Xcel Energy and three other Colorado utilities decided to join CAISO’s Western Energy Imbalance Market instead of SPP’s Western Energy Imbalance Service in December because of projected economic benefits.
Those benefits could have been far greater, however, if the other former members of the Mountain West Transmission Group also had selected the EIM instead of the WEIS, a Brattle Group study found.
If all seven had joined the EIM, the benefits for Xcel and the three other utilities in its balancing authority area would be $17.34 million instead of $1.98 million per year, the study found.
“The benefits jump eight to nine times as high,” Jason Smith, senior manager of market operations for Xcel, told the EIM’s Regional Issues Forum on Wednesday. “There’s just a ton of transmission to optimize within that footprint.”
Smith gave the most detailed public explanation yet of the decision by Xcel’s Public Service Company of Colorado — together with Black Hills Colorado Electric, Colorado Springs Utilities and Platte River Power Authority — to join the EIM as soon as 2021. (See EIM Lands Xcel, 3 Other Colo. Utilities.)
Xcel’s BAA covers the greater Denver area and most of eastern Colorado. The utility alone serves about half the state’s load.
The three other one-time members of Mountain West — the Western Area Power Administration, Basin Electric Power Cooperative, and Tri-State Generation and Transmission Association — announced in September they would join SPP’s nascent WEIS, saying they thought it would be more cost-effective and collegial. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
SPP said in June it would start the WEIS to compete with CAISO’s fast-growing EIM. SPP’s move, and a new Colorado law requiring the Public Utilities Commission to examine market options, prompted Xcel to examine the costs and benefits of joining the imbalance markets, Smith said.
They hired Brattle, which found that even if all seven Colorado utilities joined the WEIS and not the EIM, the benefits to the four entities in Xcel’s BAA would add up to just $1.62 million per year — about one-tenth as much as if all seven joined CAISO’s imbalance market.
The EIM has provided nearly $862 million in benefits to participants since it began operating in 2014, mainly through cost savings and the use of surplus renewable energy, according to CAISO.
Asked if he thought the Brattle study might encourage the utilities that signed on with SPP to change their minds, Smith said he couldn’t speak for them but wouldn’t rule it out.
“In the future, things may change, but that’s just a guess on my part,” he said.
‘A Close Call’
Brattle projected the four Xcel BA entities would spend roughly $1.6 million in start-up costs to join the market and $450,000 in annual administrative charges, Smith said. The WEIS wouldn’t require any start-up costs, but administrative fees would run about $3.5 million per year because of the relatively small number of participating entities to share the market’s expenses over time, he said.
Only the three other former Mountain West participants have decided to join the WEIS so far. The EIM has nine active participants and 11 more scheduled to join by 2022, not including Xcel and the three other Colorado utilities.
Imbalance markets allow utilities to trade excess energy across BAs, often maximizing use of renewable energy such as wind and solar, and Xcel was the first large investor-owned utility to commit to becoming carbon-free by midcentury, a pledge it made in December 2018 partly in reaction to customer demands. The city of Boulder, served by Xcel, has been trying to buy its assets there to create a municipal utility. (See Xcel Pledges to Go 100% Carbon Free.)
Smith said the time zone difference between Colorado and California and the states’ different resources would complement each other well. Colorado’s solar power comes online an hour before California’s morning peak, and eastern Colorado’s ample wind energy continues after the sun sets on the West Coast during the evening peak.
The same synergy wasn’t there if Colorado sent electricity east and south into SPP’s footprint, he said.
“The geographic distance gave us an advantage quite a bit,” Smith said. “That just wasn’t there when you look at a north-to-south diversity overall.”
Colorado has more transmission connections to SPP. Connection rights to CAISO and the other EIM entities are limited but should be adequate, he said.
“It was a close call, but we’ve got just enough transmission to make it viable,” Smith said.
Buying or building more transfer capability should increase benefits, he told the Regional Issues Forum during its teleconference. (The planned in-person meeting in Phoenix was called off because of the COVID-19 coronavirus.)
The four utilities are working toward signing an implementation agreement with CAISO and don’t anticipate any roadblocks, he said.
Some 375 people registered for Friday’s virtual version of Raab Associates’ 165th New England Electricity Restructuring Roundtable, held exclusively online in response to the COVID-19 coronavirus pandemic.
Three of seven panelists appeared in person at the Boston law offices of Foley Hoag with moderator Jonathan Raab, while the others joined via video link.
Robert Ethier, ISO-NE | ISO-NE
Robert Ethier, ISO-NE vice president for system planning, stayed away from the venue under a new policy from the RTO, effective the previous day, for staff not to appear in person at any conference or stakeholder meeting through the end of April.
Later that day, Massachusetts Gov. Charlie Baker prohibited gatherings of more than 250 people in the state, which was already operating under a state of emergency.
The webinar focused on the evolution of the transmission system in a decarbonizing New England. Electrification of the transportation and building sectors will increase power consumption, and transmission will serve as the linchpin to the region’s transition to a low-carbon and carbon-free future, Raab said.
“As New England states are pursuing their economy-wide greenhouse gas-reduction goals and mandates, our transmission grid will need to grow substantially to facilitate the development of renewable energy resources as we decarbonize our electricity supply,” Raab said.
Following is some of what we heard.
