The PJM Members Committee approved changes Thursday to the RTO’s fuel-cost policy (FCP) rules, but not before another round of animated debate over force majeure events.
The new rules, which are spelled out in revisions to Schedule 2 of the Operating Agreement and Manual 15: Cost Development Guidelines, were approved by a sector-weighted vote of 3.9 (78%).
The package, proposed by the PJM Industrial Customer Coalition, was approved by the Markets and Reliability Committee last month on a sector-weighted vote of 3.57 (71%) despite concerns that new safe harbor provisions would create loopholes permitting the exercise of market power. (See PJM MRC OKs Revised Fuel-cost Policy.)
Heat rate and cost curves for 550-MW natural gas-fired team unit | PJM
It eliminates the FCP annual review, the FCP requirement for zero-marginal-cost offer units, and market seller submission deadlines. The deadlines for reviewing FCPs was changed: The Independent Market Monitor will have an initial 10 business days to review a policy and an additional five business days when a market seller revises the policy. PJM will have 20 business days to review a policy and an additional five business days for reviewing revisions, although that time frame can be changed if agreed to by PJM and the market seller.
The ICC included a safe harbor provision proposed by generators but modified the terms for imposing penalties for noncompliance. It would impose the full penalty if the unit clears in the day-ahead market or runs in real time on a cost-based offer and is paid day-ahead/balancing operating reserves. The full penalty also would apply if the unit fails the three-pivotal-supplier (TPS) test for constraints or the cost offer is above $1,000/MWh.
Susan Bruce, representing the ICC, said the concerns raised in February about the proposal “resonate with industrial customers,” but she said she will continue to support the measures.
“We offered [changes] in the spirit of compromise, and we believe that compromise is an essential element of the stakeholder process,” Bruce said.
The safe harbor section of the proposal allows a generator to avoid penalties if it deviates from its FCP because of a force majeure event.
PJM will determine whether the evidence proves the force majeure event “directly impacted the market seller’s ability to conform to the methodology” in its FCP. “The applicability of this provision shall not apply for economic hardship nor obviate the requirement for a market seller to submit cost-based offers that are just and reasonable, and utilize best available information to develop fuel costs during a force majeure event,” the revised OA says.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, cited concerns over the safe harbor provision in requesting a sector-weighted vote on the proposal, saying he was surprised to see the revisions listed in the consent agenda because it had been the subject of a contentious vote at the MRC. “Many of us will be voting ‘no,’” he said of his group’s members. He said he would like to see PJM create a policy on what items can be included in the consent agenda.
Monitor Joe Bowring said he continued to oppose the revised force majeure language because no one has identified an event that would prevent market sellers from following their fuel-cost policies. With the emergence of the COVID-19 pandemic since February’s meeting, he said, sellers could argue “that every single fuel-cost policy would now be moot.”
“There’s actually no reason to have a force majeure exception, and the current state of the world indicates that even more clearly,” Bowring said. “The proposal is equivalent to not having any fuel-cost policies now and having every single unit be subject to unit-specific review based on the actual facts. That is not workable. The purpose of fuel-cost policies is to address unusual and unexpected conditions, and current fuel-cost policies do that.”
Paul Sotkiewicz of E-Cubed Policy Associates disagreed with the classification of the current pandemic, saying he believed it was “alarmist and also wrong” to use the coronavirus as a force majeure event because there have been no issues in getting pricing for fuels.
“I think the fuel-cost policies are still in effect here, even with the coronavirus,” Sotkiewicz said. “It’s a scare tactic.”
Two market efficiency transmission projects already approved by MISO face continued obstacles, while two others slated for belated inclusion in the 2019 Transmission Expansion Plan must wait longer for approval, stakeholders heard last week.
Speaking during a conference call of the Board of Directors’ System Planning Committee on March 24, MISO Executive Director of System Planning Aubrey Johnson said uncertainty lingers for the nearly $129 million Hartburg–Sabine Junction project because of the passage of a Texas law granting incumbent utilities the right of first refusal for any transmission projects built in the state. The law may mean incumbent Entergy ultimately takes up the project. (See Appeals Court Sets Dates in Texas ROFR Challenge.)
The RTO is currently using its established variance analysis process to study the project and developments around it. The analysis is used to study projects already approved under the MISO Transmission Expansion Plan that are later disrupted by circumstances that affect the project’s cost, schedule or “the ability of selected developers and transmission owners to complete.”
