Energy Secretary Dan Brouillette has named Alexander Gates to head the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), according to an email from Brouillette obtained by E&E News.
He replaces Karen Evans, who has led the office since its creation in 2018.
Gates joins DOE from the National Security Agency, where he worked in intelligence analysis, cyber operations, cybersecurity, research and tool development. Gates also served at the department recently as the deputy director for cyber in its Office of Intelligence and Counterintelligence. In his email, Brouillette said Gates was chosen to strengthen the bond between the intelligence community and DOE.
Former Energy Secretary Rick Perry created the CESER office in September 2018 to pool the department’s cybersecurity resources and more effectively address online threats to energy infrastructure. Under Evans’ tenure, the office has helped coordinate responses by the Department of Homeland Security and states to manmade and natural disasters, including cyberattacks, electromagnetic pulses and geomagnetic disturbances.
In his email, Brouillette thanked Evans for her leadership on issues such as expanding the department’s data sharing efforts and overseeing responders following Puerto Rico’s earthquake this year. At the National Association of Regulatory Utility Commissioners’ Winter Policy Summit earlier this month, Evans praised states for stepping up their cybersecurity efforts, noting increased state participation in last year’s GridEx V. (See “DOE Praises State Cyber Efforts,” Cybersecurity, Resilience Talks Highlight NARUC Meeting.)
Before leading CESER, Evans was the national director of the U.S. Cyber Challenge, a program intended to promote cybersecurity talents. During the George W. Bush administration, she served in the Office of Management and Budget and later as chief information officer for DOE. Evans also worked with President-elect Donald Trump’s transition team preparing staff to take over OMB. Evans’ future plans have not been disclosed.
Burned by the GreenHat Energy default, PJM stakeholders appear to favor the RTO’s efforts to improve its risk evaluations of market participants. But some of the RTO’s proposed new procedures may face challenges before FERC.
During a daylong “page turn” of proposed Tariff and Operating Agreement revisions Wednesday, several stakeholders complained some of PJM’s proposed definitions are overly broad and said it seeks excessive authority to respond to credit risks.
The special meeting of the Markets and Reliability Committee covered language to implement rule changes approved by the Financial Risk Mitigation Senior Task Force (FRMSTF) in December. The RTO wants to bring the language to a vote of the MRC and Members Committee on March 26.
When task force members were asked whether they prefer changing the rules, all but four of 157 voters opposed the status quo (97%). But the proposed changes were approved on a more modest 101-57 vote (64%).
Wednesday’s session was an often tedious, occasionally fractious walkthrough of more than 100 pages of language changes in three sections of the OA and four sections of the Tariff.
Sparks flew early in the meeting when PJM officials refused to commit to accepting additional written comments, saying they wanted the meeting to be a “working session” to get stakeholders’ feedback.
“It’s very hard for us to provide comments on the fly,” said Noha Sidhom, of TPC Energy Fund, explaining that stakeholders might need to consult with their companies’ lawyers before taking a position. [Editor’s Note: Given an opportunity to review her quote per Manual 34, Sidhom said it was inaccurate but declined to say what was incorrect.]
“For PJM not to be upfront and not consider written comments, you’re setting yourself up for further delay and protests at FERC,” said economist Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy. “It just leaves us feeling powerless.”
“That’s not my aim at all,” responded PJM facilitator Dave Anders. “I’m calling an audible. Let’s say we’ll accept written comments.”
But PJM Chief Risk Officer Nigeria Poole Bloczynski wasn’t willing to commit, citing concerns that some comments may be company-specific. “We haven’t said ‘no,’” she said, saying the decision on written comments would be made at the end of the session. “We want to make sure everyone hears the same thing.”
Sotkiewicz acknowledged Bloczynski’s concerns. “We’re not trying to have a one-on-one with PJM” through written comments, he said. But he said “from a due process standpoint, [rejecting written comments] doesn’t sound good. We can avoid a lot of that dust-up at the commission.”
PJM ended the meeting saying it would accept proposed changes to the language through Friday.
Facilitator Jen Tribulski said the proposed changes should be limited to changing terms “that you can’t live with” and not repeating issues raised during Wednesday’s session. “We would hope at this point that there’s not going to be a ton of redlines.”
“We want to reiterate: No comments,” Bloczynski said. “We’re looking for actual redlines.”
The MRC will hold another special session March 13, at which PJM staff will review changes made in response to the redlines or oral feedback.
‘Unreasonable Credit Risk’
There was no shortage of oral comments during the meeting, including frequent debate over whether the language was overly prescriptive or too vague.
Sotkiewicz complained that the rules would give PJM too much discretion to address what the rules call an “unreasonable credit risk,” noting that the term is undefined in the Tariff.
“There’s just too much latitude given to PJM to make calls on particular market participants,” he said. “It’s totally undefined and totally open to interpretation.”
Attorney Steve Huntoon, representing H-P Energy Resources, said PJM’s proposed changes to the term “market participant” could subject transmission customers and individual generators to burdensome reporting requirements.
He said stakeholders should vote against any change in the definition.