Choice of Focus
Higher load, lower clean energy capacity factors and renewable curtailments mean New England will need more than 200 GW of capacity by midcentury, said Jürgen Weiss, a principal with The Brattle Group.
Jürgen Weiss, The Brattle Group | The Brattle Group
“We concluded that if you decarbonize the energy economy in the New England states, you can count on roughly doubling electric load by 2050,” Weiss said during his presentation.
Brattle’s analysis found that growth in electricity demand by midcentury will range from about 77% when policy is focused on energy efficiency, to 103% when it’s focused on electrification, to 136% when it’s focused on electrification and renewable fuels.
“If we use electricity to make renewable fuels, to make some carbon-neutral substitute for natural gas, those processes are actually more energy-intensive; they use more electricity per unit of energy delivered to the end use than direct electrification, so in that case, you might actually see significantly more than a doubling of electricity demand,” Weiss said.
Any resource scenario has important implications for the transmission and distribution system, he said. Brattle estimated a rough doubling of incremental annual national transmission investment, largely related to connecting renewable energy resources to the grid.
New England 2050 resource scenario | The Brattle Group
“Relative to the annual transmission investments that have been occurring over the last few years, which are somewhere between $10 billion and $15 billion a year [in the U.S.], we probably need to add about twice that amount over the coming decades. So $25 billion of incremental transmission investments to do several things,” Weiss said.
“First, the new transmission will interconnect a lot of resources that are not going to be sitting next to load like the current generation is,” he said. “Here in New England, that’s obviously a lot of offshore wind.”
New distribution infrastructure also will address “very different load profiles, and ultimately much higher peaks,” Weiss said.
Big Wind Overflow
Ethier agreed with Weiss’s analysis and said that changing use patterns are “probably going to require an entirely new way of looking at the transmission system.”
“The integration of renewables and storage may significantly change the transmission flows, and we’re already seeing that with lots of resources added to the distribution system, which will cause some of our distribution feeders to actually flow in the opposite direction,” Ethier said.
He outlined ISO-NE’s transmission planning process and noted its first-ever solicitation in December for competitive transmission solutions for reliability needs in the Boston area, which drew 36 proposals — both AC and HVDC — ranging from $49 million to $745 million. The RTO is evaluating proposals and will review results with the Planning Advisory Committee. (See ISO-NE Issues First Competitive Tx RFP.)
“There are two issues with the transmission system: There’s paying for it, and then there’s getting it built,” Ethier said. “Both of those are time-consuming, and both of those are things that, if the past is any guide, we’re going to have a hard time keeping up with the states’ goals [and] meeting their carbon-reduction targets.”
Left to right: Peter Shattuck, Anbaric; Jonathan Raab, Raab Associates; Jürgen Weiss, Brattle Group; and Robert Kump, Avangrid.
In addition, developers are proposing about 15 elective transmission upgrades (ETUs) to help deliver about 11,000 MW of clean energy to load centers in New England, he said.
“We’re seeing lines that are seeking to connect northern Maine; we see lines seeking to connect offshore wind to load centers in New England, and also lines for hydropower from Canada,” Ethier said. “In most cases, we see multiple versions of these things that would accomplish the same goals.”
The ETU proposals “are queued up now and waiting for an opportunity to sell their services and sell their project as part of some sort of clean energy procurement at the state level, and until then, they’ll just bide their time in our queue,” he said.
The largest public policy effect in the region these days is offshore wind, and studies have shown that the rate of spillage increases as the buildout increases, Ethier said.
The RTO last month presented its latest study results on integrating up to 8,000 MW of offshore wind into the regional grid, analysis requested by the New England States Committee on Electricity (NESCOE). (See “OSW Study: More the Better,” ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020.)
“Spillage is where we have excess generation in New England and we actually have to back down renewable resources,” he said. “At 8,000 MW we hit spillage in every month of the year, so we have to back down various economic resources to accommodate these renewables. To avoid that you either need to increase load in the region, shift load around, or add significant amounts of storage.”
Offshore Planning
Robert Kump, deputy CEO and president of Avangrid, said his company is working on both the Canadian hydropower side and offshore.
Robert Kump, Avangrid | Avangrid
Avangrid subsidiary Central Maine Power is nearing completion of permitting for its $950 million New England Clean Energy Connect (NECEC) project to carry 1,200 MW of power from Hydro-Québec to Massachusetts, he said.
“The latest approval was from the Maine Land Use Planning Commission, received in January,” Kump said. “We expect any day now to get a draft approval from the Maine [Department of Environmental Protection],” which in fact came later that day.
“The goal would be to have all of our permits completed by the summer, and to start construction in the third quarter with a year-end 2022 completion date,” Kump said. Four gigawatts of additional transmission is needed to balance variable resources, he said, citing a Massachusetts Institute of Technology study this year on the role of Canadian hydropower in decarbonizing the Northeast.
Peter Shattuck, Anbaric | Anbaric
Kump also presented data from Vineyard Wind, his company’s offshore wind joint venture with Copenhagen Infrastructure Partners, and called for increased state and federal coordination to reduce permitting and siting risks.
“The starting point for thinking about how we connect this brand new and significant resource to the grid is looking at where we can bring it ashore,” said Peter Shattuck, chief information officer of Anbaric Development Partners. “Overall, independent transmission can minimize interconnection costs, reduce marine cabling and enable offshore wind to scale.”