“We are now continuing to gather information as part of the variance analysis and continuing to work with legal teams,” Johnson said.
The proposed 23-mile 500-kV transmission line, four short 230-kV lines and new substation would connect three county networks in East Texas and alleviate longstanding congestion and import limitations in the area.
MISO has acknowledged the recent court action, but confidentiality restrictions limit its ability to talk publicly about the project. Spokesperson Allison Bermudez said the RTO will make a further statement once it completes the variance analysis, which is expected soon.
“MISO is committed to delivering the benefits of the Hartburg-Sabine Junction transmission project in East Texas. Under our Tariff, MISO is currently executing a process to assess the Texas state law developments and their impact on the project,” Bermudez told RTO Insider earlier this month.
Huntley-Wilmarth Costs Up
MISO is similarly conducting a variance analysis on the nearly $156 million Huntley-Wilmarth line, which now faces cost overruns after a route change.
Huntley-Wilmarth met the criteria to qualify as a market efficiency project in MISO’s 2016 Transmission Expansion Plan. It would have been open to competitive bidding if not for Minnesota’s right-of-first-refusal law. Original estimated costs on the project ranged from $88 million to $108 million.
MISO said costs increased 30% because of state-ordered changes to the routing plans. The new permitted route will cross the Watonwan River in Minnesota.
Johnson said a variance analysis is automatically triggered when a project experiences cost overruns of more than 25% of original baseline costs.
MISO President Clair Moeller said the analysis is performed to provide a clear public record of the project, not to re-evaluate its merits or halt work.
“Once we approve a project, we don’t really have the ability to stop it,” Moeller said.
MISO executives said they believe Huntley-Wilmarth will still be able to deliver benefits in excess of its cost.
Meanwhile, MISO’s first competitively bid project from 2016 — the $67 million Duff-Coleman 345-kV transmission project in Southern Indiana — is making progress and could be completed as early as June 2020.
MISO-PJM Interregional, 1st SATA Projects not yet Approved
Two holdover projects from MTEP 19 have yet to receive the board approval MISO hoped for by March.
“We will not seek approval until Tariff revisions are approved,” Johnson said, noting that MISO staff must first attend a technical conference that will probably be set for late spring.
American Transmission Co.’s Waupaca area energy storage project was meant to ease transmission reliability issues in central Wisconsin.
“What happens — is this project just in limbo? So how do we deal with the congestion that this project was supposed to alleviate?” Director Nancy Lange asked.
Vice President of System Planning Jennifer Curran said MISO wants to “let the process play out a little more” before it decides on a direction or project alternative. She said it is in communication with the developer in the meantime.
MISO also faces more work before the board can approve its first major interregional market efficiency project with PJM.
The $22 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in the northwestern corner of Indiana can save about $5 million in congestion costs per year, MISO said. (See MISO, PJM Poised for 1st Major Interregional Project.) PJM’s Board of Managers has already approved the project.
But MISO doesn’t yet have an approved regional cost allocation for interregional projects with PJM. FERC rejected its newest interregional cost allocation filing in late March, finding the proposal to reserve regional allocation for market efficiency projects 230 kV and above ignored the potential regional benefits of lower-voltage projects. MISO 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, barring lower-voltage projects from cost-sharing.
Before the order, MISO staff said the Michigan City-Trail Creek-Bosserman project would not be regionally allocated in, reasoning that the project’s 138-kV rating disqualified it from a regional allocation.
The commission ordered MISO to instead use a design based on adjusted production costs for economic interregional projects 100 kV and above with PJM. MISO has a month to make the filing. (See “Interregional Filing Also Rejected,” Another Rejection for MISO Cost Allocation Plan.)
MISO will submit the filing within FERC’s 30-day deadline, Johnson confirmed. He said the wait for FERC’s response would probably push approval of Michigan City-Trail Creek-Bosserman to MISO’s June Board Week.
FERC on Thursday approved MISO’s proposal to bar participants from its market when it identifies evidence of default, manipulation or unreasonable risk. The new procedures took effect Saturday (ER20-877).
The Tariff changes allow MISO to request additional collateral when it perceives an unreasonable credit risk from a market participant. The new rules will also allow the RTO to reject applications from new market participants and from former market participants that have an uncured financial default in its markets and attempt to rejoin under a different name.
