FERC order requiring that major maintenance costs be allowed in energy offers and no longer included in net ACR calculations (ER19–210). Bowring said the “irrational definition of major maintenance” was made at PJM’s request and over the IMM’s objection. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.)
“The FERC decision removed major maintenance from gross ACR, which would reduce net ACR if nothing else changed. Historical net revenues should not be reduced after the fact by subtracting major maintenance as PJM and Brattle propose. That would effectively mean that ACR was not reduced. Price-based offers were used in the calculation of historical net revenues. If participants wanted to include major maintenance in their energy offers, they would have done so,” Bowring explained after the meeting. “Similarly, for going-forward net revenues, there is no reason to assume that participants will include major maintenance in their energy offers. We have seen no evidence that they do.”
Reducing net revenue to reflect major maintenance would improperly assume that all generators include 100% of their maintenance costs in their offers, Bowring said. “We didn’t see any bump [in prices] after the FERC order. Forwards didn’t really change.”
“Arbitrarily adding major maintenance costs to energy offers will inappropriately reduce net revenues and increase net ACRs,” he added.
Bob O’Connell of Panda Power Funds said FERC’s policy might cause units to run even when LMPs are below their operating costs just to minimize maintenance expenses from start-ups, citing a “rule of thumb” that one start is equal to 20 base hours. That, he said, could suppress energy prices in off-peak hours.
Bowring said O’Connell’s scenario seemed logical but that there was no way for the Monitor to quantify such behavior in unit-specific ACR calculations.
“We put a list of items that shouldn’t be included in major maintenance in our filing, and FERC copy and pasted it in the definition of what should be” included, Bowring said.
‘Representative’ Resources
Brattle’s Michael Hagerty presented the consulting firm’s preliminary default ACR values.
Michael Hagerty, Brattle | The Brattle Group
The group listed costs it considered most representative of each technology along with “representative low” and “representative high” costs to provide a range PJM could consider in its filing. “Not the lowest of the low and the highest of the high,” Hagerty said.
The selection of the “representative” plant for each technology was based on several characteristics, including the distribution of plants by age, state, capacity and — for fuel-burning resources — post-combustion controls.
Hagerty said the firm identified the primary factors affecting cost across fleets and compared publicly available costs with those in a confidential generation project database from design firm Sargent & Lundy.
The “very significant range of plants within each technology … creates a bit of a challenge,” he said. “Our intent was to show what we see in the existing fleet and leave it to PJM to determine where they want to be on this scale.”
PJM Vice President of Market Services Adam Keech said it was too soon to say “what [costs] we think is reasonable.”
“We’re still digesting the data ourselves,” he added.
Brattle noted that its gross ACR values for nuclear units are about 12% lower than the Monitor’s largely because of lower capital cost assumptions and because it estimated that about $1/MWh of operations and maintenance costs should be accounted for in the estimate of net E&AS revenues. Bowring said the $1 reduction was inconsistent with the FERC order on maintenance.
Exelon’s Jason Barker said the Monitor’s characterization of what constitutes variable operations and maintenance (VOM) costs are “illogical and wrong.” Barker indicated that the nuclear capital costs referenced in the Nuclear Energy Institute data, upon which Brattle and the Monitor have relied, are not the classes of costs described in the FERC order.
“It’s not our characterization. It was FERC’s,” Bowring responded.
Energy Efficiency
Brattle calculated a net CONE of $230/MW-day (ICAP) for energy efficiency based on analysis of EE programs of four utilities in PJM: American Electric Power, Baltimore Gas and Electric, Commonwealth Edison and PPL.
It noted its net CONE for PJM EE was higher than estimates for ISO-NE, saying it was because of lower assumed wholesale energy prices in PJM ($29/MWh vs. $60/MWh in ISO-NE).
Brattle calculated net CONE by subtracting wholesale energy savings and transmission and distribution savings from gross CONE but did not consider any capacity savings.
PJM’s Jeff Bastian said capacity market benefits were not included for EE just as they were excluded from the calculations for generating resources.
“This is a load-side resource,” responded Bruce Campbell of CPower Energy Management. “It’s different than a generator.”
Tom Rutigliano of the Natural Resources Defense Council said Brattle appeared to be “vastly undervaluing” EE, saying it should be assessed from the point of view of the asset owner. In addition to including capacity benefits, that means energy savings should be valued at the retail — not wholesale — rate, he said.
“This stuns me that you simply ignore the capacity benefit at the customer level,” Campbell added. “You recognize the energy savings, but you don’t recognize the capacity savings. That just seems inconsistent to me.”
The three-hour meeting ended with a presentation by Michael Borgatti of Gabel Associates on how resources seeking unit-specific price floors would document their actual costs. “The fundamental rule in the Tariff is you have to be able to provide the same level of detail and support as in [PJM’s] CONE study. That is a reasonable standard,” he said.
Borgatti used an example of a 100-MW single-axis tracking solar PV array to identify what he said are errors in PJM’s assumptions. Correcting PJM’s assumptions on useful life (30 years, not 20), construction duration (nine months), weighted average cost of capital (7.7%, not 8.2%) and capacity value (60%, not 42%) reduced the gross CONE from $290/MW-day to $168/MW-day, he said.
