MISO last week floated a proposal that would require network upgrades needed by projects in the generator interconnection queue to reach certain voltage and price levels before they could be tested for the economic benefits needed for cost-sharing eligibility.
But renewable proponents argue the plan wouldn’t do much for developers facing costly upgrades.
The proposal is a starting point for MISO’s effort to coordinate and align studies found in network upgrade planning in the interconnection queue and the RTO’s annual Transmission Expansion Plan (MTEP), Senior Manager of Economic Planning Neil Shah told stakeholders during a Planning Advisory Committee teleconference Wednesday. (See Regulators Not Sold on MISO Tx Planning Sync.)
Under the proposal, a generation project’s needed upgrade would need a minimum rating of 230 kV and cost at least $5 million to be eligible for evaluation as a possible market efficiency project (MEP), the same thresholds set out for MEPs in MISO’s proposed cost allocation plan, currently awaiting Local Projects Axed from MISO Cost Allocation Refile.)
MISO is additionally proposing that costs for a network upgrade submitted for economic evaluation can be spread across a group of interconnecting generation projects as long as they are $50,000/MW or higher. However, the projects necessitating the upgrade would need to have already completed the queue and executed a generator interconnection agreement (GIA) before they could be evaluated.
Shah said a GIA execution would help MISO avoid running economic analyses on projects that haven’t completed all interconnection studies.
“The benefit of this process is that it allows MISO and stakeholders an opportunity to compile and list all [generator interconnection] projects for economic evaluation rather that doing it on an ad hoc basis as interconnection projects come in,” Shah said.
He said MISO is aware that the RTO’s Environmental and Other Stakeholder Groups sector is critical of the proposal, arguing that it wouldn’t give interconnection customers certainty on future cost-sharing as they make their way through the definitive planning phase (DPP) of the queue.
Too Late
Sustainable FERC Project attorney Lauren Azar said the economic evaluation would still come too late for “bona fide” developers saddled with large network upgrades that could show regional economic benefits for others.
“This proposal is not going to solve the problem of generators being scared away by large increases, because by the time a generator interconnection agreement is signed, those customers would have already been scared away by large network upgrade costs,” Azar said. “I don’t think this scratches the itch of the problem we have before us.”
“We’re not going to wait until we have signed GIAs in order to get an economic evaluation. … This really doesn’t solve the problems. If folks get to a signed GIA, it’s likely that they can afford those upgrades,” Clean Grid Alliance’s Natalie McIntire argued.
But Shah said he didn’t think an economic evaluation earlier in the DPP would be feasible. Even if MISO were to figure out the timing issue, it likely wouldn’t make a substantial dent in project withdrawals because affected-system studies with neighboring grid operators — which come later in the interconnection process — also reveal high upgrade costs, he said.
Trust Queue Price Signals?
Stakeholders asked how interconnection customers could gain insight into whether their network upgrades could be economically beneficial.
Shah said it would depend on the customers’ access to tools and modeling — or by hiring of consultants, if they do not have tools to perform their own economic analysis.
“The interconnection queue is working as designed. We’ve got too many interconnection projects interconnecting at places where there isn’t enough transmission. It’s sending that signal to either reinforce the grid or go somewhere with less congestion,” WEC Energy Group’s Chris Plante argued.
| Consumers Energy
Indiana Utility Regulatory Commission staffer Dave Johnston agreed, saying requests for proposals or power purchase agreements could benefit from inclusion of grid upgrade costs.
“We need a big transmission overlay if a lot of people in the footprint wanted to procure resources of those areas,” and that’s not happening, Johnston argued.
Azar said that while price signals are appropriate, network upgrades have never been evaluated for economic benefits, even though project developers are being told to build “backbone” transmission projects.
Apex Clean Energy’s Richard Seide said the 2017 MISO West network upgrade costs were so egregious that nearly all were canceled, even those projects with PPAs approved by state commissions. Of the 27 generation projects that entered the February 2017 MISO West queue cycle, all but two dropped out, hindered by expensive but necessary transmission upgrades to accommodate the projects that cost tens to hundreds of millions of dollars per project.
More to Come
Shah stressed that the proposal for making interconnection project network upgrades eligible for economic evaluation was just the first step that MISO is considering to align transmission planning processes. He asked stakeholders to consider whether its next step should be changing its annual MTEP model building timeline in order to get more data from the interconnection queue.
Shah added that MISO’s goal is to align the two processes and not disturb them — or the FERC-approved Tariff language that governs them — as much as possible.
“I hope that we don’t make perfect the enemy of the good,” McIntire said, arguing that generator interconnection planning doesn’t need to perfectly conform to the timeline of a year and pointing out that even MTEP studies begin prior to the plan’s approval year. “We don’t need to get too hung up on making this 365 days.”
Nuclear Energy Institute CEO Maria Korsnick is always upbeat and optimistic about the future of nuclear energy when she makes her annual State of the Industry address, emphasizing plants’ emissions-free nature, high capacity factors and reliability.
Korsnick’s address this year, conducted online as it has been for the last two years, was no different. (See NEI CEO: FirstEnergy Emergency Request a ‘Bridging Strategy’.) But after the usual quick, bright and positive speech and soft question-and-answer with NEI spokeswoman Monica Trauzzi, NEI on Wednesday hosted a panel discussion featuring Union of Concerned Scientists President Ken Kimmell and Renewable Energy Buyers Alliance (REBA) CEO Miranda Ballentine. Both expressed general support for nuclear’s role in a future, zero-carbon generation mix, though both couched it with contingencies.
NEI CEO Maria Korsnick | NEI
In her opening speech, Korsnick positioned nuclear not as a competitor with renewables but as a partner. Though she noted that nuclear provides more than half of all carbon-free generation in the U.S. (as she did last year), “I want to be absolutely clear: We need to develop every source of carbon-free energy that we can. The world is counting on carbon-free resources to complement one another, not just compete. Our choice isn’t between nuclear power or wind and solar. It’s between a status quo of rising emissions from fossil fuels or a low-carbon future from all available sources, including nuclear.”
As evidenced by its name, REBA members — consisting of large corporations such as Facebook, Google and Walmart — have focused their procurement targets on renewable resources, particularly utility-scale wind and solar. But Ballentine said that “there has been a fairly significant transformation in the mindset of large clean-energy buyers, actually quite recently I would say … from goals of 100% renewable energy, to now companies thinking about 24/7/365 zero-carbon power, where renewable energy is one means to that end.”
REBA members “are beginning to think about other forms of zero-carbon power” besides large wind and solar projects, Ballentine continued. She listed geothermal, landfill gas and hydropower, “which is the one that tends to get left out of the discussions so frequently.”
ClearPath Executive Director Rich Powell (top left) moderates a discussion with REBA CEO Miranda Ballentine and UCS President Ken Kimmell. | NEI
But she said nuclear presents unique concerns for the organization: “What do we do with the waste, how do we handle proliferation, and how do we handle safety? … To the extent that new nuclear [technology] addresses some of those three core challenges of the existing fleet … I think you’re going to start seeing large consumers of power being more interested in the potential role that new nuclear can play.”
Kimmell emphasized “the herculean challenge” of not only using 100% clean energy but electrifying transportation and building heating. “This is a gigantic challenge that implies a pace of expansion of our electric grid in a way that we’ve never come close to doing in history,” he said.
Ballentine agreed. “I would say that many of the members in REBA … have a sense of urgency around the timeline that even 2050 for the power system is too late because there are so many other parts of our economy that are much harder to decarbonize.”
“To meet a challenge like” avoiding permanent climate change, Kimmell said, “all of us need to be prepared to abandon a tribalistic attachment to particular solutions.”