Finally, the RTO will ask prospective and current market participants for more specifics on their annual certifications. It will inquire about past defaults, bankruptcies, dissolutions, mergers or acquisitions and any investigations. (See MISO Looks Beyond FTRs for Market Protections.)
MISO control room | MISO
“The proposed revisions will allow MISO to improve the protection of its market participants from financial losses that result from unreasonable credit risks and defaults while also providing additional clarity and transparency to market participants,” FERC said.
The commission also pointed out that MISO has pledged to “preserve in writing” any decision it makes to reject or suspend a market participant from participation. FERC said the RTO’s written reasoning could “form a record before a commission proceeding if necessary.”
FERC said MISO made the filing “in light of significant credit events in other” RTOs/ISOs, referencing GreenHat Energy’s record default in PJM’s financial transmission rights market in June 2018. PJM last week approved tightened credit requirements to prevent future defaults. (See related story, PJM Members OK Tighter Credit Rules.)
The revisions are an extension of stepped-up requirements in MISO’s FTR market. The RTO received FERC permission in November to apply higher collateral requirements to the market (ER20-73).
MISO’s Board of Directors last week cleared the Advisory Committee to create an 11th stakeholder sector while also instructing the committee to overhaul its sector design to produce a fuller participatory model.
The board said the committee’s recent recommendation to create a new “Affiliate” sector for hard-to-define members works only in the short term. It directed it to develop a long-term solution that guarantees all members full participation in the stakeholder process. (See MISO Advisory Committee OKs 11th Sector.)
In the meantime, MISO should file with FERC revisions to its Transmission Owners’ Agreement (TOA) to include the new sector, the board said.
Board Chair Phyllis Currie said the board met to discuss the proposal and agreed that it should be in place only until the AC creates a new proposal focused on fair participation for sectors and mindful of voting power. She also said the AC should ensure that sectors are divided into groupings of likeminded members.
“I say ‘short term’ because I think in the longer term, there still needs to be more discussion on how various sectors participate,” Currie said during a committee conference call Wednesday. The meeting took place via conference call instead of in New Orleans as originally planned because of the spread of the COVID-19 coronavirus. (See Virus Fear Sends MISO Board Week to the Web.)
Currie urged the AC to examine its current voting structure and think about affording members an equal voice. She said the board would give the committee a year to draft a fuller solution for incoming — and increasingly diverse — members.
The new sector would not be allowed a vote in either AC or Planning Advisory Committee matters, but it would have one designated seat for AC meetings and be allowed to offer opinions during the committee’s quarterly hot topic discussions.
The sector would serve as a home for any MISO member that isn’t participating in another sector. Prospective MISO members must declare a sector affiliation before they can join the RTO.
“I think other interest groups, other businesses, other NGOs will come to the table,” Director Nancy Lange told the AC.
The AC began debating the merits of an 11th sector last year when Lignite Energy Council, a North Dakota coal lobbying group, approached MISO about membership. The organization did not fit neatly into any of the existing 10 sectors and was almost relegated to the Environmental and Other Stakeholder Groups sector. But some AC members said it wasn’t appropriate for a sector to contain entities with diametrically opposed views and said the new sector was necessary to allow the Environmental/Other sector to have a singular voice. The Environmental/Other sector would be able to drop its “other” designation if FERC accepts the changes to the TOA.
Environmental/Other sector representative Beth Soholt said that, save for the Energy Storage Association, all other entities in the sector have an environmental focus.
So far, the proposed Affiliate sector seems destined for a fossil-fuel focus — at least at the onset. LEC indicated that it has drummed up interest among other entities interested in joining the new sector, including coal and iron mining organizations, coal trade organization America’s Power and various chambers of commerce.
LEC CEO Jason Bohrer said his organization had been “working on earning a seat at the table for the past 18 months.” He said the board’s decision was “a significant step in this long process.”
“We applaud the work of the MISO Advisory Council, the Board of Directors and MISO staff, as well as our partners like America’s Power, for their support of opening up the regional market planning stakeholder process to more voices and perspectives, which now will include coal producers along with chambers of commerce and other organizations that have strong electricity market interests,” Bohrer said in an email to RTO Insider. “We look forward to providing a strong voice for the coal miners and utilities who provide the electricity that is the ‘always-on’ backbone for the electric grid and the economy in our region.”