Shattuck presented an argument for networked HVDC offshore transmission that compared scenarios of planned and unplanned development, with the latter seeing energy losses of 8%, while a planned network had only 3% losses, with comparable reductions in environmental and fisheries impacts because of 49% fewer miles of cables needed.
Wholesale Market Design
The second panel focused on what wholesale market design should look like in a fully decarbonized regional grid.
MIT economist Paul Joskow discussed how wholesale markets will support the investment costs of new generation and storage technologies.
Paul Joskow, MIT | MIT
“The systems in place have worked least well in stressed conditions in terms of providing efficient price formation,” Joskow said. “There’s been a lot of discussion about resource adequacy and capacity compensation focused on adapting capacity markets in various ways to provide additional net revenues. I don’t think that the conventional capacity markets framework used in most RTOs is well-adapted to a system dominated by intermittent generation.”
Joskow’s observation that New England “is way behind the other states and regions in the smart meter or smart grid technology” prompted a question from Manuel Esquivel of the Boston Planning and Development Agency as to what municipalities could do to encourage the adoption of smart meters.
“Mandating real-time meters and other smart equipment, controllable sensing equipment, inverters that can do more; these are state public utility commission decisions,” Joskow said. “This is not some way-out thing. Philadelphia has 100% penetration of smart meters; Baltimore has 100% penetration.”
The most important thing is to get the real-time design correct, said professor William Hogan, of Harvard University’s John F. Kennedy School of Government.
“If not, you’ll create many new problems,” Hogan said.
(Clockwise) Abigail Krich, Boreas Renewables; Paul Joskow, MIT; and William Hogan, Harvard.
He highlighted that under scarcity pricing in ERCOT, high prices of $9,000/MWh last summer occurred at the right time and were not socialized through capacity market charges spread over all load. (See “Scarcity Pricing Likely Again in 2020,” Overheard at Infocast’s ERCOT Market Summit.)
Sue Coakley, executive director of Northeast Energy Efficiency Partnerships, asked what the market design would need in order to include carbon-free demand-side resources, especially energy efficiency.
“I have a long record of not being a big fan of capacity markets, so if you’re worried about this problem, the worst place to start would be the capacity markets,” Hogan said. “I would go much more towards the retail rate design side.”
Boreas Renewables President Abigail Krich agreed with Hogan, saying that ISO-NE’s current capacity market design “absolutely would not be sufficient” to decarbonize New England’s grid.
“Some other mechanism is needed to secure a new way of financing, whether it’s in the centrally run market by ISO-NE, or whether it’s some mechanism by the states, or hedging,” Krich said. “I think this is going to be an iterative process … and there is a lot of investment needed.”
Robert Stoddard of Berkeley Research Group asked if the states’ roles needed to fundamentally change: For example, does New England need to adopt mandatory retail choice, as in Texas?
“I actually think the Massachusetts attorney general has it right in pushing to eliminate retail choice at the residential customer level,” Krich said. “I think that experiment has not worked in Massachusetts so far. At a larger scale, there are customers who are able to make informed decisions.”
PJM’s Joint System Operations Subcommittee (SOS) will hold the first of its weekly meetings on how the COVID-19 coronavirus is impacting generation and transmission operators at 2 p.m. Thursday.
PJM’s Paul McGlynn announced plans for the meeting at last week’s Operating Committee meeting. (See “SOS to Meet Weekly on COVID-19 Impacts,” PJM Operating Committee Briefs: March 12, 2020.)
“I recognize that many of you are competitors in our markets … on a normal day-in-and-day-out basis,” McGlynn said Tuesday during a 30-minute conference call to prepare for Thursday’s session. “But our industry has a long tradition of working together to operate the grid reliably and … keep the lights on through some pretty challenging conditions. [The weekly calls are] to get us on the same page.”
The agenda for Thursday’s meeting includes discussions on PJM’s Pandemic Response Plan; transmission outage rescheduling; generation availability and maintenance outages; gas pipeline coordination; COVID-19 prevention best practices; and waivers that may be required due to impacts of the pandemic.
Senior Vice President of Operations Mike Bryson paraphrased testimony astronaut Frank Borman gave to Congress in a hearing on the Apollo 1 fire that killed three astronauts in 1967.
“The comment he made was, ‘The thing we were most guilty of is a failure of imagination,’” Bryson said. “The emphasis I really want to put on this is give us any of your ideas. … We need to be thinking outside the box.”
Stakeholders asked PJM to inform them of any contacts with state and federal officials and how the RTO would deal with minimum generation events caused by reduced loads from manufacturing shutdowns and office workers telecommuting.
“With the mild weather coming through right now and … this feeling almost like a weekend or a holiday, that is something we will keep looking at,” promised SOS Secretary Paul Dajewski.
Calpine’s David “Scarp” Scarpignato said generators may need “proactive action” from PJM if there are mandatory quarantines.
PJM control room | PJM
“If we’re unable to get our contractors there to do the major maintenance that has to occur in March and April, and you put it off … into June or July, then all the sudden you need this stuff done for the generators to perform during peak [demand], [and] you’re not going to have” sufficient generation, Scarp said. “It is really critical that our personnel and our contractors are considered essential personnel.”
PJM announced after the meeting that it was canceling the PJM System Operator Seminar scheduled in Columbus, Ohio, from March 31 to April 24.