Anders responded by asking members to avoid advocacy over the coming vote. “We’re trying to work this out [collaboratively],” he said. “We’re trying to get it over the finish line so everyone can vote yes.”
At the end of the meeting, Tribulski promised PJM would address concerns that the term could apply to transmission customers. “We definitely heard the feedback,” she said. “So, we will tighten that up.”
‘Key Personnel’
PJM also received pushback on its plan to review whether an applicant to trade in PJM markets has “principal or key personnel in common” with a former member that has defaulted in PJM or other RTO/ISO markets.
Bob O’Connell of Panda Power Funds asked PJM to delete the term “key personnel,” saying if an individual is not an officer, “they’re not a key person.”
PJM attorney Jacqui Hugee disagreed, citing PJM’s experience with GreenHat, whose two principals had come to FERC’s attention for their roles in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012. (See Doubling Down —with Other People’s Money.)
“If they go somewhere else and they’re not the principal of the company … I’d want to know that. … We want to know about these bad actors.”
O’Connell said he understood Hugee’s concern but worried about how applicants would meet the requirement. “Do I have to submit my full roster of employees?” he asked. “The issue is not the concept. The issue is the application.”
Sotkiewicz said PJM would be exceeding its authority by performing “ex ante enforcement.”
PJM attorney Steve Pincus said the RTO is using FERC guidance and trying to be practical: “It’s not productive to try to define every particular scenario,” he said.
Strategy Changes
Joe Wadsworth of Vitol challenged a requirement that market participants notify PJM of “material changes to [the company’s] business strategy.”
“I don’t see how that informs PJM on anything about the financial strength of an entity,” Wadsworth said. “It’s an overreach. At the end of the day, it’s the money. Do you have the money to support your position?”
Bloczynski said if a long-time financial transmission rights trader suddenly stops trading, “that’s noticeable. … We’re going to ask questions.
“Or you’ve acquired a new business … and will be participating in a different way,” she continued. “That’s something we’re going to want to know about.”
It’s okay for PJM to ask questions, responded Robert Viola, director of legal and compliance for Vitol. “The way this is written, if we don’t [disclose] it, we’re in breach of the Tariff.”
Anders said PJM will seek to address the concerns. “That sounds like a hot button for you,” he said.
The proposed rules include a table showing how PJM will determine a participant’s unsecured credit allowance based on parameters including the “internal credit score” assigned by the RTO. The credit score will be based on PJM’s evaluation of the companies’ profitability, liquidity and other measures.
Bloczynski said PJM would not make public its scoring model to avoid companies “manipulating their financials” to obtain a higher rating.
Jim Davis of Dominion Energy said PJM should rely on the ratings of external credit rating agencies where available, saying they are “very experienced” and “may have access to company personnel that PJM credit staff may not have access to.”
But Bloczynski said rating agencies’ gradings haven’t always been accurate, noting companies that were “rated investment grade and next day defaulted.”
Finding the Balance
Bloczynski also pushed back on some language changes, saying the existing terms — such as a reference to the “five most senior principals” — were added in response to earlier stakeholder requests for more detail.
She said PJM was seeking an appropriate balance. “We can be very prescriptive … and box ourselves in, or we can use some reasonable business practices, and that’s what we’re trying to do.”
The growth of distributed generation means the MISO grid will become increasingly fraught with planning challenges that require target responses, stakeholders heard Tuesday.
“We’re doing our best to adapt, and no one really knows what the future holds, but we can add more visibility into our planning processes,” MISO DER Program Director Kristin Swenson said during a joint workshop hosted by the RTO and the Organization of MISO States. The workshop was the latest in a series that the organizations have been hosting since 2017 to prepare for grid changes under widescale DER adoption. (See MISO Explores Changes to Accommodate DER.)
Swenson also said MISO is beginning to see improved coordination between transmission and distribution systems for planning purposes.
MISO contains about 4.5 GW of unregistered DERs in its footprint, according to an OMS survey completed last year. (See OMS: 4.5 GW of Unregistered DERs in MISO.) It also has about 16 GW in registered DERs participating in the market both in front of and behind the meter. For now, MISO’s definition of DER includes demand response and energy efficiency. RTO staff say its DER definition could change when FERC issues its own definition.
Iowa Utilities Board attorney David Schmitt said that a few MISO utilities with large penetrations of DERs in their territories have experienced backflow on the transmission system, though most have yet to experience any impacts.
| Alliant Energy
Swenson said the distribution system in some instances can provide a more attractive means of connecting to the grid for new, smaller generators than the MISO system, which is running out of capacity in the West region.
“We have folks who are frustrated with the MISO interconnection queue who turn to the distribution system. There is distribution capacity in some cases where there isn’t transmission capacity. … I can imagine that can provide a path to getting a project done that otherwise couldn’t be,” Swenson said.
DER experts said MISO should plan for an uneven adoption across the footprint, with some areas becoming hotspots of activity.
Stacy Van Zante, manager of delivery system planning for Alliant Energy, said her company’s Iowa subsidiary, Interstate Power and Light, contains about 204 MW of distributed generation, with 4,441 interconnections on the distribution system.