Monica Trauzzi, NEI | NEI
ClearPath Executive Director Rich Powell, who moderated the panel, echoed those sentiments. “I think that lesson of stopping being against the things we’re not specifically for — and eventually becoming for the things we’re not specifically for — is … just a crucial mental frame to adjust [to] as we respond to a challenge this enormous.” ClearPath, formed in 2014, seeks to “develop and advance conservative policies that accelerate clean energy innovation.”
Kimmell warned, however, that UCS’ support for nuclear power was conditioned on maintaining the Nuclear Regulatory Commission’s strict safety regulations for plants. “And I should say this is an area where it’s hard for us to work cooperatively because we don’t support efforts to relax those standards, and to the extent that those standards do get relaxed, we’re going to need to reconsider that criteria” of support, he said.
He also said any financial support through legislation should be reserved for plants that “meet or exceed the NRC’s highest safety standards.” He pointed to UCS’ 2018 report that recommended policies such as a national carbon tax or clean energy standard that would prevent existing nuclear plants from retiring earlier than their expected useful life.
ERCOT’s Technical Advisory Committee last week held its first full working meeting — albeit virtually — since the COVID-19 outbreak, endorsing a raft of revision requests, reviewing the committee’s strategic goals, and receiving updates from the Real-Time Co-Optimization Task Force (RTCTF).
The committee last conducted a full meeting in January. It has held several information sessions since, taking email votes on changes to the grid operator’s protocols and a $219 million transmission project. (See “Corpus Christi Tx Project Gets OK,” ERCOT Technical Advisory Committee Briefs: May 27, 2020.)
Speaking during a webinar the day after the TAC’s meeting Wednesday, ERCOT CEO Bill Magness said staff’s “experimentation” with conducting webinars resulted in a meeting “where the TAC was really able to do everything.” (See related story, Companies Debate When to Bring Back Staff.)
“Yesterday showed us we can do things on a remote basis,” he said. “[Stakeholder] meetings are still happening and still going on. We’re working through a lot of complexities with real-time co-optimization, but those folks aren’t missing a beat so far, knock on wood.”
The committee and the Board of Directors have already approved the use of roll-call votes during their remote meetings and modified other rules and procedures that compensate for the inability to meet in person. ERCOT’s corporate members will convene virtually July 10 to vote on the changes.
In-person meetings will not resume until October, at the earliest — if then.
ERCOT in May extended mandatory work-from-home rules through September. Staff can request “limited periods” of on-site work for “business-critical” task that can’t be completed remotely, but approvals will be limited and must come from executive leadership, human resources or security and facilities.
ERCOT Finds New Corporate HQ Site
Staff discussed with the committee their plans to move into a new office space, assuring members the new digs would not increase the system administrative fee.
Facing a 2022 expiration on its Austin office space it leases for corporate staff and Independent Market Monitor, ERCOT engaged a commercial real estate firm to find a new one. The grid operator’s criteria included at least 35,000 square feet of space, 180 parking spaces, proximity to the city’s airport and hotels, and an option to purchase.
The search resulted in a location within the same MetCenter business park where ERCOT is currently located. The board this month gave staff the go-ahead to execute an agreement with developers, which is expected to be finalized by the end of July, with construction to begin in August.
The grid operator expects the two-story building to be ready for occupancy by the end of next summer. Construction, equipment and furnishing costs are expected to be about $20 million, with ERCOT expecting to break even within 13 years.
Artist rendering of ERCOT’s new corporate headquarters | ERCOT
Staff said a lack of meeting space and technology issues are the main reasons they are moving from their home of 20 years. ERCOT supports about 300 stakeholder meetings each year at its MetCenter location.
“With the pandemic, do we even need a MetCenter? The answer is a strong ‘yes,’” said Betty Day, vice president of security and compliance. “The number of meetings is increasing.”
The new building will include two additional meeting rooms among its 5,000 additional square feet of public meeting space. Informal meeting areas, public booths and phone rooms will also be added.
Day said staff have had “multiple” conversations with the board about the plan. During individual meetings with stakeholders last fall, staff “made stakeholders aware this lease was coming up and we would look at alternatives,” she said.
Committee members expressed concern over making a costly real estate decision during a bad economy and encouraged further due diligence. Day said ERCOT felt the project’s costs were “reasonable.”
“We’re where we are,” Magness said during his online panel discussion. “We had to move on making a decision. As long as there’s ERCOT, there’ll be meetings. We’re moving forward with the real estate decision in this strange environment.”
Software Error Results in ‘Minimal’ Market Exposure
Staff said a software error in ERCOT’s credit monitoring and management system resulting from a 2012 protocols change resulted in “minimal” exposure to the market.
Mark Ruane, director of settlements, retail and credit, said errors in a real-time liability forward (RTLF) calculation resulted in a 100% multiplier, rather than the proposed 150% multiplier, being applied to some components of the real-time liability calculation, among other errors.
System limitations kept staff from quantifying the number of instances where an erroneous calculation determined a counterparty’s total potential exposure, Ruane said. He said the error may have resulted in either higher or lower RTLF estimates.
Staff patched the error on June 4 by aligning the calculation with the 2012 Nodal Protocol revision request (NPRR) that reduced the time frame for an operating day’s cash clearing and correspondingly reduced required collateral. ERCOT notified market participants of the error that same day.
Given the chance to ask questions, none of the TAC members did.
RTCTF Continues its Work
ERCOT’s Matt Mereness, chair of the RTCTF, told the TAC that the group met June 22 to consider ancillary services’ deployment and recall. Staff walked the task force through a 44-page slide deck in sharing their view and understanding of the process.
“As we develop the protocols, sometimes it’s hard to see how everything fits together,” Mereness said.
The task force is reviewing 90 of 187 binding document sections. It has reached consensus on 64 sections as it works toward a November deadline to develop real-time co-optimization’s protocols.
TAC Endorses Consent Agenda’s 16 Changes
The committee unanimously approved a 16-item consent agenda in a voice vote that concluded the meeting. Many of the changes were noncontroversial cleanup items; some removed gray-boxed language that is no longer needed. Four other changes were tabled while waiting on related revisions to pass through the stakeholder process.
The changes included six NPRRs, four changes to the Nodal Operating Guide (NOGRR), three revisions to the Planning Guide (PGRRs), a system change request (SCR), and single revisions to the Resource Registration Glossary (RRGRR) and the Verifiable Cost Manual (VCMRR):
NPRR903: clarifies the deviations that may occur with day-ahead market delays and adds language requiring ERCOT to issue a market notice for any act or omission to ensure the day-ahead process is successfully completed.
NPRR973: adds definitions for generator step-up and main power transformer to the Nodal Protocols and clarifies their uses.
NPRR983: deletes remaining gray-boxed language associated with NPRR257 (Monitoring Programs and Changes to Posting Requirements of Documents Considered CEII).
NPRR990: deletes the remaining gray box for NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) and relocates the defined term “combined cycle train” from “Resource” to “Resource Attribute.”
NPRR992: ensures the day-ahead liability estimate correctly includes ERCOT contingency reserve service charges and payments, as intended by NPRR863 (Creation of ERCOT Contingency Reserve Service and Revisions to Responsive Reserve).
NPRR993: clarifies gray-boxed language after the concurrent approval of NPRR902 (ERCOT Critical Energy Infrastructure Information) and NPRR928 (Cybersecurity Incident Notification).
NOGRR196: clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
NOGRR200: deletes all remaining gray-boxed language associated with NOGRR025 (Monitoring Programs for QSEs, TSPs and ERCOT).
NOGRR202: removes language regarding the posting timeline for resources’ megawatt limits when providing responsive reserve service. The requirement is now outlined in the Other Binding Document procedure for calculating individual resources’ limits.