Hot Topic Panel Delayed
On the same conference call, the AC postponed the policy discussion portion of its meeting until June.
The committee was supposed to hold a panel-style discussion featuring industry experts as its quarterly hot topic discussion during the March Board Week. The panel was meant to focus on how RTOs deal with resource transition and would have featured one executive apiece from NYISO, CAISO and ERCOT. However, AC leadership said a panel discussion was too difficult to navigate in a teleconference-only format.
The wind and solar industries were disappointed last week that Congress’ massive $2 trillion stimulus bill did not include extensions of the production and investment tax credits.
In a joint letter to Congress, the American Wind Energy Association (AWEA) and the Solar Energy Industries Association (SEIA) said the COVID-19 coronavirus pandemic was causing “delivery delays, necessary employee absences, serious financing concerns, and project cancellations or postponements. This is jeopardizing the jobs of our combined 364,000 workers, threatening to sidetrack tens of billions of dollars in investment.”
President Trump on Friday signed the bill, the largest stimulus legislation in U.S. history, as shelter-in-place rules grind the U.S. economy to a near halt.
The major provisions of the Coronavirus Aid, Relief and Economic Security (CARES) Act (S. 3548) include $1,200 checks for millions of taxpayers “as rapidly as possible”; programs to disburse nearly $900 billion in loans to business impacted by the pandemic; and an expansion unemployment benefits.
AWEA CEO Tom Kiernan said “relief provisions ensuring renewable projects can secure financing and meet safe harbor continuity schedules are critical to preserving a strong domestic clean energy sector. Making these adjustments to existing tax credits would provide the industry the flexibility needed to accommodate COVID-19 delays, without costing the federal government any additional money. … Without assistance, 35,000 American jobs, $43 billion of investment and $8 billion in payments to local communities are at risk.”
President Trump signed the CARES Act on March 27. | The White House
SEIA CEO Abigail Ross Hopper acknowledged that some of the bill’s provisions for individuals and displaced workers would benefit solar industry workers. But she warned that “as a result of this pandemic, the solar industry stands to lose half of our jobs.”
The tax credit extensions were also not part of a separate bill introduced by House Democrats while Senate leaders and Treasury Secretary Steve Mnuchin negotiated over the Republican-crafted CARES Act, though the House bill did include emission limitations for airlines. When Democrats blocked passage of the Senate bill March 22, Majority Leader Mitch McConnell (R-Ky.) the next day falsely accused them of holding up the bill over the extensions and emission limits.
“Democrats won’t let us fund hospitals or save small businesses unless they get to dust off the Green New Deal,” McConnell said. “They’re continuing to hold up emergency measures over tax cuts for solar panels.”
In truth, McConnell was outraged by Democrats blocking a procedural motion on the bill after he had rallied his caucus members to bite their tongues and pass a House Democrat-crafted bill the week before as an initial response to the crisis. Minority Leader Chuck Schumer (D-N.Y.) and his caucus were likewise peeved that Republicans had included a $500 billion fund in the CARES Act to bail out corporations harmed by the crisis without any oversight provisions. The partisan rancor led to a rare, actual debate on the Senate floor, between McConnell and Sen. Joe Manchin (D-W.Va.).
After two days of negotiations, however, the Senate ended up passing the bill early Wednesday morning, 96-0. The House of Representatives followed on Friday, passing the bill by voice vote, rather than unanimous consent off the floor as Speaker Nancy Pelosi (D-Calif.) and Minority Leader Kevin McCarthy (R-Calif.) had wanted, after Rep. Thomas Massie (R-Ky.) indicated he would object and attempt to force members to record their votes.
This forced 218 members of the House to travel back to D.C., some of whom drove to avoid flying, to assemble a quorum to block Massie’s motion — this despite the Centers for Disease Control and Prevention’s advisory not to have 10 or more people gathered in one place.
Trump signed the bill into law hours after the House passed it.
FERC last week rejected AMP Transmission’s request for a waiver of the commission’s Standards of Conduct and requirements to maintain an Open Access Same-Time Information System (OASIS) (TS19-1).
AMP Transmission (AMPT) is an affiliate of American Municipal Power that was created to own and operate the transmission facilities of AMP and AMP’s members. AMP has purchased a 138-kV ring bus from the city of Napoleon, Ohio, and plans to purchase a similar transmission facility from Wadsworth, Ohio, both less than 50 feet in length. It also owns a 1.84-mile, 69-kV transmission line and two 69-kV station facilities in Amherst, Ohio.