Bryson said companies that have operators whose NERC or PJM certifications are at risk of lapsing should contact the RTO’s member training team. “We can try to work with you to try to get those [continuing education] hours,” he said. “Our first approach is to push the training to maintain certification. And then if we need to do something different, we’ll work with ReliabilityFirst and SERC [Reliability] and NERC to handle that.
The commission first decided the hotly contested case in August 2018 and reaffirmed its decision in July after the 9th U.S. Circuit Court of Appeals rebuked it and sent the matter back on remand. (See PG&E Deserves $30M ISO Adder, FERC Says.)
The two decisions left little doubt about FERC’s views on whether participation in CAISO is voluntary or mandatory for PG&E and other transmission owners.
FERC concluded in both instances that participation in CAISO is voluntary; that PG&E could unilaterally leave CAISO without permission from state regulators; and that the “RTO-participation incentive [adder] induces PG&E to remain a participating member of CAISO and is consistent with the directives of the Federal Power Act.” (See Can PG&E Quit CAISO? FERC Wants to Know.)
The California Public Utilities Commission and other parties sought a rehearing, contending FERC had cited irrelevant sections of state law and ignored court decisions regarding the scope of the CPUC’s authority. They also argued FERC had erroneously justified the grant of the incentive adder based on commission policy that participation in a transmission organization is voluntary, even if state law and regulations say it’s not.
“We are unpersuaded by these arguments,” FERC said in its latest ruling. The commission said it had interpreted the appropriate laws and legal precedents correctly and that it didn’t have to defer to the CPUC’s authority in the case.
The CPUC argued in its rehearing request that it must approve changes in operational control of utility assets, such as CAISO returning operational control of PG&E’s transmission lines to the utility. FERC said it didn’t need to address that argument because it was based on evidence presented for the first time on rehearing.
“Nonetheless, we disagree with California parties’ interpretation,” FERC said. California law “expressly provides for CPUC authority over ‘changes in control’ of a public utility, along with mergers and acquisition.” The specified code sections, FERC said, “are most reasonably interpreted to mean changes in ownership control of the entire utility enterprise, not the operational control of individual facilities.”
The state laws cited by the CPUC refer to “changes or transfers in proprietary interests or something similar, rather than applying to transfers of operational control where the transmission owner retained ownership over the transmission facilities,” as in the case of PG&E and CAISO, FERC said.
MISO said Monday that it will hold its quarterly Board Week via conference call only, canceling the New Orleans event as the COVID-19 coronavirus extends its reach.
The cancellation was announced in a joint letter from CEO John Bear and Board of Directors Chair Phyllis Currie. The two said the six committee meetings and full board meeting scheduled for March 24-26 will continue as planned, but in WebEx/dial-in format.
“At this point, the board and MISO senior management have concluded that it is prudent for us to take more aggressive steps to keep our employees and stakeholders safe and do our part to limit the spread of this virus,” Bear and Currie wrote. “We did not take this decision lightly. MISO’s Board of Directors views these meetings as extremely important aspects of the stakeholder process that provide valuable opportunities for engagement with our stakeholders. As we have monitored the situation overall, paying special attention to member and state travel policies, we have concluded that this is the right decision for the region.”
MISO also announced that all other stakeholder meetings will continue to take place via conference call through May 1. The RTO’s conference call-only policy originally applied to meetings held March 9-13. (See MISO Steps Up COVID-19 Response.)
MISO has hosted its spring quarterly Board Week in New Orleans uninterrupted since 2011, two years before Entergy joined the RTO and made the city part of the footprint.
The cancellation occurred less than one week before stakeholders and MISO staff were set to converge on the Westin Hotel in downtown New Orleans. The RTO apologized for the short notice, explaining that it tried to collect “as much input and direction as possible” before its decision.
Advisory Committee Chair Audrey Penner said she fully supported MISO’s decision “to protect its staff and stakeholders while the uncertainty over the COVID-19 situation continues to play out.” She pointed out that the committee has held meetings via conference call in the past.
“While they are a little trickier to manage, I don’t anticipate any issues next week that would prevent us from having a good discussion. Having said that, holding ‘policy-type’ discussions via conference call [isn’t] ideal, so we are limiting those types of discussions next week,” Penner said in an email to RTO Insider.
Penner said she will prepare a verbal report to the board as usual, this time covering the AC’s recent recommendation that the RTO create a new “affiliate” sector for hard-to-define members. (See MISO Advisory Committee OKs 11th Sector.)
Steering Committee Chair Tia Elliott canceled the March 25 meeting of her committee and said it will next meet in an April conference call.
Elliott, who also serves as vice chair of the Advisory Committee, said she had full confidence in MISO and Penner to navigate the AC meeting by conference call.
“No doubt it can be tricky at times, but there is a chance we have a glitch during an in-person meeting too,” Elliott said. “I would encourage stakeholders to be patient, kind, and show grace during these conference calls, and to each other, especially during this unprecedented time we are all living through together.”
The AC has more than 50 members and alternates; audiences regularly exceed 100 people at Board Week.
MISO promised more updates on COVID-19’s effect on its stakeholder process and echoed Elliott’s message of unity.
“In times such as these, it is essential that we all work together to deliver electricity reliability to serve our customers,” Bear and Currie said.
Retail-choice states wanting to reduce their reliance on RTO capacity markets need to improve how their retail markets handle resource procurement, according to a new study produced for the Wind Solar Alliance.