“In some areas, we don’t see a lot of distributed resources, but in other areas, what’s happening in Iowa is akin to California,” Van Zante said, describing neighborhood hotspots of solar adopters or projects on college campuses. “People are adopting at different rates.”
Planning for Every Hour
Van Zante said Alliant will examine the possible benefits of wind interconnections on the distribution system. If a distributed resource can benefit the surrounding system, the interconnection customer won’t bear the entire cost of the interconnection, she said.
She also noted Alliant has found that wind interconnections cause “wear and tear” on load tap changers on station transformers.
“We lived at the world of peaks, but that’s changing. There’s a lot of activity on the system,” Van Zante said, adding that Alliant is looking at the need for 8,760 hourlong load profiles for planning — one for each hour of the year.
“We want to avoid stranded investments,” she said.
Richard Mueller, DTE Energy’s manager of engineering technology, also agreed that planning is quickly evolving from peak loads.
“It’s changing the times we’re evaluating,” Mueller said.
John Schmall, of ERCOT’s Dynamic Studies Department, said the grid operator has tracked some of its DER influx by requiring distributed generators greater than 1 MW that plan to export energy into the distribution system to register with it.
However, he said ERCOT is still grappling with the challenges DERs can present to transmission planning, like accurate DER modeling and aggregation, and how to best represent unregistered DERs in planning and forecast their growth. He also said ERCOT is also studying DER impact on voltage recovery.
Schmall also agreed that peak times will become increasingly hard to predict.
“When you have a mix of solar and wind, and a diesel generator and energy storage, that’s something that will be a challenge in getting that information, to know when you charge and don’t charge. … There are big question marks that still need to be worked out,” Schmall said.
MISO currently makes DER penetration projections in the roughly 15-year future scenarios used in its annual Transmission Expansion Plan (MTEP), using estimates from Applied Energy Group, which is currently wrapping up updated DER forecasts for MTEP 20.
MISO will hold another DER workshop March 31 that will focus on DERs and how they could affect the RTO’s markets.
Consumers Energy on Monday announced it plans to achieve net-zero emissions by 2040, putting the utility on track to achieve that goal a decade earlier than most of its peers in the industry.
The announcement means the Michigan utility will aim to offset all carbon emissions created by the electricity it generates or purchases within two decades.
Consumers Energy CEO Patti Poppe in a Feb. 24 video released by the utility
In a release, CEO Patti Poppe admitted Consumers doesn’t have “all the answers yet” for reaching the goal but said it could counteract lingering emissions with “carbon sequestration, landfill methane capture or large-scale tree planting.”
Vice President of Public Affairs Roger Curtis said the move makes Consumers “the largest energy company in U.S. to plan net-zero this soon.”
“We have confidence in our ability to achieve that lofty ambition, though it’s about a decade earlier than most because of our Clean Energy Plan,” Poppe said in a video circulated by the utility. The Clean Energy Plan refers to the company’s 2019 integrated resource plan, which contains a goal to eventually meet 90% of Michigan’s energy needs with clean resources in addition to the new net-zero target. Consumers serves 6.7 million of the state’s almost 10 million residents.
“Consumers Energy is proud to take a stand for Michigan and for the planet. We are committed to take actions that eliminate our carbon footprint and do our part to combat climate change,” Poppe said. “Our Clean Energy Plan already is focused on protecting the planet, and our net-zero pledge takes that commitment to the next level.”
Consumers previously committed to an 80% reduction in carbon emissions from 2005 levels by 2040, a goal shared by Michigan’s other large utility, DTE Energy.
But the two companies now appear to be headed in different directions.
While DTE in 2018 announced it would strive for net-zero carbon emissions by 2050, its most recent IRP was recently sent back for major changes by the Michigan Public Service Commission, which ruled DTE hadn’t properly accounted for the benefits of renewable generation and relied too much on existing coal and natural gas generation. (See Michigan PSC Orders DTE to Redo IRP.)
Consumers, on the other hand, received approval in June for an IRP that proposed eliminating its coal fleet and reducing emissions from power plants by 90% by 2040. The company plans to retire the D.E. Karn plant in 2023 and idle Units 1 and 2 at its J.H. Campbell plant as early as 2025, replacing them with energy efficiency, solar and wind farms, and battery storage. The utility has already retired seven coal-fired power plants.
Fading Love for Coal
Poppe, who herself held positions at DTE until 2010, has been uncharacteristically candid for a utility CEO about Consumers’ obligation to cut emissions to mitigate the effects of climate change and her changing attitude toward coal-fired generation. She has repeatedly admitted she once dismissed climate predictions as alarmist.
“On that last day at every facility … it’s a heart-wrenching sort of day because of the effect and the change that’s happening to the people there,” Poppe said of attending coal plant closures on a Feb. 18 edition of the podcast “Illuminators,” which chronicles transformation and disruption in the energy industry.
“But you know, my co-workers are very proud of what they’ve done — as they should be — and very realistic and customer-centric to say that we care about our future generations and we care about making sure that we can, at the end of our days, look back and say that we did everything that we could to protect future generations from the effects of climate change.