NOGRR205: clarifies gray-boxed language to maintain consistency with revisions adopted from NOGRR197 (Align Responsive Reserve Manual Deployment Requirements with Current Practice) following the November 2019 incorporation of NOGRR191 (Related to NPRR939, Modification to Load Resources Providing RRS to Maintain Minimum PRC on Generators During Scarcity Conditions) into the guide. It also corrects an error in ERCOT’s administrative comments to NOGRR191 that inadvertently changed the language.
PGRR074: clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
PGRR078: specifies that data related to the regional transmission plan and special planning studies considered protected information may be posted to the market information system’s certified area for transmission service providers. The change also includes updated resource asset registration form generator data postings to the system.
PGRR080: aligns the Planning Guide with NERC standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
RRGRR022: clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
SCR810: adds logic to ERCOT’s energy management system by removing the flag that indicates to the operator that a unit representing a DC tie does not count toward the 2% criterion for activating transmission constraints.
VCMRR207: removes from the manual and its appendix language regarding the validation rules imposed on ERCOT’s external telemetry and used in the resource-limit calculator. This maintains consistency between the manual and the protocols by aligning energy storage resource-related provisions with NPRR986 (BESTF-2 Energy Storage Resource Energy Offer Curves, Pricing, Dispatch and Mitigation) and its provision that storage resources do not have start-up or minimum-energy costs and sets their mitigated offer cap at the systemwide cap.
The Midwest Reliability Organization (MRO) covered a number of timely issues at its quarterly Board of Directors meeting, held via conference call on Thursday because of the COVID-19 pandemic.
Protests, Racial Tensions Acknowledged
MRO CEO Sara Patrick wasted no time addressing the protests in the Minneapolis and St. Paul, Minn., areas that were set in motion by the killing of George Floyd while in Minneapolis police custody on May 25. MRO is headquartered in St. Paul.
“It isn’t easy to talk about racism. … I should be uncomfortable. I will never know what it is to be black,” Patrick said. She announced that MRO is forming a diversity and inclusion committee and holding all-staff trainings on implicit bias.
MRO Board Chair Tom Kent reminded attendees of Iowa teacher Jane Elliott’s famous eye-color classroom exercise.
“I was a participant in this exercise in my school as a sixth-grader in rural Nebraska,” Kent said, remembering how quickly the class “bought in” to the idea of special treatment based on eye color. He acknowledged that as a middle-aged white man from Nebraska, he’s lived much of his life “not really appreciating the impact of discrimination and prejudice,” but he can no longer ignore it.
NERC Trustee Jan Schori said staff reached out to make sure MRO employees and facilities were safe during the unrest.
Post-pandemic ‘Novel Normal’ Predicted
MRO is also betting the protest-and-pandemic combo will be an inflection point in the energy industry, and the board invited Caitlin Durkovich, of advisory firm Toffler Associates, to speak on societal changes affecting the energy industry.
Caitlin Durkovich, a futurist and infrastructure security expert with Toffler Associates | Toffler Associates
“When you think about the Great Depression and World War II, you understand the frugality brought on by those events. To this day, my father-in-law cuts away the mold from an onion [rather than throwing it away],” she said.
Durkovich also recalled the 1982 Tylenol poisonings in Chicago that spurred tamper-proof packaging and the banking changes implemented after the 2008 subprime mortgage crisis and ensuing Great Recession. As with these previous crises, Durkovich predicted that following the pandemic, the world will transition to a “novel normal.”
“COVID-19 is a catalyst for new behaviors,” she said. “My concern is the perception that we’re going to return to normal. … I think increasingly with each passing day that society is being stretched to its limits and the chances that it resumes its normal shape is slim.”
Durkovich said Black Lives Matter protests have also generated distrust in large institutions. Coupled with the recent emphasis on hygiene and supply chain reinforcements, she predicted that many households would move toward renewable resources and battery storage in a bid for independence.
Social distancing is accelerating “the dislocation of activities from locations,” Durkovich said, allowing companies to increasingly consider a virtual talent pool for new employees. More remote operations also mean more security issues, she warned.
MRO must battle with market uncertainty and an economic recovery dependent on when “the great wait” will let up, Durkovich added.
“This great wait will last until we have a vaccine or a better understanding of antibodies,” she predicted. MRO will need to be able to adjust its market strategy quickly on advice, Durkovich recommended. She also said decarbonization and electrification will likely continue unabated.
“I don’t think we’re going to take our foot off the pedal,” she said.
2021 Budget Approved; Assessment Flat from 2020
Also in the meeting, Patrick announced an $18.4 million budget for 2021, a 5% increase from 2020’s $17.5 million budget. She said MRO’s assessment costs in 2021 would remain flat from 2020 at nearly $17 million.
In keeping assessments flat, MRO is following the lead of NERC, which in its 2021 business plan and budget resolved to maintain its own assessment at the 2020 level of $72 million. (See NERC Aims for Cost Control in 2021 Budget.) The total ERO Enterprise budget for the year is projected to be $211.4 million, up 2.4% from the year before, while overall assessments are expected to grow by 0.8% to $189.2 million.
MRO Vice President Lam Chung said 2021 budget planning balanced financial pressures brought on by the pandemic and operational needs. Impacts from COVID-19 included delays to the regional entity’s office expansion plan, though the outbreak has also provided a limited amount of budget relief in the form of reduced meeting and travel expenses, as Chung and other RE representatives reported in a webinar earlier this month. (See Pandemic Provides Travel Savings for NERC, REs.)
Board members voted to approve the proposed budget, including funding for the MRO post-retirement medical plan and a targeted operating reserve of 30 days’ cash, and to submit it for approval by NERC and regulatory agencies.
NERC Delivers Update on Align, SEL Training
Stan Hoptroff, NERC’s vice president of business technology, provided an update on the development of the organization’s Align software project, an effort to standardize compliance monitoring and reporting processes across the ERO Enterprise.
The project’s flagship product, the Align tool for managing Compliance Monitoring and Enforcement Program-related work papers, is currently set for release in the first quarter of 2021. (See Align Tool Set for 2021 Rollout.) A separate product, the ERO Secure Evidence Locker — which will provide secure storage for potentially sensitive information — is planned for release in the fourth quarter of 2020, though the organization recently acknowledged that a delay to the following quarter is likely because of the pandemic. (See related story, FERC Approves NERC’s Align Spending Request.)
Upcoming key activities in development of NERC’s Align tool | NERC
In addition to detailing the expected benefits of the new software for REs — such as a standardized interface for reporting compliance issues, real-time access to information and secure management of data — Hoptroff also provided a look at the roles that REs and registered entities are expected to play in its future development. Testing by select registered entities is planned to begin by next month, with regional adoption workshops for ERO Enterprise staff scheduled for August and September. Regional training is planned for October through December, with a “Go/No-Go Process” scheduled for December and January.
“We’ve got a checklist of items that we will systematically step through to make sure all systems are go, and if they are, then we’ll publish the release schedule,” Hoptroff said. “But if there’s work to be done, then obviously we’ll put our time and attention into buttoning up whatever items … may need more work.”
RDA Acknowledges Independence Commitment
The MRO board also unanimously approved the new Regional Delegation Agreement (RDA) between itself and NERC that NERC’s board adopted at its May meeting, along with agreements with the other REs. (See “Other Approvals,” NERC Board of Trustees/MRC Briefs: May 14, 2020.) The agreement was set to expire Dec. 31 without a renewal.
Revisions in the new RDAs were relatively light but include:
eliminating maps of RE boundaries in favor of textual descriptions;
clarifying that delegation agreements may be terminated earlier than the end of the five-year term as long as written notice is provided of at least one year;
allowing REs greater flexibility regarding the use of funds collected through penalties; and
clarifying requirements regarding the nomination of independent board members.