“When competitive retail states restructured, there was insufficient focus on designing the market structure to support long-term contracting,” said the study, authored by Rob Gramlich of Grid Strategies and Frank Lacey of Electric Advisors Consulting. “Expansion of renewable energy and issues with wholesale capacity markets now require a focus on the competitive retail entities’ incentive and ability to procure power.”
The report notes that at least five states — all of which have retail competition — have begun proceedings over the last year to consider leaving FERC-regulated capacity markets.
State retail market rules were graded for their impact on competitive retail energy providers’ incentive to invest in generation resources. | Wind Solar Alliance
“If states wish to rely less on capacity markets, they will need to make sure their retail markets are designed to handle resource procurement,” the study said. Yet among the 14 states with retail competition, only Texas clearly assigns responsibility for resource procurement to customers or their load-serving entities. “No entity in those [13 states] has both the incentive and ability to procure power, given the rules and structures currently in place,” Gramlich and Lacey say.
Of the 14 states with retail electric choice, only Texas clearly assigns responsibility for resource procurement to customers or their load-serving entities. | Wind Solar Alliance
The other 13 states have “hybrid” competitive retail structures with “a monopoly default service provider offering rates that are subsidized to varying degrees and some form of a free option for customers to move in and out of competitive service. This dynamic reduces the incentive for retailers to procure supply.”
Clean Energy Transformation
The study says the transition to a decarbonized economy will require a market structure with entities able and willing to sign long-term contracts because generation developers and lenders are reluctant to finance 20- to 40-year assets based on expected future hourly prices.
This is especially the case for renewables, which are capital-intensive, with no fuel expenses and minimal ongoing costs. “Prearranged contracts provide the certainty necessary to finance those capital costs at a reasonable rate before the investment is made,” said the authors, who also noted that increasing penetration of renewables with zero production costs can depress spot energy prices. “Contracts provide upfront revenue certainty for lenders prior to committing capital.”
The failure of most restructured states to assign responsibility for ensuring resource adequacy caused a “free-rider” problem, leaving supply “under-procured and underpaid,” the authors say. “That is one reason RTOs in those areas stepped into the resource adequacy role with mandatory capacity markets.”
Recommendations
The study includes a scorecard on state retail market rules and their impact on competitive retail energy providers’ incentive to invest in generation resources. Texas gets straight “A’s,” while New Jersey, Maryland and Pennsylvania score mostly “D’s” and “F’s”.
The report identifies several reforms the authors say would improve retail market operations:
Eliminate Subsidies for Default Service: Utilities typically do not include in default service rates the costs for billing systems, accounting services, call centers or other functions required to deliver default service, resulting in a subsidy the authors estimate to be about 1 to 2 cents/kWh. In Baltimore Gas and Electric’s 2019 rate case, for example, the cost of providing default service was estimated to be about $170 million, only $12.3 million of which BGE planned to allocate to default service customers. The remainder was recovered through BGE’s distribution rates, which are paid by all customers, including those choosing competitive suppliers.
Unbiased Initial Placement: Default service is really a “provider of first resort” in many states instead of the “provider of last resort” as it is sometimes referred, the authors say, noting that only about one-third of residential customers in the 13 states have chosen competitive suppliers. Retail electric providers’ (REPs) “ability to maintain their customer base is eroded where new customers or moving customers are automatically placed on utility default service,” the authors say. “If customers were compelled to choose a supplier when enrolled for new service, they would be empowered with many options, including the option to purchase renewable energy.”
No Free Option: Consumers in hybrid restructured states are free to return to default service at any time. “The option imposes costs on default service wholesale providers (they lose load when market prices decline because the default service price decline lags the market) and onto REPs and onto other entities that provide customer services. (REPs lose load to default service when market prices increase because the default service price increase lags the market.) The free option eliminates the incentive for REPs to procure power on a long-term basis on a customer’s behalf.”
Creditworthiness: High and enforceable creditworthiness standards are needed to ensure REPs can make the long-term resource commitments needed to serve their loads.
Utility Neutrality on Default Service: Utilities profiting from providing default service are likely to steer customers away from competitive suppliers, the authors say. In its latest distribution rate proceeding, it was estimated that BGE will earn $8.3 million annually above its approved distribution revenue requirement from providing default service. By contrast, Texas has eliminated utilities’ role as default service provider.
The report says the recommendations would “enable broader wholesale market improvements.”
“One key market design element that is not widely used yet but is important to ensure retail providers have the incentive to sign long-term contracts, as well as to provide appropriate long- and short-term incentives for efficient behavior, is to accurately price energy at times of scarcity,” the authors say. “In Texas, prices can rise to $9,000/MWh at these times, as they did in the summer of 2019. This feature along with the rest of the Texas structure appears to be working to achieve supply-demand balance.”
PJM’s Paul McGlynn told the Operating Committee on Thursday that the System Operations Subcommittee (SOS) will begin holding weekly conference calls later this month to discuss how the COVID-19 coronavirus is impacting generation and transmission operators locally “and the steps that we’re all taking to deal with the situation.”
“I think it will help us to share best practices,” McGlynn said.
PJM has canceled all business travel, restricted access to its buildings and limited stakeholder meetings to Webex through at least March 27. The RTO is encouraging staff to stay home if feeling ill and planned to hold a telecommuting exercise March 13 to test its remote capabilities.