“That just supersedes … in these tough decisions. But on the day of, you can bet, it’s a tough day for the people who are so deeply affected by the change,” Poppe said, who also admitted to once having a bumper sticker on her electric car that read, “I love coal.”
She told the Illuminators’ host that she’s since swapped it for a pink sticky note on her wall that reads, “I used to ‘heart’ coal.”
“I do think that coal had its time and place, and now we have the really great fortune that the economics have changed. We’ve got other clean energy technologies that can help us in ways that were not possible before. … We used to have this sucker’s choice: You can have clean energy — it’s just going to be expensive. Or, you can have the cheap and dirty stuff. Take your pick. We sold that story for a long time, and the reality is we don’t have to make that sucker’s choice anymore,” Poppe said.
Two MISO planning committees are set to begin discussions on what the RTO can do to break down walls between the annual Transmission Expansion Plan and network upgrade planning for the generation interconnection queue.
Speaking during a Coordinated Planning Process Task Team conference call Monday, MISO Senior Manager of Economic Planning Neil Shah revealed a list of transmission planning topics to be divided between the Planning Subcommittee and Planning Advisory Committee.
The task team has been compiling ways MISO could increase consistency between its MTEP and queue processes since January. Stakeholders have suggested that the RTO better align the timelines of MTEP and interconnection planning and ensure their respective studies draw on more similar data, including dispatch assumptions. The synchronization effort could have MISO approving more transmission projects by MTEP 21. (See MISO Seeks Ideas for Streamlined Tx Planning.)
Stakeholders also suggest MISO link its annual transmission planning process with network upgrade planning. Renewable proponents and some state regulators have repeatedly said the RTO is unfairly relying on interconnection customers to finance increasingly expensive new transmission capacity under the pretext of network upgrades and may be neglecting a responsibility to get major transmission projects approved in its transmission packages. Renewable advocates have questioned why interconnection studies show the need for expensive transmission upgrades when MTEP studies do not.
The PSC will review the study objectives, methodologies and modeling assumptions behind existing MISO reliability planning, economic planning, transmission service requests, and generator interconnection and retirement processes.
Once it compares the processes, the PSC may choose to make changes to certain methodologies and modeling assumptions to “ensure comparable treatment,” according to MISO.
The PAC will be tasked with the remainder of the possible planning overhaul, including devising a process for study coordination and data exchange to help MISO’s planning processes identify transmission needs “that are common to generator interconnection, reliability planning and economic planning process.”
The committee will also explore how it might design a multipurpose project designation for the Tariff that combines aspects of generation interconnection, baseline reliability and/or market efficiency projects.
Finally, the PAC will scrutinize the timing behind reliability planning, economic planning and generator interconnection processes to see how they can better align project evaluations to ensure that a recommended transmission upgrade receives the most precise project designation.
“If we coordinate and exchange information across the three planning processes, instead of us pursuing different, smaller upgrades in different processes, we have an opportunity to recommend a bigger, better project that can take care of multiple issues,” Shah said, referring to MTEP planning and necessary network upgrades identified in the generation interconnection queue.
“We could be laying the groundwork for how we restructure project categorization,” Wisconsin Public Service Commission economist Enrique Bacalao said.
Bacalao said the “natural evolution” of the PAC and PSC discussion could be that MISO reorganizes its planning processes so that “certain projects have more than one component to them” and are cost allocated accordingly.
Clean Grid Alliance’s Natalie McIntire asked why MISO’s list didn’t include the possibility of a consolidation of the generator interconnection and MTEP planning processes.
“We could potentially see that merging the processes could be helpful,” McIntire said.
That move could be on the table, Shah said, but MISO doesn’t want to prescribe any action at this point by specifically directing the PAC to consider it.
Shah said he will brief the issues list to more stakeholders at the PAC’s March 11 meeting. Multiple stakeholders thanked Shah for capturing the nuanced issues in the to-do list.
HARTFORD, Conn. — Lawmakers will this continue to focus this legislative session on efforts to transition the state to renewable energy and a carbon-neutral grid by 2040 while protecting ratepayers who already pay the highest electric bills in the continental U.S., industry participants heard Monday.
Leaders of the General Assembly’s Energy and Technology Committee spoke to about 100 members of the Connecticut Power and Energy Society (CPES) and the state’s bar association at the University of Connecticut School of Law. The meeting came a month after Connecticut regulators convened a public hearing to examine whether ISO-NE’s wholesale electricity markets are effective in serving the state’s clean energy objectives. (See Connecticut Weighs Pros, Cons of ISO-NE Markets.) Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett attended the discussion but did not comment.
“I think we’re going to try to continue and build on the successes that we had last year in our two major pieces of legislation, offshore wind and HB 5002,” said Rep. David Arconti (D), the committee’s co-chair, referring to a bill (HB 7156) authorizing the procurement of up to 2 GW of offshore wind and another authorizing procurement of energy derived from anaerobic digestion.
“A lot of our colleagues like to talk about energy in terms of what are we doing to address climate change, but when you get into the weeds of energy policy, it gets much more difficult to navigate those waters because there are so many other factors you have to consider,” Arconti said. “The top two obviously for me leading this committee are utility costs and the reliability of the grid.”