The last topic was of special importance to MRO’s board, as the new agreement includes a provision “noting that MRO commits to maintaining independent members to perform oversight obligations” such as monitoring the compensation of CEO and board members, as well as maintaining conflict-of-interest and recusal policies for board members and staff. Future renewals of the RDA will require reviews to ensure MRO has continued to fulfill the independence principles.
“We’ve had a number of discussions over the course of the past couple of years with the board, and one of the outcomes of RDA negotiations was a confirmation … that MRO has satisfied independence principles. That was nice to hear,” Patrick said.
California Public Utilities Commission members on Thursday called FERC’s proposal to double its transmission incentive adder and make the bonuses easier to get “disgusting,” “appalling” and enough to make “one’s blood boil.”
The commissioners made their comments before voting unanimously to authorize CPUC lawyers to file comments with FERC opposing a March 20 Notice of Proposed Rulemaking to update its transmission incentives policy (RM20-10). (See FERC Proposes Increased Tx Incentives.)
“I think that my 6th grade teacher Sister Augustine would have captured this moment really well because, ‘It is atrocious,’ as she would say,” Commissioner Martha Guzman Aceves said. “The greed in the time of such economic recession is just atrocious.”
CPUC President Marybel Batjer took the opportunity to wish for a shakeup at FERC.
“This body has got to change. Unfortunately, they’re termed,” Batjer said of the federal commissioners, who serve five-year terms. “But [the nation] clearly needs some better thinking and better logic coming out of FERC. There’s no doubt about it.
“I think ‘appalled’ is another word that comes to mind besides ‘atrocious,’” she said.
The NOPR that outraged the California commissioners proposes a new approach to awarding transmission incentives and a doubling of the adder for participating in an RTO from 50 to 100 basis points. It would shift the policy away from awarding benefits based on the risks and challenges of a transmission development project to one focused on economic and reliability benefits.
FERC, which gained authority to issue incentives in the Energy Policy Act of 2005, implemented its policy in Order 679 in 2006. Last March, it opened a docket to reconsider its policy, prompting disagreements among stakeholders over the course FERC was taking. (See Stakeholders Spar in FERC Tx Incentives Docket.)
In general, those that stand to profit from the change support the policy, while those who would pay oppose it. The CPUC is intervening on behalf of California ratepayers, who could end up paying hundreds of millions of dollars unnecessarily, commissioners and staff members said.
“Staff have overarching concerns with FERC’s untenable rationale for now making these incentives far easier to obtain and far more lucrative for transmission owners,” CPUC lawyer Jonathan Knapp told the commission Thursday, paraphrasing a staff memorandum he co-wrote.
Because of “dramatically increased levels of investment in transmission infrastructure and widespread reduction in transmission congestion, these incentives are not needed, particularly in the CAISO’s control area,” he said.
‘Head Scratcher’
When it directed FERC to issue the incentives in 2005, Congress relied on projections that the incentives would lower costs for ratepayers as demand for electricity grew, Knapp said. That turned out to be wrong, he said. In CAISO, transmission charges have increased 300% since 2006, while demand has decreased 5%, he said.
FERC lacks data showing the incentives worked, and “everything points in the opposite direction,” he said.
That’s why the proposed changes don’t make sense, Knapp said.
“Most fundamentally, FERC now proposes to ignore the definition of an incentive — something that encourages a person to do something — but instead proposes to essentially award bonuses to transmission owners for developing projects that they would already have undertaken or to take actions that in some instances are required by state law,” the lawyer said.
One of the changes would remove the requirement that TOs must voluntarily participate in an ISO or RTO to receive the adders. State law requires investor-owned utilities to participate in CAISO, but under the proposed FERC changes, the IOUs would get the doubled adder for remaining in CAISO, Knapp said.
He cited FERC Commissioner Richard Glick’s dissent to the March 20 decision calling the proposed change “the biggest head scratcher.”
PUC Commissioner Clifford Rechtschaffen said that the proposed changes would give Pacific Gas and Electric $145 million a year for “just showing up.”
In two decisions in 2018 and 2020, FERC ruled that CAISO participation is voluntary and that PG&E and other IOUs deserve the return on equity incentives. FERC upheld its original 2018 ruling on March 17 on remand from the 9th U.S. Circuit Court of Appeals. (See FERC Rejects RTO Incentive Adder Rehearing.)
CPUC Commissioner Genevieve Shiroma said FERC ignored the 9th Circuit and decided to “double-down on the incentives … inexplicably.”
“Who’s paying for all of this? The customers are paying for all of this,” Shiroma said. “And especially during this time of high unemployment, the pandemic, it’s not going to go away soon.”
Meeting New York’s ambitious clean energy goal of having the first grid in the country to reach 100% emissions-free electricity will require an “astonishing” 80 GW of new generation by 2040, NYISO stakeholders heard Monday.
Brattle Group representatives presented the Installed Capacity/Market Issues Working Group their final analysis of the state’s evolution to a zero-emission power system.
The report included three “alternative scenarios” modeling operations and investment in scenarios of increasing electrification for the years 2024, 2030 and 2040, as stakeholders had requested when presented the base case modeling in May. (See NYISO Examines ‘Evolution’ to Zero Emissions.)
“This is a sweeping study of a complete transformation of the system over the next two decades,” Brattle’s Sam Newell said. “By 2030 the system would need about 35 GW of additional wind and solar to meet the 70% renewable goal, and 80 GW relative to today of new wind and solar by 2040 to get to zero carbon.”
Signed into law last July, New York’s Climate Leadership and Community Protection Act (CLCPA) mandates, among other targets, that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)
“That means adding about 4 GW per year of onshore wind, offshore wind and solar in some combination,” Newell said. “That’s an astonishing pace.”
As part of its “Grid in Transition” initiative, the ISO retained Brattle to simulate the resources that can meet state policy objectives and energy needs in order to inform planning for reliability and market design over the next two decades. (See N.Y. Looks at Grid Transition Modeling, Reliability.)
Three Scenarios
Brattle developed three scenarios to address a range of questions from NYISO and stakeholders, including: an existing technologies case; a increased flexibility case (with expanded interties to Hydro-Québec); and an expanded transmission case (with new lines southbound).
The study is modeling for a 20-year time horizon. Given the amount of uncertainty about what available technologies, costs, and state and market rules will be, the ISO and its stakeholders thought it was important to use alternative scenarios to get a sense of how much the results change under different assumptions, said Brattle Senior Associate Roger Lueken.
“One thing to stress is that there is a lot of uncertainty in the study both in terms of the setup and the results,” Lueken said. “Of course, there’s a lot more scenarios that we could look at, but these were the three that it sounded like were of most interest.”
The study compares each of the scenarios to the high electrification case and to the base case results, he said.
In addition to the CLCPA, a key public policy driving decarbonization of the grid is the Regional Greenhouse Gas Initiative, the Northeast regional cap-and-trade program that had an average 2019 price of $5.40/ton of carbon dioxide, which is expected to reach $12.60/ton by 2030.
The study also considers the zero-emissions credit (ZEC) program for payments to New York nuclear plants, which expires March 2029, and the Department of Environmental Conservation rule to reduce NOx emissions from peaking plants, whereby peakers built before 1986 will most likely retire instead of retrofitting to meet emissions requirements.
The existing technologies case for 2040 gives high-level insights into a large overbuild of renewables (+80 GW from current levels) and storage (+27 GW) to meet load in all hours, with large curtailments of 221 TWh, or 50% of projected generation.