Scott Heffentrager, PJM’s chief security officer, said there have been nine presumptive cases of COVID-19 in Montgomery County, Pa., where the RTO’s two control rooms are located. PJM is conducting regular sanitizing operations of the control rooms.
The RTO will announce a decision by April 3 on the status of its Annual Meeting, scheduled for May 4-5 in Chicago.
PJM canceled the first three weeks of its Operator Seminar, scheduled to begin in Baltimore on March 10, and will decide by this Tuesday if training set for Columbus, Ohio, will be held.
Senior Vice President of Operations Mike Bryson said companies should contact PJM’s training department if they are concerned about staffers unable to complete required training because of the cancellation.
Heffentrager said PJM has experienced an increase in “phishing attempts and other scams” related to the virus. NERC warned of the risk of virus-related phishing attempts in a Level 2 Alert it issued March 10.
The alert advised registered entities to maintain situational awareness, reinforce good personal hygiene practices, and review and update business continuity plans. It also advised of possible supply chain disruptions that could affect the availability of electronics, personal protective equipment and sanitation supplies.
Station Power Complaint Challenges FERC Jurisdiction
PJM Associate General Counsel Steve Pincus briefed members on a FERC complaint filed March 6 by Lawrenceburg, Ind., and the Indiana Municipal Power Agency against the RTO, American Electric Power Service Corp. and Lawrenceburg Power alleging that the commission does not have jurisdiction over station power and seeking to void the power self-supply monthly netting provisions of the RTO’s Tariff (EL20-30).
The city’s Lawrenceburg Municipal Utilities has an exclusive franchise for supplying electricity within city limits and says Lawrenceburg Power’s 1,096-MW combined cycle plant in the city must take station power service from the city because Indiana law does not allow it a choice of retail supplier. Lawrenceburg Power is owned by a joint venture of The Blackstone Group and ArcLight Capital Partners. The plant is interconnected with AEP transmission facilities under PJM’s operational control.
The complaint asks FERC to declare that supply station power is a retail sale over which the commission lacks jurisdiction and that PJM Tariff provisions providing a merchant seller the right to self-supply station power through monthly netting are void and unenforceable. The complainants say Lawrenceburg Power must take station power service under the retail rates and terms of state and local law.
“The reason we’re bringing this to your attention is the complaint may implicate other members,” Pincus said.
Comments and PJM’s answer are due March 30.
FERC approved the netting rules in 2001, saying station power can be supplied to a generating plant in three ways: on-site self-supply (from behind-the-meter generation); remote self-supply (from another generator owned by the same company); or third-party supply.
The city is relying on federal court rulings in 2010 and 2012 that electricity purchased from a third party for use at a generating plant is a retail sale subject to state jurisdiction.
Manual 3 Update Prompts Questions
Stakeholders voiced surprise and concern in response to a proposal to create a confidential appendix to Manual 3 (Transmission Operations), which details requirements for transmission outages and includes guidelines on thermal, voltage and stability limits.
PJM’s Lagy Mathew said the RTO plans to move section 5 of the manual — which contains operating procedures for specific areas of the system and is amended frequently to reflect topology changes — to a new Manual 3B (Transmission Operating Procedures). Because of its sensitivity, section 5 is only accessible to stakeholders with Critical Energy/Electric Infrastructure Information (CEII) clearance.
Mathew said the published version is not always current and that even members with CEII clearance don’t see changes until the semiannual update. PJM maintains a separate, internal-only version for system operators, he said.
PJM proposed that the new Manual 3B not go through the committee endorsement process when it is revised, although the RTO would review changes monthly at SOS meetings.
That would ensure that the operational procedures are current for PJM dispatchers and eliminate the need for the separate internal version, Mathew said.
Several stakeholders questioned the value of the proposed change. “Why do you need to do it?” one stakeholder asked. “You already have two versions.”
Adrien Ford of Old Dominion Electric Cooperative recalled “very contentious” discussions in the OC regarding “the whole gas contingency situation, and much of that was in the CEII version of Manual 3.”
“I’d urge PJM not to make a change until we’ve had a more fulsome discussion,” she added.
PJM’s Darlene Phillips said staff “underestimated the level of conversation and confusion that this might cause. We thought we were doing something that would simplify the process.”
She said staff will create a question-and-answer document to address stakeholders’ questions in time for the OC’s April meeting.
Generation Cold Weather Survey due April 1
PJM’s Vince Stefanowicz reminded generation operators that the RTO’s survey on minimum operating temperatures, which opened on eDART on Dec. 1, will close April 1. The survey was prompted by the joint NERC/FERC report on the MISO cold-weather event in January 2018.
MISO will allow stakeholders an additional month to file their opinions on the RTO’s draft 2021 transmission planning futures scenarios.
The three futures have undergone three sets of alterations as MISO evaluates and responds to stakeholder requests. (See MISO Outlines Electrifying Tx Planning Futures.) The RTO had hoped to finalize new scenarios in April.
Speaking during a Planning Advisory Committee conference call Wednesday, Planning Manager Tony Hunziker said MISO will now collect stakeholders’ written feedback through March 27 and hold more discussion at the PAC’s April meeting.
Future I — formerly Announced Plans — assumes an 85% probability that companies’ renewable growth and carbon-cutting goals will materialize and full certainty that states’ clean energy plans will come to pass. It also includes a 40% reduction in carbon emissions from 2005 levels by 2040.