“One of the things we do as legislators is try to stand on the cutting edge of technology and bring forward those policies that are going to help Connecticut, but at the same time look out for our ratepayers,” said Rep. Charles Ferraro (R), one of the ranking members on the committee.
“We’re very focused on moving us to a more renewable future, and Gov. Ned Lamont’s initiative for a carbon-free grid is something we’re trying to turn into policy in a reasonable way, knowing that Connecticut already has the highest electric rates in the country,” said Sen. Norm Needleman (D), co-chair of the committee. “Advancing that agenda without breaking the backs of people and businesses who live here is the dancing on the head of a pin that we’re trying to do.”
As for offshore wind, Needleman said Connecticut is uniquely positioned with two deepwater ports, Bridgeport and New London, which do not have bridges separating the piers from the open water.
“Connecticut has the opportunity to be a leader and the location for a lot of offshore wind deployment,” Needleman said.
Tech and Tax Solutions
Sen. Paul Formica (R), the other ranking member, could not attend Monday’s discussion but was quoted in The Connecticut Examiner in January as favoring energy storage as a solution to the variability of solar and wind.
Formica said he is “working with leaders in the energy sector on the mechanics of a bill that will incentivize the creation of ‘pockets’ of megawatt storage along the transmission line, which could prevent blackouts during major weather events,” the Examiner reported.
Arconti said, “The goal of the bill is to bring the storage industry here to Connecticut, and storage is how we’re going to solve the intermittency issues of renewable energy.”
He said the legislation will contain “a very ambitious goal” of 1,000 MW of energy storage by 2030 “to mirror some of the programs we have with the offshore wind.” Lawmakers will also ask PURA to “leverage all the great work they’ve been doing on the grid modernization dockets, specifically the energy storage section,” he said.
Needleman brought up the need to tax commercial solar developers who he thinks enjoy an unfair property tax break on solar arrays between 1 and 5 MW, in many cases to the detriment of rural communities.
“I believe that the threshold at which we levy property tax is way too high, and a lot of those power plants are benefiting wealthier communities,” Needleman said.
He said he is working on legislation that would lower the tax threshold for commercial generation and would base the property tax only partly on project location in order to prevent developers from avoiding taxes.
Speaking about non-wires alternatives, microgrids and distributed energy resources, Needleman said he is “a big fan” of DER but thinks a microgrid powered by natural gas would conflict with public policy given the “big push to restrict the amount of natural gas we are using moving forward.”
“I have not been a huge fan of the state rushing headlong one way and now trying to do a gigantic reversal of policy that was put in place the last decade,” Needleman said. “It doesn’t make a lot of sense to set public policy with radical shifts. I think we need to be sensible. … We need realism, not just aspirational policy.”
Staff were invited to meet with FERC staff in October, which Lanford said was more about building bonds. “Senior staff had some questions for us, but not about particular issues,” he said.
Texas RE staff has also scheduled a conference call in March and another in-person meeting in May with FERC staffers.
FERC staff have “said we didn’t do anything wrong. … ‘We just never see you,’” Lanford said. “I guess they want to see us. That’s good, because we have a positive story to tell.”
Case in point: Violations in the region have dropped from 103 in 2016 to 94 in 2019. With 240 registered entities, the regional entity’s enforcement case load numbers 425 in the first quarter of 2020.
The organization has once again secured a contract as the Public Utility Commission’s Texas Reliability Monitor. Thanks to its work, the PUC issued $602,000 in penalties last year.
Texas RE’s footprint continues to grow. It certified Rayburn Country Electric Cooperative as a transmission operator (TOP) last year before the co-op integrated about 130 miles of transmission lines and 190 MW of load into the ERCOT balancing authority. Texas RE will conduct a similar TOP certification of Lubbock Power & Light, which plans to migrate 470 MW of its load from SPP to ERCOT by June 2021.
COO Jim Albright told the board that the RE is “in the best place we’ve been since I’ve been involved in this.”
“The relationships we’re building with NERC and other regions are the best they’ve been,” Albright said. “They’re in a really good place, and it’s showing.”
Committee Assignments Handed out
The Texas RE board approved placements on several of its committees:
Crystal Ashby, Milton Lee and Curt Brockmann were appointed to the 2020-21 Hearing Body, with Delores Etter as an alternate. The group, which meets only when a contested case hearing is requested, will select its chairman in the near future.
Independent Directors Ashby and Etter; affiliated Directors Liz Jones, with Oncor, and Brockmann, with CPS Energy; and Lanford will fill out the Director Compensation Committee, as dictated by the organization’s bylaws. Ashby agreed to serve as the committee’s chair.
Lee, Etter and Jones will serve on the 2020 Nominating Committee, with Lee chairing. The group will be responsible for finding a replacement for board Chair Fred Day, whose final term expires in December.
Ashby Begins Board Tenure
The board meeting marked Ashby’s first as a director. A Michigan undergraduate — “Go Blue!” she said — Ashby has 32 years of experience in compliance, ethics and risk assessment. Much of her career has been in the energy industry, including time in BP’s government affairs unit during the 2010 Deepwater Horizon oil spill.