The existing technologies case for 2040 gives high-level insights of a large overbuild of renewables (+80 GW) and storage (+27 GW) to meet load in all hours. | The Brattle Group
In addition, retirement of gas plants by 2040 causes unforced capacity reserve margins to fall below planning reserve margins, and load falls by 50 TWh without in-state renewable natural gas production.
“In the second case — increased flexibility — we model expanded interties to Hydro-Québec as being able to provide flexibility, and we model more flexible load on the system,” Lueken said.
Lueken said “there are many different ways load can be flexible,” but Brattle chose to focus on two.
“The first is controlled electric vehicle charging, so people with EVs can control at what time of day they charge,” he said. The second is controllable heating and air conditioning loads, with the study assuming that buildings are outfitted with smart thermostats or types of HVAC that allow occupants to vary their thermostat point in order to shift their load from hour to hour.
The increased flexibility case for 2040 gives high-level insights of increased HQ imports (+24 TWh net), zero-emission generation largely unchanged and increased flexible load capacity resulting in less storage capacity. | The Brattle Group
“The third case is an expanded transmission case where we model transmission along key corridors from upstate New York into downstate New York, and between Zone J [New York City] and Zone K [Long Island],” Lueken said.
The New York Public Service Commission in May authorized a study to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197). (See NYPSC Launches Grid Study, Extends Solar Funding.)
The third case is designed to show how the amount of transmission affects what types of resources are built and where they’re added.
Brattle made three specific updates to the scenario. The first update was increasing transmission from zones A through E (Western to Central New York), and to zones G, H and I (Central and Lower Hudson) by 2,000 MW, and more than doubled the base case transfer limit from 1,900 MW to 3,900 MW, Lueken said.
The expanded transmission case for 2040 shows upstate capacity grows, as increased transmission enables more capacity to be built in lower-cost areas. | The Brattle Group
“The second update was increasing transmission from zones G, H and I into the Zone J by 2,000 MW, upping the transfer limit in the base case from 3,900 MW to 5,900 MW. Both of those upgrades were unidirectional, so we only increased the flow limit in the downstate direction,” Lueken said.
The third update was applied bidirectionally, assuming that the transmission lines between zones J and K increase by 1,000 MW, so that an additional 1,000 MW can flow from J to K and vise-versa, he said.
In response to a question about assumed costs for the transmission buildout, Lueken said “we did not compare the cost of building the increased interties to Hydro-Québec to the benefits; we simply reasonably assumed that they occurred and checked what happens to the resulting resource mix. The same is true here — we don’t make assumptions about what these upgrades cost, and we don’t compare the benefits of these upgrades to some estimate of what they might cost.”
Merits a Closer Look
The study’s main point is that the projected renewable needs for 2030 are in line with the technical potential for renewables in New York, but projected needs for 2040 will possibly exceed that potential, Lueken said.
He reiterated his cautionary note about the uncertainty around what the actual limits are, especially the estimates from the Department of Public Service, the New York State Energy Research and Development Authority and the National Renewable Energy Laboratory.
“One thing that might be worth further study by the Iabs or by the state or someone is getting a better sense of what these limits really are, and how that might influence the types of resources that are built,” Lueken said. “This is most obvious looking at solar, where for the amount of potential the limits range from 7 GW to 50 GW to almost 1,000 GW.”
Newell wrapped up the presentation by emphasizing Lueken’s last point: “The one area for further study is how do these needs relate to resource potential, including how much offshore wind you can get without transmission being built to access whatever lease sites are developed.”
“In any case, we’re talking about massive amounts of intermittent resources that are difficult to rate properly in terms of capacity,” Newell said. “Their intermittency is accounted for in installed capacity reserves studies, but they’ve become such a big part of the system, it’s worth taking a closer look at how you look at multiple years of wind and solar data, and more robustly incorporate that into the analysis, and extend that to resource accreditation.”
FERC on Wednesday approved the purchase of the Mankato natural gas plant in Minnesota by a specially created subsidiary of Southwest Generation, despite concerns about the company’s links to a JPMorgan Chase investment fund (EC20-54).
Denver-based Southwest Generation Operating Co. formed subsidiary SWG Minnesota Holdings for the sole purpose of acquiring the 760-MW Mankato Energy Center for $680 million.
Through a series of parent company arrangements, JPMorgan’s Infrastructure Investment Fund (IIF) holds 100% of the voting securities of Southwest Generation Operating Co.’s parent company. IIF is controlled by three private owners using a slightly different company name. Those owners also own about 29 MW worth of small generating facilities in MISO.
Consumer interest group Public Citizen had questioned JPMorgan’s involvement with the sale, asking the commission to require the company to more clearly explain its involvement with its subsidiary investment fund.
“Determining IIF’s affiliation with JPMorgan Chase and Co. in the Mankato transaction is vital for establishing whether the Mankato transaction is in the public interest, as failing to address affiliation threatens harm to competition, rates and regulation,” Public Citizen said.
Mankato Energy Center | Southern Co.
But FERC said the new owners are affiliated with just 0.4% of the generation capacity in MISO, a “de minimis amount.” The commission declined to require SWG Minnesota Holdings to conduct an analysis to prove no harmful effects on competition.
The commission also said that “treating J.P. Morgan Investment as an affiliate of SWG Minnesota Holdings would not change the ultimate result of the commission’s analysis of the effects of the proposed transaction on competition, rates, regulation or cross-subsidization.”
Xcel Energy purchased Mankato from Southern Co. for $650 million in January. The quick turnaround will net the utility $30 million, two-thirds of which it promised will be earmarked for corporate giving and COVID-19 relief in its eight-state territory.
Mankato will continue to provide energy to Xcel through long-term contracts.
MISO’s Independent Market Monitor issued five new recommendations in its annual State of the Market report released Wednesday, focusing on the RTO’s management of flows across its seams, dynamic transmission line ratings and whether energy efficiency should be considered a capacity resource.
But IMM David Patton also used presentation time before the MISO Board of Directors’ Markets Committee to issue a warning on the deteriorating condition of the RTO’s reserve margins.
MISO Executive Director of Market Strategy and Design Scott Wright said the new recommendations this year concentrate on seams and efficient use of the transmission system. Three recommendations offer advice on how to manage flows between neighboring RTOs, where the Monitor suggests:
Using new testing criteria for defining market-to-market constraints. Patton said the rules for determining flowgates have not been overhauled since 2004 and could use an update that places more emphasis on how much available flow relief a non-monitoring RTO can provide.
Improving the relief request software used in market-to-market coordination. Patton said MISO’s current relief request software does not always request enough relief from the non-monitoring RTO because it doesn’t consider shadow price differences between the RTOs.
Clearing coordinated transaction scheduling transactions with PJM every five minutes based on the most recent five-minute prices, not forecasts. The Monitor said “persistent forecasting errors by MISO and PJM have likely hindered” use of coordinated transaction scheduling. Instead, Patton said the most recent five-minute prices are a more accurate forecast of the prices over the next five minutes.
Patton’s two other recommendations include MISO developing the capabilities to apply dynamic transmission line ratings from transmission owners and disqualifying all energy efficiency resources from the capacity auction.
Most MISO TOs don’t adjust line ratings to reflect ambient temperatures and wind speeds, Patton said. He said a “broad adoption” of ambient-adjusted ratings could have reduced congestion costs by $150 million in 2018 and 2019.
Patton also said if all TOs provided short-term emergency ratings, which tend to be about 10% higher than normal ratings, MISO might have saved as much as $114 million in congestion over the past two years.
“The ratings transmission owners provide tend to be overly conservative,” Patton said. “If you calculate how much we could save by rating transmission lines more efficiently, it would be something like $265 million.”