AMPT said it qualified for a waiver of the OASIS and Standards of Conduct requirements because its facilities are “limited and discrete,” geographically dispersed and do not form a contiguous network.
American Municipal Power headquarters in Columbus, Ohio | American Municipal Power
AMPT said its transmission function employees work independently from AMP’s marketing function employees and that it has contracted with Gridforce Energy Management to provide NERC transmission compliance services.
But PJM and its Transmission Owners sector told FERC the waiver should be rejected because the marketing affiliates of AMPT will have access to nonpublic transmission information through its participation in the PJM Transmission Owners Agreement-Administrative Committee and other committees where planning or operational transmission information is discussed.
The TOs said that if the commission approved the waiver, it should prohibit AMPT from participating in PJM activities and TO meetings in which nonpublic transmission information is disclosed or discussed, noting that Old Dominion Electric Cooperative committed to similar conditions when it sought waivers from the commission.
The TOs expressed concern that a waiver would give AMP the ability to use nonpublic information available to PJM transmission operators to benefit AMP’s merchant trading — the kind of behavior the Standards of Conduct’s no-conduit rule was designed to prevent.
The commission agreed.
“We find that an entity like AMPT that participates as a transmission owner in an RTO or ISO cannot qualify for waiver of the commission’s OASIS or Standards of Conduct requirements on the basis that its facilities are limited and discrete,” FERC ruled. “Although AMPT’s facilities are limited in size, AMPT’s participation as a transmission owner in PJM qualifies its facilities as an integral part of the integrated PJM grid and therefore AMPT’s facilities cannot be considered as limited and discrete under our waiver precedent.”
The California Public Utilities Commission has established two building decarbonization pilot programs to jump start the state’s electrification of residential structures, devoting $200 million toward the effort.
The Building Initiative for Low-emissions Development (BUILD) program and the Technology and Equipment for Clean Heating (TECH) initiative were created under Senate Bill 1477, which the state Legislature passed in 2018. Lawmakers tasked the CPUC with implementing the programs.
“These two pilot programs are designed to develop valuable market experience for the purpose of decarbonizing California’s residential buildings in order to achieve California’s zero-emissions goals,” Commissioner Liane Randolph wrote in her proposed decision, which the commission adopted March 26.
“The BUILD program and TECH initiative are building decarbonization pilot programs intended to raise awareness of building decarbonization technologies and applications, test program and policy designs and gain practical implementation experience and knowledge necessary to develop a larger scale approach in the future,” the CPUC said.
The move comes amid efforts by some cities to require electrification of new, and in some circumstances, existing structures. Eliminating furnaces and water heaters that use natural gas could contribute significantly to California’s efforts to become carbon-neutral by midcentury, advocates contend. (See West Coast Pushesfor Building Electrification.)
Replacing traditional gas appliances such as water heaters with electric units is a key goal of electrification. | Edison International
The BUILD program is meant to incentivize technologies in new residential buildings that reduce greenhouse gas emissions (GHG) well beyond the requirements of the state’s building and energy codes.
The California Energy Commission will administer the program with CPUC oversight. At least 30%, or $60 million, of the total $200 million must be earmarked for new low-income housing under SB 1477.
“This percentage is not the ceiling for spending on low-income housing but rather, the floor,” the proposed decision says.
“The CEC should aim to design the BUILD program with the goal to deploy near-zero emission building technologies in the largest number of new residential housing units possible,” it says.
The TECH initiative is intended to promote the adoption of space heating and water heating equipment powered by electricity instead of gas in new and existing residential structures. A third party, still to be selected, will implement the program, with specific technologies still to be identified, the CPUC said.
“To accelerate market development and adoption of building decarbonization technologies targeted under the TECH initiative, we allow the implementer discretion to consider or build upon an array of tactics and approaches,” the CPUC said. “We decline to adopt a prescriptive list of eligible technologies and products until an implementer is selected.”
American Electric Power on Monday warned shareholders that the company’s financial condition and operations could be “adversely affected” by the COVID-19 pandemic as other utilities considered delaying spring maintenance.
In an 8-K filing with the Securities and Exchange Commission, AEP said it is working to mitigate the pandemic’s “potential risks” and that it will continue to review and modify its plans as conditions change.