Left to right: Texas PUC Chair DeAnn Walker, and Texas RE Directors Delores Etter, Fred Day, Milton Lee and Crystal Ashby during February’s board meeting. | Texas RE
“I plan to bring those traits and skill sets to the discussions the board has,” Ashby said.
She also serves as vice chair of The Executive Leadership Council, which is focused on increasing African-American representation in the C suite and on corporate boards. She earned her law degree from DePaul University.
Texas RE to Co-host GridSecCon 2020
A scheduling change to NERC’s annual GridSecCon and Electric Power Human Performance Improvement Symposiums means the Texas RE will be hosting one of these events every three years, beginning this fall, Albright said during the Member Representatives Committee meeting that preceded the board meeting.
The RE will co-host GridSecCon 2020 Oct. 20-23 in Houston with NERC’s Electricity Information Sharing and Analysis Center. “We’ll definitely be doing some heavy lifting,” Albright said.
The Western Electricity Coordinating Council will co-sponsor the Human Performance event Sept. 29 to Oct. 1 in Denver. With each of NERC’s six REs hosting the event, Texas RE’s turn should come up in 2023.
General Counsel Tammy Cooper told the MRC that Texas RE’s draft of a renegotiated regional delegated agreement will be considered by NERC in May.
A PJM task force considering the implementation of carbon pricing continued its education sessions Tuesday with an analysis on the impact of Virginia and Pennsylvania joining the Regional Greenhouse Gas Initiative (RGGI).
At its sixth meeting since its formation last summer, the Carbon Pricing Senior Task Force heard PJM officials walk through an analysis of the impact on emissions, prices and interregional trading of a “carbon price region” composed of up to five PJM states.
RGGI, which includes New York and the six New England states, currently has only three PJM states: Delaware, Maryland and New Jersey.
However, Virginia would join RGGI under the Clean Economy Act currently before the legislature.
Carbon sub-region (in green) including RGGI states and Pennsylvania and Virginia | PJM
Pennsylvania Gov. Tom Wolf issued an executive order in October directing state officials to develop a rulemaking by July 31 for joining RGGI, although his authority to do so has been challenged by the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
Although PJM officials have taken pains to emphasize that the analysis is theoretical and that the RTO is not proposing a carbon price, it has said a carbon price could provide a way for ensuring states’ clean energy policies do not distort wholesale markets. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.)
Analysis
PJM’s analysis compared the status quo with a region pricing carbon at a low-end reference of $6.87/short ton (the trigger price for the RGGI Emissions Containment Reserve) and a high-end reference of $14.88/short ton (the trigger for the RGGI Cost Containment Reserve). The analysis modeled the year 2023, the most recent planning case from the Regional Transmission Expansion Plan and market efficiency process.
It used PLEXOS software to simulate the commitment and dispatch of resources and the resulting market and emissions outcomes. Resources both internal and external to PJM were included in the optimization.
The analysis of adding Virginia without Pennsylvania found that at a price of $14.88/ton, emissions in the carbon zone would decrease from 52 million tons of CO2 for the year to 35 million tons. That reduction would be almost entirely offset by an increase in emissions in the rest of PJM, resulting in only a small reduction in total emissions from 278 million tons to 277 million. Meanwhile, NOx and SO2 emissions for the entire RTO would actually increase.
Shift in generation production by sub-region from adding one-way (1W) and two-way (2W) border adjustments | PJM
But the analysis also found that PJM would increase its net exports from about 37,000 GWh to more than 45,000 GWh, meaning that the PJM region would be providing substantially more power to its neighbors without increasing its emissions.
“If you look at emissions across the entire [Eastern] Interconnection outside of PJM, it’s not a wash,” said economist Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy. “But I think what that also tells us is that trying to cure leakage within PJM is a fool’s errand because it’s going to leak to outside of PJM. … It’s going to leak one balancing area away from PJM [where] PJM has no control.”
When including Pennsylvania in the carbon region, PJM-wide CO2 emissions would drop from 278 million tons to 259 million tons at a $14.88/ton price, with reductions of NOx and SO2 emissions as well. In this case — without any border adjustments to capture leakage — PJM’s net exports would drop substantially.
Leakage
PJM also found that a one-way border adjustment would have very little impact on generation in either the carbon region or the rest of the RTO at either the low- or high-end price for carbon. The modeling of the one-way adjustment — capturing transfers into the carbon region — was based on the 2013 draft final proposal for CAISO’s Energy Imbalance Market.
But the two-way border adjustment — covering transfers into and out of the carbon region — would result in a big increase in generation inside the carbon zone and a smaller decrease in generation outside of it, with a large increase in net generation exports.
“One way doesn’t do much,” PJM’s Anthony Giacomoni said.
Study methodology | PJM
PJM officials cautioned that their analysis did not consider state-specific approaches such as programs that reduce electricity demand or load-based greenhouse gas compliance obligations.
It also did not capture how higher power prices could affect power demand. “We can add a low-demand sensitivity” in the future, PJM’s Natalie Tacka said in response to a request for that data.