Further, Patton said more efficient line ratings on just the top 25 constraints could achieve two-thirds of that estimated savings alone.
“Hopefully over the next year, we’ll see some progress,” he said, adding that effectively managing congestion can save MISO more than developing a new, big-ticket market product.
Patton also said allowing energy efficiency resources to offer into the MISO Planning Resource Auction (PRA) makes little sense.
“Funneling an additional subsidy to pay for LED lightbulbs is an inefficiency,” Patton said, adding that capacity payments for energy efficiencies don’t make sense because entities with installed energy efficiency are already saving on retail bills.
He also said capacity payments for energy efficiency owners further offset the bills that contain, ironically, the cost of serving them, including energy, ancillary services, and capacity, transmission and distribution costs.
“When they purchase energy-efficient equipment, the electric bill savings include all of these elements. There’s just an array of problems,” Patton said of energy efficiency receiving funding through MISO’s capacity market. “The quantities are growing rapidly and in key tight locations like Michigan.”
Last year, Patton produced six new market recommendations as part of his 2018 report, among them clarifying the criteria for calling emergencies, procuring operating reserves on the Midwest-to-South regional transfer limit and lowering the generator shift factor cutoff for transmission constraints with limited relief. (See MISO Monitor Poses 6 New Market Recommendations.) MISO has yet to issue proposals on any of the 2018 recommendations, though it is working on new capacity accreditation requirements that could address two of the six recommendations. The RTO also discussed possible improvements to the logging and documenting of emergency procedures with the Monitor last year.
Markets Competitive, but Trouble Brewing
Patton also reported that offers into the MISO markets throughout 2019 were highly competitive.
“The prices were about as competitive as they could be. The MISO markets always performed very competitively,” Patton told board members.
Real-time prices for the year averaged just $26/MWh in the footprint, driven by cheap natural gas and a 2% decrease in average load, while a cooler year overall brought lower demand, he said.
By the IMM’s count, 3.3 GW of resources retired in MISO last year. Of those megawatts, almost 90% were coal generation. Patton said more than 4.5 GW of new capacity entered MISO over the same time, including nearly 2 GW of natural gas capacity in MISO South and more than 2 GW of less dependable nameplate wind capacity.
“Nuclear and coal resources are under a tremendous amount of pressure, mainly because gas prices are so low,” Patton said.
Patton predicted a continued gradual loss of coal resources in MISO, making the need for reliable capacity resources more pressing. He said the retirements make MISO’s possible rethink of its capacity resource accreditation even more crucial. Capacity accreditation must be doled out according to resource’s ability to serve capacity reliably, he said.
“It’s likely to be one of the most unpopular proposals among participants, since it’ll look like we’re taking capacity credits away. It’ll be a heavy lift because it’ll look hostile — or at least adverse to their interests — to participants,” Patton said.
“What’s striking about this [report] is the theme of a resource mix in transition,” Wright said.
The Monitor also reserved space in the report to decry the continued use of a vertical demand curve and advocate for a sloped demand curve in the PRA.
Save for a high zonal price in Lower Michigan in this year’s capacity auction, the PRA produces prices that are “close to zero and generally represent less than 2% of the revenue needed to support investment in new peaking resources,” Patton said. “These prices have really hammered the merchant generation and forces them into retirement … or selling capacity outside the footprint.”
Addressing its board earlier this month, MISO said there was a “lack of assurance that the existing resource adequacy construct will … promote participant investments that ensure sufficient resources are available to meet load in all time periods.”
According to MISO’s Tariff, the RTO’s leadership has 120 days, until Oct. 16, to make a public response to Patton’s recommendations.
MISO has temporarily backed off requiring load-serving entities to provide the location and capacity values of distributed energy resources for its planning models.
Planning Modeling Manager Amanda Schiro said the requirement for LSEs to provide counts of inverter-based DERs on distribution systems has been downgraded to a request for 2021.
Schiro said this year’s request is only intended to allow MISO to get a better handle on DER siting. She said the RTO is only in a “data-gathering mode” to possibly introduce future modeling improvements that better capture DERs.
MISO wants LSEs to provide more explicit DER estimates for transmission planning models by 2022.
DERs are registered in the capacity market but not represented in the RTO’s planning models, Schiro said. She said DER integration into reliability planning and operations and market systems will soon necessitate a modeling change.
Summer peak load continues to drop slightly every year, and DERs could play a role in that, Schiro said.
“We want to plan for the situation we’re going to find ourselves in,” she said.
For now, MISO needs more information to decide how to represent DER in modeling, Director of Planning Jeff Webb said.
“We’re trying to just get an understanding of what’s out there,” he said, agreeing with stakeholders that MISO must engage in more discussion with LSEs before it adopts a new approach for better estimating DER in planning models.
Some LSE representatives have expressed skepticism over MISO’s DER modeling goals.
WEC Energy Group’s Chris Plante said many LSEs already include in their forecasts any DERs they have insights into. He also said it might be impossible for MISO to locate all DERs.
“In some cases, it might not be practical to model some DERs because some might be behind the customers’ meter, and we have nothing to do with it,” Plante said.
MTEP Transfers Under Study
MISO has defined the transmission transfers it will study in its 2020 Transmission Expansion Plan (MTEP 20) to determine the system’s capability for handling various transfer scenarios.
The RTO is studying nine transfers under the MTEP 20 voltage stability analysis, which seeks to find future “soft spots” that might cause contingencies on the system. Three of the transfer scenarios will focus on transfer paths from Minnesota to areas in Wisconsin and Illinois, while two others focus on exports into the Downstream of Gypsy area near New Orleans from other Entergy territories.
The analysis also includes:
Minnesota and North Dakota’s exports into Manitoba Hydro territory;
Indiana and southern Michigan’s exports to the St. Louis area;
exports from Iowa into the MISO Central planning region of Indiana, Illinois, western Kentucky and eastern Missouri; and
MISO South to the West of the Atchafalaya Basin load pocket straddling Texas and Louisiana.
Additionally, MISO is studying five transfers under its NERC-required transfer study, used to determine the ability of the MISO system to handle possible power transfers across the footprint:
Ontario’s Independent Electricity System Operator to MISO’s East planning region;
MISO Central to the North planning regions in both directions; and
PJM’s Northern Illinois territory to the rest of its footprint east of Indiana.
Nearly all the transfers were chosen based on heavy historical usage; however, the PJM transfer was selected because of an influx of wind generation additions in the area by 2025.
At the end of last month, MTEP 20 contained 510 proposed projects at a combined $4.06 billion. (See Price Tag Rising for MTEP 20.) Those figures will remain fluid as MISO finalizes the transmission package over the next three months.
MTEP 20 is also on a shorter-than-usual timeline this year.
MISO announced earlier this year that it will revise the MTEP 20 schedule to allow the Board of Directors’ System Planning Committee an additional month to review the transmission package prior to the full board vote in early December. That means the PAC will review, then vote on, whether to recommend the draft MTEP 20 report about a month earlier than usual, in September instead of October. (See “MTEP 20 Schedule Change,” Northern Focus for MTEP 20.)
PAC Chair Cynthia Crane has said the truncated MTEP timeline caused “some consternation” among stakeholders. “As much as everyone wants to give the board extra time to review, it’s going to take a month out of the process to form the MTEP,” Crane reported to the MISO Steering Committee in February.
PJM’s load-side stakeholders were disappointed last month when they failed in their bid to give the RTO control over end-of-life (EOL) transmission planning.
But the joint stakeholders rebounded at the June 18 Members Committee meeting, recording a 69% win that culminated more than four years of battles with PJM’s Transmission Owner sector. The victory sets up a showdown at PJM Stakeholders Endorse End-of-Life Proposal.)