Separately, he offered a Lazard proxy that set gross CONE at $143/MW-day, which he said represented “what you should expect market participants to” submit. “There’s a delta there [between $168 and $143], but it’s not significant,” he said.
With a $213/MW-day E&AS offset, he added, net CONE is zero.
Gabel Associates says correcting errors in PJM’s assumptions on useful life, construction duration, weighted average cost of capital (WACC) and capacity factor reduced the gross CONE for a 100-MW single-axis tracking solar PV array from $290/MW-day to $168/MW-day. | Gabel Associates
MIC Chair Lisa Morelli said Borgatti’s presentation would inform PJM’s compliance filing and future discussions on MOPR procedures. She joined Keech in apologizing that some materials for Friday’s meeting were not posted until just hours beforehand.
“You are … getting real-time updates of the latest and greatest PJM thinking,” she said. “It’s a pretty heavy lift within the 90-day compliance [deadline]. You’re seeing a race to the finish.”
Next Meeting
The next scheduled discussion on MOPR will be the MIC’s regular meeting March 11. Morelli said the afternoon would be reserved for MOPR, “if not more.”
SAN FRANCISCO — The former president of the California Public Utilities Commission told a gathering of energy lawyers Friday that common assumptions about the future of renewable energy and electrification need to be re-examined.
Michael Picker, who left the commission in summer 2019, was replaced by Marybel Batjer. Since then, Picker said he’s been working for Gov. Gavin Newsom, putting together an energy roadmap for the state as it tries to reach its ambitious renewable energy and greenhouse gas reduction goals by midcentury. (See Retiring CPUC President Still Has Lots to Say.)
His research has led him to new thinking about reliability and resilience, he told the Western Chapter of the Energy Bar Association at its annual meeting. Picker was the keynote speaker, and his thought-provoking presentation was discussed throughout the day’s proceedings.
For instance, Picker said the idea that the state’s biggest utilities are opposed to clean energy, while community choice aggregators are more progressive, doesn’t pan out in the math.
The state’s investor-owned utilities — the “much maligned” Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — had achieved renewable portfolio compliance of 40%, 36% and 41%, respectively, by the end of 2018, he said.
“So that’s not bad progress since the goal was 30% by 2020,” Picker said. “And if you look at the forward compliance, each of them expects to be at 52% or above by 2024.”
Under Senate Bill 100, passed in 2018, the IOUs are expected to achieve primary reliance on clean energy sources by 2045.
Community choice aggregators (CCAs), most of which promise clean energy to retail customers and will become the majority of load-serving entities in coming decades, are falling behind, he said. They’ve proven more reliant on short-term contracts with out-of-state generators, with transmission constraints between source and sink, he said.
The IOUs, with more capital available, have been more successful in signing long-term contracts with in-state generators, whereas the “smaller entities [such as CCAs] with thinner capitalization have had a harder time being able to make those investments in long-term contracts,” he said. (See Calif. Lawmakers Reveal Growing Divisions over CCAs.)
Another issue, Pickers said, is that time-of-day demand from residential and commercial customers is merging.
California’s aerospace and automobile manufacturing economy died away, he said. Those industries used electricity around the clock, working three shifts every 24 hours. Now the state has a lot of “computational-based industries” that mirror household demand, with peaks about 200 hours out of the year, mainly after 5 p.m. on weekdays, he said.
“Who wants to build a power plant that’s only going to be selling electricity for 200 hours per year?” Picker said. “And how do you do that with solar if some of that demand is in the evenings after the effective capacity of solar starts to decline as the sun’s going down to the horizon?”
Rethinking EVs
Picker also noted that there’s a common misconception that generators are responsible for the bulk of greenhouse gas emissions. Electricity generation is responsible for 15% of carbon emissions, whereas transportation is responsible for 40%, he said.
State law requires a reduction in greenhouse gases by 40% below 1990 levels by 2030.
“As the electricity supply gets cleaner, it’s harder to reach that 2030 goal simply on the backs of the electric industry,” Picker said. “We have to address transportation.”
Statutes set a goal of having 2.5 million electric vehicles on California’s roads by 2025, he said. But planners tend to focus on individual ownership of EVs.
“There’s an implicit assumption amongst many of the planners that transportation is going to look the same 20 years from now as 20 years before,” he said. “Most of the policy … is focused on single ownership cars.”
In some urban areas, including Sacramento, more EVs are being charged and parked under car-sharing programs. The cars are taken to central locations where they’re charged at night, when demand is lowest, and distributed throughout the cities during the day.
Why, then, are government planners focused on owners charging cars in their garages? Picker asked.
“Why wouldn’t [car sharing] be the public policy priority rather than people installing [charging stations] in their homes?” he said.
Another point: As more Western states adopt renewable energy goals, the hydroelectric power generated in the Pacific Northwest will become a more coveted commodity, Picker said. And limited transmission will result in greater congestion, he said.
Electricity is becoming devalued as a commodity, while poles and power lines are generating greater revenues, he said.
The focus of policies has been on reducing greenhouse gases, but climate change will require greater resilience, which Picker said is another term for adaptation to changing circumstances.
“What I’m arguing,” Picker said, “is that we’re going to see more and more focus on adaptation.”