Next Steps
Task force facilitator Jennifer Tribulski said the group will meet next on March 27, when it will consider the legal, regulatory and technical considerations of a carbon pricing program.
Tribulski said the RTO will also issue a call for speakers for that meeting. “We want to hear about … what you expect to see; what you’d like to see in future meetings so we can really gauge where we are and what comes next.”
Consolidated Edison on Thursday reported 2019 net income of $1.34 billion ($4.09/share), down slightly from $1.38 billion ($4.43/share) the previous year.
Net income for the fourth quarter was $295 million ($0.89/share), compared to $331 million ($1.06/share) in 2018.
The company attributed the decline in income to depreciation and amortization expenses increasing 14.6% year-on-year, and taxes other than income taxes going up 8.4% in the same period.
“While meeting many challenges in 2019, Con Edison delivered solid financial results and remained focused on leading the way towards a cleaner energy future for our customers and the planet,” CEO John McAvoy said. “Our recently approved three-year rate plans are essential to helping New York state achieve its clean energy goals, as well as to continue providing safe and reliable service to our customers.”
The state’s Public Service Commission last month approved electric and gas rate plans for January 2020 through December 2022 reflecting an 8.8% return on equity, and the New Jersey Board of Public Utilities approved an electric rate increase, effective Feb. 1., of $12 million for Rockland Electric, reflecting a 9.5% ROE.
The PSC last month also issued an order directing energy efficiency targets and budgets for New York utilities, approving $2 billion statewide for EE programs, heat pump budgets and associated targets through 2025 to meet the goal of reducing electric use by 3% and gas use by 1.3% annually by 2025 (19-E-0065).
Con Ed’s DER meter, ConnectDER | Con Edison
In December, Con Ed completed a study of climate change vulnerability. Considering the increased risk of sea level rise, coastal storm surge, inland flooding from intense rainfall, hurricane-strength winds and extreme heat, the company estimates it might need to invest between $1.8 billion and $5.2 billion by 2050 on programs to adapt to impacts from climate change.
Con Ed is still extremely exposed to Pacific Gas and Electric’s bankruptcy through a large volume of power purchase agreements sold to the California utility. At year-end, Con Ed’s balance sheet included $819 million of net non-utility plant relating to PG&E projects, approximately $1 billion of intangible assets relating to PG&E PPAs, $282 million of additional projects that secure the related debt and approximately $1 billion of non-recourse related project debt. (See PG&E Reports $3.6 Billion Q4 Loss.)
Pursuant to the related project debt agreements, Con Ed reported distributions from the related projects to the Clean Energy Businesses have been suspended.
“Unless the lenders for the related project debt otherwise agree, the lenders may, upon written notice, declare principal and interest on the related project debt to be due and payable immediately and, if such amounts are not timely paid, foreclose on the related projects,” the company said.
FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) prompted outrage among some officials in the RTO’s 13-state footprint and shoulder shrugs from others (EL16-49, EL18-178).
Filings by officials in Delaware, Virginia, West Virginia and D.C. show they share some of the concerns that regulators from Illinois, Maryland, Pennsylvania, Ohio and New Jersey expressed last week in a webinar with RTO Insider. (See related story, PJM’s MOPR Quandary: Should States Stay or Should they Go?)
But regulators in Indiana, Tennessee, Kentucky, Michigan and North Carolina — which are only partly within the PJM footprint — say they expect little impact from the ruling. Here’s a summary of where regulators in the nine jurisdictions not represented in the webinar stand.
D.C.
The D.C. Public Service Commission sought rehearing or clarification on the MOPR’s impact on new renewables, new demand response and the district’s default service procurement program, which provides 28% of the district’s electricity, including 85% of residential customers’ usage.
It noted that Maryland and Delaware have similar procurement processes for their default customers.
The PSC said it is unclear if the commission intended the MOPR to apply to the default service procurements. Commissioner Richard Glick said in his dissent that the MOPR could apply to New Jersey’s similar default program, but the PSC noted that the order suggested such programs could be protected under the competitive market exemption or unit-specific exemption.
D.C. also is concerned that the order could make it more expensive for it to comply with district law requiring a 50% cut in greenhouse gas emissions by 2032 and reaching carbon neutrality by 2050.
PJM transmission zones | PJM
It said only 7% of PJM’s power comes from renewables, below the national average (17%) and the shares in MISO (15%), ISO-NE (18.8%) and ERCOT (21.5%).
Using the net cost of new entry (CONE) to set the price floor for renewables could leave PJM further behind, the PSC said. “Thus, we request that FERC consider exempting new renewable resources from the MOPR or treat such resources as an exception — using the net ACR [avoided-cost rate] as opposed to the net CONE for the price floor for new renewables.”
The district also raised concerns about the order’s directive that PJM average the last three years’ DR offers to determine the default offer price floor value for DR that has not previously cleared a capacity auction. A new DR program targeting water heating would have no history, it noted.
It said new and existing DR should have a zero floor price “due to the fact that demand response programs are producing negawatts, not kilowatts.”