AEP’s headquarters building in Columbus, Ohio.
“Despite our efforts to manage these impacts to the company,” AEP said, “their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, we currently cannot estimate the potential impact to our financial position, results of operations and cash flows.”
The Columbus, Ohio-based company said it has updated and implemented a company-wide plan that addresses specific aspects of the coronavirus pandemic. The plan provides guidance on emergency response, business continuity and precautionary measures to take on behalf of employees and the public, the company said.
“This is a rapidly evolving situation that could lead to extended disruption of economic activity in our markets,” AEP said.
Deferred Maintenance
As of Tuesday, other major utilities including Con Edison, Exelon, NextEra Energy, Entergy, CenterPoint Energy and Sempra Energy had not issued similar warnings to their stockholders.
AEP and other Edison Electric Institute members have pledged to suspend utility disconnects during the crisis.
DTE Energy announced March 23 that it is suspending all noncritical infrastructure and maintenance in response to the pandemic. “This move to keep employees home — in instances other than emergency response to customers — helps to ensure they do not add to the growing spread of the virus and further stress the health care system, equipment and services across the state,” it said.
“Right now, there’s definitely a lot of uncertainty regarding maintenance outages this spring,” said Maggie Cashman, a power market analyst for Genscape, during a webinar Tuesday. “The main concern that has been brought up … is the status of nuclear [refueling] given that they require a large number of contract workers from across the country.”
AEP companies operate in 11 different states. | AEP
NB Power has decided to delay the refueling of its Point Lepreau Nuclear Generating Station in New Brunswick, which had been scheduled for April, because of the outbreak.
In the U.S., however, “nuclear outages have gone largely as planned,” Cashman said, noting the refueling of NextEra Energy’s Seabrook plant in New Hampshire was expected to begin this week as scheduled. “Gas generation outages are much more likely to be postponed because they’re not critical and unnecessary for continued operation in the near-term.”
The Nuclear Energy Institute says 32 nuclear plants in 21 states are scheduled for refueling outages this spring.
The Nuclear Regulatory Commission is allowing reductions in non-essential maintenance work, Cashman said. Last week, the NRC said it will allow temporary waivers of its rules limiting the number of plant operators who can stay at work.
Supply Chain
Duke Energy made an 8-K filing March 27 on the pandemic saying it was “actively managing the materials, supplies and contract services for our generation, transmission, distribution and customer services functions” and has had “no issues of significance” in its supply chain. It said it would provide an update on the actual and potential business and financial effects of the pandemic when it announces first quarter 2020 financial results on May 12.
AEP said that while the company has instituted measures to protect its supply chain, global shortages will likely affect its maintenance and capital programs. AEP has enjoyed strong financial success lately. In February, it reported a total shareholder return of 30.5% in 2019, exceeding the 27.5% total return for the S&P 500 Electric Utilities Index. (See Renewables Key to AEP’s Performance.) However, the company’s stock has lost nearly 24% of its value since Feb. 18, when its share price hit a 52-week high of $104.97. Shares closed at $79.98 Tuesday.
New Jersey regulators have taken the first step in determining whether the state should remain in PJM’s capacity market or to go in a different direction to meet the state’s electricity needs.
The New Jersey Board of Public Utilities (NJBPU) voted March 27 to investigate if staying in the capacity market will impede Gov. Phil Murphy’s goals of 100% clean energy sources in the state by 2050 or increase consumer costs (Docket No. EO20030203). (See NJ Unveils Plan for 100% Clean Energy by 2050.)
If not achievable, board members have instructed staff to examine alternatives to the market.
“Taking control of our own resource mix may be the only way to stop the Trump administration’s attempts to prop up fossil fuels to the detriment of our clean energy program,” said NJBPU President Joseph L. Fiordaliso in a press release. “We will do everything in our power to prevent that from happening.”
[FERC on Tuesday extended the deadline for comments on PJM’s compliance filing in the MOPR proceeding to May 15, from April 22, in response to a request by the Public Utilities Commission of Ohio (ER18-1314-003). PUCO had sought a delay until the end of the coronavirus emergency or no earlier than June 1. Commissioner Richard Glick dissented, saying he would have granted PUCO’s request. Opposing the delay were the PJM Power Providers Group and the Electric Power Supply Association, which said in a joint filing: “PJM has not conducted a capacity auction since May of 2018 and the lack of market certainty has harmed both consumers and suppliers.”]