How did the joint stakeholders pull off their comeback, after falling short in votes in May? A review of voting records and interviews with more than a dozen stakeholders indicate it was the joint stakeholders’ gains among the Generation Owners and Other Suppliers sectors that turned the vote after days of intense lobbying by both sides.
“In all the time I’ve been involved in the stakeholder process, I’ve never seen so much outreach on an issue,” said Ed Tatum, vice president of transmission for American Municipal Power, which led the joint proposal with Old Dominion Electric Cooperative (ODEC), the PJM Industrial Customer Coalition (ICC) and LS Power. “That includes PJM and the [TOs] as well as our group.”
End of Life Task Force
AMP, ODEC and the PJM ICC have been fighting to increase the transparency of the EOL process since at least February 2016, when they won approval of a senior task force to consider development of RTO-wide criteria for EOL transmission facilities. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)
Some TOs have established criteria for such projects under FERC Form 715, while others consider them supplemental projects — improvements not required for compliance with PJM system reliability, operational performance or economic criteria. The RTO does not approve supplemental projects but does study them to ensure they won’t harm reliability.
PJM says TOs’ supplemental projects totaled almost $3.4 billion in 2019, more than double the less than $1.5 billion in regionally planned baseline projects. It was the fifth year out of the last six in which the costs of supplemental projects exceeded those of baseline projects.
Load interests, who noted that much of the grid is 30 to 50 years old and in need of replacement, say EOL projects should be planned regionally by PJM to optimize and control spending. LS Power would like to see the projects eligible for competitive bidding under Order 1000.
The group ended its work five months after FERC approved the TOs’ request to move language governing supplemental projects from PJM’s Operating Agreement to Tariff Attachment M-3, while requiring changes to improve transparency. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
In January 2019, AMP and ODEC won 69% support of the Markets and Reliability Committee for changes to Manual 14B that would give PJM more control of supplemental projects. PJM officials refused to implement the changes, however, saying they would conflict with FERC rulings. After months of negotiations, AMP and LS Power reached agreement with the TOs on manual language to prevent TOs from proposing supplemental projects designed to meet regional needs. (See PJM TOs Sign off on Supplemental Project Deal.)
Last fall, Tatum won approval of a new issue charge that resulted in five special MRC meetings to consider “Transparency and End of Life Planning” — discussions that resulted in the joint stakeholders’ EOL proposal and PJM’s alternative.
The joint stakeholders’ proposal would amend the OA to require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date. The projects would be included in five-year planning models and potentially opened to competitive bidding.
The Transmission Owners Agreement-Administrative Committee (TOA-AC) laid out its own EOL proposal, which aligned with the position of PJM staff, in proposed amendments to Attachment M-3 (ER20-2046). It would require TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with Regional Transmission Expansion Plan reliability violations would be included in a competitive window seeking “the more efficient and cost-effective solution.”
The TOs say the proposal would increase transparency and improve planning coordination with PJM while honoring their rights and responsibilities over asset management. The joint stakeholders contend it would do little to improve transparency or change the status quo.
Element of Surprise
The TOs gave notice on May 7 that they were considering the M-3 amendments, starting a 30-day clock to accept comments before they could make the filing under Section 205 of the Federal Power Act. Their action forced the joint stakeholders to seek a vote at the May 28 MRC meeting — earlier than stakeholders had planned, Tatum said. “We felt like it might have been a little too soon, but we had to give it a run,” he said.
The stakeholders garnered 64% support for the proposal in a sector-weighted vote in the MRC, then 62% on a procedural vote to bring the matter before the Members Committee — both short of the two-thirds threshold required.
The stakeholders felt more confident heading into the June 18 vote, after addressing what they said was misinformation about their proposal.
One stakeholder said some members were concerned the proposal would “mess up” the interconnection queue. Others were told TOs “couldn’t replace a pole without going to the stakeholders.”
“There were a lot of things that were being said about our proposal that weren’t entirely accurate,” Tatum said. “We talked to a lot of folks to make sure they had an unbiased view of the facts and the focus.”
“It really did require a lot of listening on our part … to address the concerns” that caused the failed May vote, said Susan Bruce, who represents the PJM ICC. “You had to do old school get-out-the-vote discussions.”
“In the last four or five years, I can’t think of more grassroot-level voting calls than I received on this issue,” one stakeholder said. “I had folks on both sides reaching out to me. … There was almost none of that before the prior [May] vote.”
The joint stakeholders gained 21 supporters on June 18 among those absent in May and also won over one member that had abstained. All told, 30 more members voted in June than in May (from 128 to 158), an increase of almost one-quarter.
The joint stakeholders lost six “yes” votes from May: four to abstentions and two to absences. But none of the original “yes” votes joined the TOs in opposition. Meanwhile, four “no” votes switched to “yes,” and four other “no” votes abstained.
The stakeholders made big gains among the Generation Owners, picking up six votes to rise from 56.5% of the sector (13 of 23) to 82.6% (19 of 23). Among members of the PJM Power Providers, voting affiliates for seven supported the proposal while three members abstained, including two, Advanced Power (voting as Carroll County Energy) and Talen Energy, which had voted “no” in May.
Vistra Energy (voting as Dynegy Marketing and Trade), Eastern Generation and Wheelabrator Falls, which had voted “no” in May, flipped to the “yes” column. The stakeholders also won backing from five generators that hadn’t voted in May: Cape May County Municipal Utilities Authority, CPV Power Holdings, Pixelle Specialty Solutions, Tenaska Power Services and NRG Power Marketing.
NRG Energy “supports using competition to control transmission costs in PJM and voted accordingly today with consumer interests and others at the RTO’s Members Committee,” Travis Kavulla, vice president of regulation for NRG, tweeted after the vote.
By one count, the RTO’s renewable generators split with six “yes” votes, three “no” votes and six abstentions. “What happened was the competitive generators all lined up behind the proposal, while the renewable crowd kind of sat on the sideline,” one stakeholder involved said.
Financial Traders Side with TOs
The stakeholders also peeled off enough Other Suppliers to squeak out a majority in the sector, rising from 40% in May (14 of 35) to 51% (26 of 51).
They added 12 “yes” votes — including Conoco Phillips, BP Energy and NextEra Energy Marketing, which had abstained or not voted in May, and Direct Energy, which switched from “no” to “yes.” The TOs were able to add only four “no” votes.
Sixteen of 21 financial traders in the OS sector opposed the joint stakeholders, with two voting “yes” and three abstentions. Eleven of the companies that voted against the stakeholders are represented by attorney Ruta Skučas of Pierce Atwood. | Pierce Atwood
The joint stakeholders would have cleared the two-thirds threshold at the May MRC meeting had they been able to flip four OS votes. RTO Insider reported previously that it was a bloc of financial traders that turned the sector against the stakeholders’ proposal in May. (See “Financial Traders Joined TOs in Opposition,” PJM TOs Outline End-of-life Tariff Amendments.)
Sixteen of 21 financial traders in the OS sector opposed the joint stakeholders, with two voting “yes” and three abstentions. Ten of the companies that voted against the stakeholders are represented by attorney Ruta Skučas of Pierce Atwood.
Several stakeholders noted that financial traders have been at odds with load interests, who have questioned whether the traders bring value to PJM markets.
In 2017, the Financial Marketers Coalition, led by Skučas, vigorously opposed a rule change supported by the PJM ICC and Electric Distributor sector that reduced bidding locations for increment offers, decrement bids and up-to-congestion transactions by almost 90%. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
In May 2019, the Organization of PJM States Inc. (OPSI) pressed PJM to act on a recommendation from the independent consultants’ report on the GreenHat Energy default that the RTO conduct a general review of the financial transmission rights market and consider potential reforms. The RTO announced last month it will hire a consultant to help it consider whether the FTR and auction revenue rights markets should be changed to ensure more of the benefits go to load-serving entities rather than financial traders. (See PJM ARR/FTR Review Could Pit LSEs vs. Financial Traders.)