Future II — previously Accelerated Fleet Change — assumes MISO members meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. Electric vehicle adoption stimulates demand, while residential and commercial electrification reaches 39% of its technical potential, representing a 30% energy growth footprint-wide by 2040.
Future III — Advanced Electrification — also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand because of residential and commercial electrification hitting 77% of its technical potential, representing a 60% energy growth. MISO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels.
From its last futures draft, MISO has eliminated the nearly 35% renewable generation minimum penetration by 2040 prediction in Future I. The RTO’s most aggressive renewable prediction in the MTEP 19 futures estimated that renewables would take a 36% share of the resource mix by 2035.
Consultant Kavita Maini said it didn’t appear MISO was preparing for the possibility of an economic slowdown and a subsequent postponement of the retirement of certain plants in an effort to keep investments and customer rates low. She said some utilities might not achieve the emissions reductions for which MISO is planning.
“I don’t think we want to plan for doomsday,” Minnesota Public Utilities Commission staff member Hwikwon Ham responded, noting that MISO plans for an average growth, not the troughs and booms of the economy.
“Regardless of your political leanings, I can guarantee there’s going to be at least one administration”, that changes party, MISO Planning Manager Tony Hunziker said.
The futures are set to guide the 2021 MISO Transmission Expansion Plan (MTEP 21). MISO will begin planning for MTEP 2022 in June.
The RTO has also scheduled an April 16 workshop to discuss resource siting for the MTEP 2021 futures.
PAC to Begin MTEP, Queue Synchronization
MISO members will soon decide whether to retire the Coordinated Planning Process Task Team (CPPTT), charged with compiling ideas for synchronizing the annual transmission expansion plan with interconnection project planning.
The CPPTT’s sole purpose was to review the MTEP and generation interconnection planning processes and identify ways the RTO could increase consistency and coordination across the two. The team forwarded its findings to the PAC and Planning Subcommittee. (See MISO Committees Tackle Queue, Tx Planning Disparities.)
MISO Senior Manager of Economic Planning Neil Shah said having created the list of issues, stakeholders could decide to retire the CPPTT if there are no additional assignments for the group.
Shah said once reliability, economic and interconnection queue planning processes are synched up, MISO could identify fewer and more cost-effective transmission projects.
“We can evaluate a single solution instead of three separate solutions using three different processes,” Shah said. “If the timing is not aligned, there isn’t much opportunity to share information and evaluate.”
Some stakeholders asked that MISO either draft a white paper or hold workshops before drafting solution ideas in the PAC.
Stakeholders will again discuss the issue at the April PAC meeting.
MISO is recommending that two substation bypass projects begin earlier than the MTEP 20 cycle allows, stakeholders heard.
The RTO received two expedited project review requests from Ameren in December to bypass the 345-kV Coffeen and Duck Creek substations in western Illinois. Ameren said the projects are necessary because Vistra Energy has retired the corresponding Coffeen and Duck Creek power plants, which used to be pseudo-tied into PJM.
MISO said the bypass projects will “eliminate the need for AC/DC station service at these stations since these services became inefficient due to the retirements.” The RTO also said it didn’t discover any reliability issues as a result of the projects.
Ameren said it will save about $1.5 million if it no longer has to provide AC/DC station service or oversee the operations and maintenance costs of the substations.
MISO said it will move both projects into Appendix A of MTEP 20 and authorized Ameren to begin construction.
SPP staff last week shared a draft congestion study with the Seams Steering Committee on the effect of MISO’s contract path to its southern footprint.
The study of the SPP day-ahead market’s external flows and solution costs analyzed whether regional directional transfers (RDTs) above the contract path capacity between MISO’s South and Midwest subregions created additional congestion or operating costs for SPP’s market. MISO is limited to 1,000 MW of contracted, firm capacity over the contract path as a result of a 2015 settlement agreement. (See SPP, MISO Reach Deal to End Transmission Dispute.)
The committee had asked staff to provide more information on the differences in the hourly redispatch level, with a look at the generation footprint broken out by state and legacy balancing authority. Staff’s limited study was inconclusive as to whether MISO’s above-capacity RDTs created a “pattern of financial harm.”
SSC Chair Jim Jacoby noted during the committee’s meeting Thursday that high north-to-south days would “probably” overstate the study’s results.
Staff will return to the committee for its April 2 conference call with a final version of the study. The SSC plans to endorse or accept the report at that time.
M2M Settlements Up to $72M in SPP’s Favor
SPP earned $1.81 million in market-to-market (M2M) settlements in January, the fourth straight month — and 43rd in 59 months — that the M2M process with MISO has settled in its favor.
| SPP
SPP has now incurred $72.14 million in M2M settlements from MISO since the two began the process in March 2015. The process provides a compensation mechanism when SPP or MISO have to redispatch transmission around congested flowgates.
Temporary and permanent flowgates on the RTOs’ seam were binding for 438 hours during January. Temporary flowgates accounted for 427 of the binding hours.
ISO-NE is wrapping up its Energy Security Improvements (ESI) initiative ahead of an April 15 filing deadline with FERC, stakeholders learned last week during a two-day meeting of the New England Power Pool Markets Committee (EL18-182).
The committee plans to vote on ESI at its March 24 meeting, and the NEPOOL Participants Committee plans to vote on the market design at its April 2 meeting.