“Inasmuch as customer participation in demand response programs is ‘voluntary’ and the programs produce benefits greater than their costs, we do not fully understand why demand response is considered as a subsidized resource. Furthermore, the demand response programs from [electric distribution companies], due to their proximity to load, offer significant reliability values and lead to reduced market power and reduced final price to consumers especially during scarcity hours.”
Delaware
The Delaware Division of the Public Advocate’s rehearing request sought a declaration that the MOPR does not apply to the Regional Greenhouse Gas Initiative, which includes Delaware, Maryland and New Jersey in PJM. Pennsylvania Gov. Tom Wolf is attempting to join also but is facing opposition from the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
The advocate expressed concern that the order appeared to limit the MOPR exemption for existing renewable resources based on the PJM Tariff’s definition of “intermittent resources,” which it said does not cover all renewable resources that have generated or received renewable energy credits (RECs) and solar RECs (SRECs).
“For example, Delaware’s [renewable portfolio standard] statute includes geothermal energy technologies, biomass generators, landfill gas generators and fuel cells as electricity generators that are eligible to produce RECs, SRECs or their equivalencies,” it said. “These resources are not intermittent.”
Virginia
The Virginia State Corporation Commission filed a brief rehearing request that referred back to its October 2018 comments in the docket, in which it called for continuing the self-supply exemption for vertically integrated utilities in regulated states. The order exempted existing self-supply resources but indicated new self-supply would be subject to MOPR. (See Is Self-supply Suppressing Prices?)
“Customers in vertically integrated states should not bear the risk of paying twice for capacity, because the states in which such customers reside have made no out-of-market payments to generators,” it said. “What the commission concluded [in 2013] remains true today: Utilities in regulated states have no incentive to attempt to artificially suppress capacity prices, and a properly configured self-supply exemption would fully address the intent of an expanded MOPR.”
West Virginia
West Virginia, which remains fully regulated, has one load-serving entity that meets its capacity obligation through PJM’s fixed resource requirement (FRR): American Electric Power’s Appalachian Power and Wheeling Power, which together serve a little over half of the state’s load. Appalachian also serves significant retail load in Virginia.
The remainder of the state’s load is served by FirstEnergy’s Monongahela Power, which owns or controls 3,580 MW of generation, and Potomac Edison, which owns no generation but is supplied by Mon Power.
Mon Power’s load is almost entirely in West Virginia, while three-quarters of Potomac Edison’s load is in Maryland. Mon Power bids its capacity into PJM and buys its requirements, and those for Potomac Edison’s West Virginia operations, from the PJM market.
“The commission is still reviewing the order, but it appears that the decision to grandfather existing regulated plants that have been selling capacity into the PJM capacity market means that there is no immediate MOPR-related effect on our RPM [Reliability Pricing Model] LSE,” said Susan Small, communications director for the Public Service Commission of West Virginia.
The ruling would not impact the current operating decisions of the AEP companies, but their “option to elect to switch to RPM is now compromised,” Small said.
“We are concerned that new or existing regulated power plants that have not been selling into the PJM capacity market in the past will be subject to the MOPR, a treatment that we believe is unreasonable and discriminatory. This will mean that future options for West Virginia capacity additions and existing FRR regulated plants may be limited.
“By regulating the bid price of only certain unfavored power supply, including regulated power supply, not only will our options regarding how to serve West Virginia load be limited, but the cost of RPM capacity will grow over time because of the discriminatory treatment of resources that are bidding at a price that is considered by some to be too low.”
Indiana
Indiana Michigan Power (I&M), a subsidiary of AEP, is the only investor-owned utility in Indiana operating in PJM and meets its capacity obligation through the FRR, said Stephanie Hodgin, deputy director of communications and media for the Indiana Utility Regulatory Commission.
“Indiana also has rural electric membership cooperatives and municipal electric utilities that may participate in PJM; however, the IURC does not have information on how FERC’s MOPR order may or may not affect them,” she added.
Tennessee
Only a small portion of the northeast corner of Tennessee is within PJM. It is served by AEP’s Appalachian and its affiliate Kingsport Power, according to Tim Schwarz, chief of the communications and external affairs division for the Tennessee Public Utility Commission.
AEP, which serves about 47,000 customers and does not generate any power in the state, is exempt from the MOPR because it uses FRR.
Kentucky
Four Kentucky utilities participate in PJM, including AEP’s Kentucky Power and Duke Energy Kentucky, which use the FRR, and Big Rivers Electric, which is an “other supplier” in PJM but participates in the market through MISO.
Only East Kentucky Electric Cooperative participates in PJM’s capacity market, according to Andrew Melnykovych, director of communications for the state’s Public Service Commission. In its request for rehearing, EKPC called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.
EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.” (See MOPR Ruling Threatens to Upend Self-supply Model.)
Michigan
The only Michigan utility in PJM is AEP’s I&M, which uses FRR.
“It’s a very minimal impact, if anything,” said Matt Helms, spokesman for the Michigan Public Service Commission.
North Carolina
Dominion North Carolina is the only FERC-jurisdictional utility regulated by the North Carolina Utilities Commission. Dominion, which serves about 120,000 customers in the state, uses FRR. Only about 5% of North Carolina’s load is in PJM.