Hope Creek Nuclear Generating Station in New Jersey
State officials are concerned the MOPR will prevent new offshore wind generation and nuclear units receiving zero-emission credits from clearing the capacity market, forcing state residents to pay twice for capacity. The state has set a goal of procuring 7,500 MW of offshore wind by 2035. (See NJ Sets Schedule for OSW Procurements.)
The board directed its staff to conduct the process through written comments, technical conferences and public hearings.
The written comment period, which is open through April 29, asks for responses to several questions, including the following:
Can New Jersey utilize the fixed resource requirement (FRR) alternative to adequately satisfy the state’s resource needs?
Can it utilize the FRR to accelerate achievement of clean energy goals stated in its Energy Master Plan?
Can other mechanisms, such as a clean energy standard or clean energy market, facilitate the achievement of the state’s clean energy goals?
What “practical limits” may result from the state’s location along the Atlantic Ocean and the NYISO seam?
Should the state consider creation of a state power authority?
Cynthia Holland, director of BPU’s Office of Federal and Regional Policy, presented the investigation proposal at the March 27 meeting.
Board member Upendra Chivukula asked Holland if an exact timeline to come up with a resolution has been put in place. “This is an important initiative, so a timeframe will have some kind of inputs that come from the stakeholders,” Chivukula said.
Holland said besides the written comments that are to be filed by April 29, the staff does not yet have a finalized date for issuing its recommendations to the board.
NYISO stakeholders on Monday explored detailed assumptions and modeling descriptions for a study on transitioning the New York grid to a cleaner future.
Roger Lueken and Sam Newell of the Brattle Group presented the Installed Capacity/Market Issues Working Group (ICAP-MIWG) the thinking behind the study, which will simulate market operations and investment through 2040 to inform ISO staff and stakeholders on market evolution. (See NYISO Focus Turns to Grid ‘Transition’.)
“The model is reasonable for painting a broad-brush picture of how the supply and demand will look in the future,” Newell said. “It’s not a super granular model, it’s zonal, with a ‘bubble’ [representation] transmission layout and is a somewhat stylized representation of the generation fleet where we aggregate individual units
“There are a lot of unknowns currently about how we will meet the state goals, and what kinds of new resources will come in,” Newell said.
In conjunction with NYISO, Brattle developed a 5-zone “pipe-and-bubble” representation of the New York grid. | The Brattle Group
The modeling helps the ISO answer several questions, he said, such as what types of renewable resources will be needed to meet the Clean Energy Standard, including flexible resources and storage, and how electrification will affect load profiles and market operations.
“Wow, the world is so different now, three weeks after our last meeting, but we’re just building on what we did then to provide more detail on the assumptions and on some of the modeling approaches,” Newell said.
New York Gov. Andrew Cuomo in February proposed a budget amendment to speed up the permitting and construction of renewable energy projects in order to meet the state’s ambitious clean energy goals. (See Cuomo Proposes Streamlining NY’s Renewable Siting.)
The Climate Leadership and Community Protection Act (A8429), signed into law last July, calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.
The CLCPA’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.
Modeling Approaches
David Clarke, director of wholesale market policy for Power Supply Long Island, asked how the study would simulate the impact of shortage pricing on energy revenues in the CLCPA future, which might hinge on the supply-demand balance and the amount of surplus capacity in the system.
“We are only partly representing [shortage pricing] in the study,” Newell said. “First of all, we’re not necessarily representing all of the features of either extreme net load conditions that could lead to shortage pricing, nor are we fully representing the dynamic challenges of ramping, and so we’re not fully going to capture that, even if we do represent the upgrade in demand reserve curves in the model.
Electrification and climate change are forecast to affect load shapes. | The Brattle Group
“Secondly, we’re not actually designing this study to explore the different ways to implement enhanced shortage pricing, for example, through a richer demand curve,” Newell said. “That actually takes a lot of design and is tricky to do well.”
In modeling generators, Lueken said the study is accounting for known retirements and additions to occur over the next few years and not just existing resources, as in the ISO’s 2019 Gold Book.
“So, for example, we are accounting for the potential for downstate peaker retirements due to the new NOx rule,” Lueken said. “We’re currently planning to assume that downstate peakers built before 1986 retire, that frame units built after 1986 retire, that the aero-derivative units built since 1986 could, instead of retiring, decide to economically retrofit. However, we’re reevaluating these assumptions based on the compliance plans the generators have submitted to the ISO.”