The start of the second day’s proceedings was delayed by a brief discussion of teleconference protocol after ISO-NE announced that, in response to the spreading COVID-19 coronavirus, its staff will not participate in person at stakeholder meetings from March 12 to April 30.
Later on Wednesday, NEPOOL announced that “future NEPOOL meetings in March and April will be conducted via teleconference with webinar capabilities.”
Focus on Winter Benefits
Todd Schatzki of Analysis Group presented a draft impact analysis that shows that — in addition to expected reliability benefits — ESI can also improve efficiency and lower production costs under stressed market conditions when the increase in energy inventory reduces energy production from less efficient and higher-cost fuels.
The study of winter months demonstrates that changes in net revenues vary across resource types, although the direction of these impacts (i.e., whether net revenues increase or decrease) is generally the same across resource types within each case, given the nature of the stressed market conditions, Schatzki said.
Summary of change in total payments, Winter Central Case | Analysis Group
Much of the quantitative analysis focuses on impacts in winter months, partly because the ESI proposal aims to improve market efficiency by better aligning individual participant incentives with the region’s need for energy supplies during tight market conditions, according to the full draft report.
ESI would be expected to increase total payments by load to suppliers on a rising scale, with the increase being lowest during periods when stressed market conditions are uncommon or infrequent and highest when they are frequent, while the extended case shows a 2.5% decrease in such payments.
Multiple factors influence the impact, such as the frequency and duration of the stressed conditions, and the amount of incremental energy inventory incented by ESI, as the inventory can lower market prices, particularly during stressed market conditions, the presentation showed.
Stakeholder Amendments
Massachusetts Assistant Attorney General Christina Belew presented an amendment to remove replacement energy reserves (RER) from the ESI proposal. (See “ESI Methodology in Question,” NEPOOL Markets Committee Briefs: Jan. 14-15, 2020.)
“On a high level, we think that RER is both unnecessary to successfully implement FERC’s fuel security requirements, and we think it is not required to be priced for compliance with NERC or [Northeast Power Coordinating Council] standards,” said Belew’s colleague in the Massachusetts attorney general’s office, Ben Griffiths, an energy analyst for regional and federal affairs.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
The Massachusetts attorney general’s office argues that reserve deficiencies are uncommon, so the need for reserve restoration production is low. | ISO-NE
The RTO’s impact analysis has not demonstrated that RER would actually improve system reliability, he said.
RER has a much weaker link to fuel security, the reason for the market initiative, than either generation contingency reserves (GCR) or energy imbalance reserves (EIR) products, Griffiths said.
“While removing RER reduces some of the ISO’s desired incentives, it seems that removing [RER] will save $50 [million] to $142 million per year, depending on how you combine the different winter and summer seasons,” Griffiths said. “And in doing so it doesn’t disrupt the rest of the core ESI design — the GCR and EIR components, and the self-disciplining that they offer one another.”
Griffiths noted that much of the material in their presentation was not new, but that they updated data looking at the historical role of reserve deficiencies: their durations, magnitudes and season.
Based upon exogenous fuel assumptions, ESI tends to increase fuel availability, which might be helpful, “but the impact analysis does not show — when the rubber hits the road, when the system gets really tight and we start approaching reserve deficiencies — that ESI actually improves reliability,” Griffiths said.
“RER offers poor value for money,” he concluded.
Look Back, Carefully
The Massachusetts attorney general’s office and the New England States Committee on Electricity (NESCOE) are jointly sponsoring an amendment to add a look-back provision to the ESI program to enable evaluation of its efficacy.
Under the amendment, the Internal Market Monitor would assess the competitiveness of the energy call option offers and day-ahead reserve prices, determine if any uncompetitive prices are the result of market power and estimate any excess consumer payments resulting from market power.
“We are conscious of and want to respect the Market Monitor’s independence; so while we felt comfortable saying what one of the purposes of the evaluation would be, we leave it exclusively to the discretion of the IMM to determine what evaluation criteria it’s going to use,” Belew said.
The amendment proposes that the Monitor file a quarterly report of its findings with FERC, while ISO-NE will file a quarterly certification of the competitiveness of the energy call options and resulting prices.
Consumer costs scenarios under ESI | NESCOE
Jeff Bentz, NESCOE director of analysis, said his organization had open discussions of the various amendments with IMM staff, who were helpful.
“This ESI thing is in such flux, there’s only small pieces being proposed now,” Bentz said. “There’s a lot of work to do afterwards, so we thought it would not be fruitful to define the criteria here in this room between now and March 24” — the date of the MC vote.
NESCOE also put forward several ESI amendments to include a $10 strike price adder; set the RER quantity to zero for non-winter months; and remove accounting for load forecast error in RER.
“We really have worked hard starting back in July and August, and came to this committee in September, made changes and continued to work towards what we thought were amendments that would decrease consumer costs while still not harming the incentives for the objectives that ISO New England was trying to achieve,” Bentz said.
“This isn’t an attempt to just whittle down money and to be cheap,” he said. “It really comes back to what are the costs and what are the benefits. If we can get the same benefits at a lesser cost, that’s the right approach.”
The Markets Committee also voted to recommend that the Participants Committee support NESCOE-sponsored Tariff revisions relating to energy efficiency resource capacity supply obligations during scarcity conditions. (See “NESCOE Intent on EER Revisions,” NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.)