With that review looming, one stakeholder speculated that the financial traders were engaged in vote trading with TOs. “That’s the only conclusion I can come to,” the stakeholder said. After the May vote, the stakeholder added, “there was a huge get-out-the-vote effort in the Other Suppliers sector to counter the financial traders.”
Skučas declined to discuss her clients’ reason for their votes, saying, “I am also concerned and disheartened that a stakeholder could not reach the conclusion that a fellow stakeholder group was substantively weighing disputed issues and reaching a position that differed from their own.”
As they had been in May, the Electric Distributor and End-Use Customer sectors were almost unanimous in supporting the joint stakeholders in June. The End-Use Customers sector added two “yes” votes in the June vote (from 17 to 19), remaining unanimous.
Consumer advocates from D.C. and nine of PJM’s 13 states — Delaware, Indiana, Maryland, New Jersey, Kentucky, Pennsylvania, North Carolina, West Virginia and Ohio — supported the proposal. Representatives for Virginia, Illinois, Michigan and Tennessee did not vote.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said it is difficult to get participation from all CAPS members for a variety of reasons; some states need more time to obtain voting authority.
Although OPSI took no position on the vote, staff for the New Jersey Board of Public Utilities and the Kentucky Public Service Commission spoke in favor of the proposal at the June MC meeting.
The EOL issue is particularly important for New Jersey, as Public Service Electric and Gas has led all PJM TOs since 2005 in spending on supplemental transmission projects. PSE&G spent $10.3 billion on supplemental projects between 2005 and 2019. Only one other TO, American Electric Power ($7.96 billion), spent more than $4 billion. PSE&G spent more than $5 million on supplemental projects per transmission line circuit mile over the period. Second-ranked Baltimore Gas and Electric spent less than $1.5 million per mile.
Asked to explain the discrepancy, a PSE&G spokesman declined to comment, saying only “we’ll pass.”
PSEG has led all PJM transmission owners since 2005 in spending on supplemental transmission projects, which include end-of-life facilities and are excluded from competition. | PJM
Public Power
The Electric Distributor sector was unchanged at 96.6% in the June vote, with support from all but one of the 29 voting.
All but two of the 21 members of the PJM Public Power Coalition represented by Carl Johnson voted for the stakeholders’ proposal. (Most of the coalition is in the Electric Distributor sector; members that don’t have load in PJM are registered as Other Suppliers.) Similarly, all nine members of the Public Power Association of New Jersey (PPANJ) voted “yes.”
“For the most part, there was support among the public power entities to having PJM do a broader look at replacing facilities that reach their end of life,” said Johnson, a consultant for Customized Energy Solutions. “And there was interest in having FERC finally give us a clear determination” on whether its CAISO rulings apply to PJM, he added, saying stakeholders have made convincing arguments on both sides.
PJM has said its role is limited by the two FERC rulings, which concluded that equipment replacements that result in only incidental increases in system capacity are asset management decisions under TOs’ exclusive control, not planning matters subject to FERC Order 890. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
“For us, [transmission] is a very big component of our cost, particularly in the PSEG territory,” said Brian Vayda, executive director of the PPANJ. “Transmission is on the verge of overtaking the cost of the commodity on a per-megawatt basis.”
Vayda said his members, who serve 75,000 customers, are keenly aware of the importance of reliability and resilience. “But we’re very concerned about the escalating costs and the lack of transparency that has always been an issue with supplemental projects.”
Margin of Victory
Backers of the joint stakeholders’ proposal said they were gratified by the widespread support they received.
“The joint stakeholders put tremendous time and effort into educating stakeholders on the need to push PJM into a grid of the future approach that includes competition and a regional perspective,” Poulos said. “It was amazing to see stakeholders rally behind the proposal with only the transmission owners, financial traders and a handful of renewable interests voting against it. On a major issue like this, it is quite impressive to see a unified position from the vast majority of stakeholder interests.”
“The key takeaway for me is that a majority of every sector other than the TOs supported the joint stakeholder proposal,” ODEC’s Adrien Ford said. “That is powerful to me.”
“There were 94 companies that voted in support of this. That’s a lot of companies,” LS Power’s Sharon Segner said.
Tatum said the joint stakeholders are eager to have FERC opine on issues that have provoked disagreement among PJM members, including the applicability of the two CAISO orders and the PJM TOs’ rights under the OA, Tariff and Consolidated Transmission Owner Agreement (CTOA).
After the June 18 MC vote, AMP Transmission and ODEC filed a motion to have the TOs’ Attachment M-3 filing dismissed. They contend the TO’s 30-day notice was issued without a formal vote of the TOA-AC, as they say is required by the CTOA. As PJM TOs, AMPT and ODEC have seats on the committee.
Outgoing TOA-AC Chair Takis Laios, of AEP, had said a vote wasn’t necessary because a “supermajority” of the TOs had approached him and said they had the votes necessary for a Section 205 filing they wanted to take before stakeholders.
Tatum acknowledged that AMP and ODEC could not have blocked the TOA-AC from approving the Attachment M-3 changes. But had the TOs followed the CTOA rules, Tatum said, “we would have known this was coming.”
As in the May votes, the TOs were near unanimous in opposition to the joint stakeholders on June 18 (11 of 13 “no” votes in May to 12 of 14 “no” votes in June). The only defectors were two merchant transmission operators, Linden VFT and Neptune Regional Transmission System, who supported the joint stakeholders.
TO representatives did not respond to requests for comment for this story.
During debates before the MRC and MC, the TOs and PJM said the stakeholders’ OA changes violate the CTOA by attempting to give the RTO authority over asset management decisions, making it in the words of Exelon’s Robert Taylor “substantively and legally flawed.”
In a May 22 letter, 10 of the TOs said the joint stakeholders proposal is “not in the best interest of our customers and will impair system reliability and safety.”
PJM said the joint stakeholders’ proposal to amend the definition of supplemental projects and create a new category of EOL projects under the RTO’s planning authority “is beyond the scope of authority transferred to PJM under the CTOA.”
Alex Stern, director of RTO strategy for PSEG Services, told the MC on June 18 that the TOs spent six months trying to work with other stakeholders only to find “divide and a disconnect” in the stakeholder process. He said the OA changes will hinder, not facilitate, “the grid of the future.”
Tatum disagreed. “I honestly believe this is how [the PJM stakeholder process] is supposed to work. There’s nothing broken about this in any stretch of the imagination.”
He said he has been encouraged by PJM’s new CEO, Manu Asthana, who he said has shown a willingness to listen to other stakeholders. “The stakeholder process can work when PJM’s fingers are not on the scale,” he said.
Erik Heinle, of the D.C. Office of the People’s Counsel, said the transmission assets being replaced now were built under different business models — before retail choice, renewable generation, demand response and other innovations.
“We want to see more oversight by PJM. We want to see it fulfill its role as the regional transmission planner.
“PJM has been great about being a leader on the market side. They’ve been less good about bringing that leadership on transmission,” he said. “I am concerned that PJM is not always a neutral player.”
Asked to respond, PJM referred to General Counsel Chris O’Hara’s comments at the June 18 meeting — at which he said the RTO would file the OA changes with FERC although it disagrees with them — and the Board of Managers’ May 27 letter to the joint stakeholders defending PJM’s EOL proposal.
“These issues will be ultimately settled at the FERC,” said spokeswoman Susan Buehler.