The new NOx regulations go into effect May 1, 2023, with initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen. Generator compliance plans were due March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
Modeling the capacity value of wind and solar. | The Brattle Group
The study also models the declining capacity value of wind, solar and storage.
“The capacity value of the 5,000th MW of solar will be much lower than the first MW of solar because as you get so much solar in the system, it tends to shift the hours that capacity is needed to other hours in which the solar is not generating,” Lueken said. “It’s the same for wind, and there’s a similar dynamic in place for energy storage.”
The high-level approach to develop the relationship between the amount of resources deployed and the capacity value of these resources entails varying the amount of each technology in turn while holding everything else constant, he said.
“For all the resources, the capacity value falls off quite a bit when you have 10,000 MW deployed,” Lueken said.
Capacity Market and Reliability
Clarke presented a study by PA Consulting and the Long Island Power Authority on how the transition to renewable energy resources will impact the ISO’s installed capacity market, moving to a system dominated by low variable-cost, high fixed-cost resources from one now dominated by the opposite: high variable-cost, low fixed-cost units.
“We are basing our capacity market on the premise that new capacity is needed,” Clarke said. “If you have to add capacity for something and it’s not monetized [in the capacity market], in this case greenhouse gas abatement, the premise that you’re going to need new capacity for reliability is really no longer a valid premise.
“Making a more granular market, making sure there are sufficient market signals for generators to recover the ‘missing money,’ breaking down what things capacity is providing, different kinds of capacity and paying them for things they are providing — that is the kind of approach I see as being necessary in the long run,” Clarke said.
Voluntary bilateral markets should continue, but the underlying market price should be disaggregated. These structural changes are necessary in the long run, as the existing structure may not best advance the state’s clean energy mandates, he said.
“As energy margins and prices are declining, [and] the needed capacity is facing retirement, we recognize the essential need for long-term support for renewable resources,” Clarke said.
Howard Fromer, director of market policy for PSEG Power New York, asked why a resource would need long-term support: “Is your own model still going to encompass out-of-market support? That seems to undermine everything you’re talking about in terms of [market] efficiency.”
“I don’t think it needs to,” Clarke said. “There will be attributes that will be monetized as we move in this direction, and attributes that aren’t, so to the extent that we have not monetized the attributes that we need, there will be need for renewable resources and out-of-market payments in the long term.”
The proper place to recognize the desirable attributes of renewable energy resources is in the energy market, said Mark Younger, president of Hudson Energy Economics.
“We have a multiyear effort to properly try and capture the value of those renewable attributes but have not yet been successful. But that is the proper way to capture it, to put a price on energy attributes and incorporate it into the market,” Younger said.
Storage resources would still have value in scarcity conditions requiring a price signal, “but it’s not a capacity signal. Trying to do it through a capacity price is a very blunt instrument being wielded by blind people,” Younger said.
Clarke said the paradigm of trying to include everything possible in a 2040 energy price was “not particularly workable.”
Clarke highlighted differences among those who would allow highly volatile and perhaps extreme energy and ancillary service prices driven by flexible resource shortages to provide the incentive for their construction from those that would assure development of sufficient flexible resources through a targeted capacity payment.
Offshore wind speed (and ultimately power) is more broadly distributed than conventional generation outages. | PA Consulting/LIPA
“We do support the NYISO’s proposal to enhance ancillary services revenues as a means of more efficiently distinguishing resources that can provide flexible resource services over and above those that cannot,” he said. “However, we do recognize that an additional missing money payment for flexible capacity attributes could signal an appropriate mix.
“I see energy as declining in price and in value generally,” Clarke said. “I also see some reliability challenges going forward — increasing ICAP requirements, net load shifting, a changing load shape and frequency of ramping, saturation of particular renewable resources in certain load pockets and continued need for firm dispatchable resources.”
Clarke showed a graph indicating that offshore wind speed — and ultimately power output — is more broadly distributed than the duration of conventional generation outages.
“If the Long Island buoy data perfectly correlated with the sites offshore New York City, then the capacity value of offshore wind would be effectively zero,” Younger said. “While this is informative to indicate that we probably are massively overvaluing the capacity value of wind, because there are so many hours with very low wind speed, it doesn’t really take us beyond that observation.”
