MISO’s Independent Market Monitor issued five new recommendations in its annual State of the Market report released Wednesday, focusing on the RTO’s management of flows across its seams, dynamic transmission line ratings and whether energy efficiency should be considered a capacity resource.
But IMM David Patton also used presentation time before the MISO Board of Directors’ Markets Committee to issue a warning on the deteriorating condition of the RTO’s reserve margins.
MISO Executive Director of Market Strategy and Design Scott Wright said the new recommendations this year concentrate on seams and efficient use of the transmission system. Three recommendations offer advice on how to manage flows between neighboring RTOs, where the Monitor suggests:
Using new testing criteria for defining market-to-market constraints. Patton said the rules for determining flowgates have not been overhauled since 2004 and could use an update that places more emphasis on how much available flow relief a non-monitoring RTO can provide.
Improving the relief request software used in market-to-market coordination. Patton said MISO’s current relief request software does not always request enough relief from the non-monitoring RTO because it doesn’t consider shadow price differences between the RTOs.
Clearing coordinated transaction scheduling transactions with PJM every five minutes based on the most recent five-minute prices, not forecasts. The Monitor said “persistent forecasting errors by MISO and PJM have likely hindered” use of coordinated transaction scheduling. Instead, Patton said the most recent five-minute prices are a more accurate forecast of the prices over the next five minutes.
Patton’s two other recommendations include MISO developing the capabilities to apply dynamic transmission line ratings from transmission owners and disqualifying all energy efficiency resources from the capacity auction.
Most MISO TOs don’t adjust line ratings to reflect ambient temperatures and wind speeds, Patton said. He said a “broad adoption” of ambient-adjusted ratings could have reduced congestion costs by $150 million in 2018 and 2019.
Patton also said if all TOs provided short-term emergency ratings, which tend to be about 10% higher than normal ratings, MISO might have saved as much as $114 million in congestion over the past two years.
“The ratings transmission owners provide tend to be overly conservative,” Patton said. “If you calculate how much we could save by rating transmission lines more efficiently, it would be something like $265 million.”
Further, Patton said more efficient line ratings on just the top 25 constraints could achieve two-thirds of that estimated savings alone.
“Hopefully over the next year, we’ll see some progress,” he said, adding that effectively managing congestion can save MISO more than developing a new, big-ticket market product.
Patton also said allowing energy efficiency resources to offer into the MISO Planning Resource Auction (PRA) makes little sense.
“Funneling an additional subsidy to pay for LED lightbulbs is an inefficiency,” Patton said, adding that capacity payments for energy efficiencies don’t make sense because entities with installed energy efficiency are already saving on retail bills.
He also said capacity payments for energy efficiency owners further offset the bills that contain, ironically, the cost of serving them, including energy, ancillary services, and capacity, transmission and distribution costs.
“When they purchase energy-efficient equipment, the electric bill savings include all of these elements. There’s just an array of problems,” Patton said of energy efficiency receiving funding through MISO’s capacity market. “The quantities are growing rapidly and in key tight locations like Michigan.”
Last year, Patton produced six new market recommendations as part of his 2018 report, among them clarifying the criteria for calling emergencies, procuring operating reserves on the Midwest-to-South regional transfer limit and lowering the generator shift factor cutoff for transmission constraints with limited relief. (See MISO Monitor Poses 6 New Market Recommendations.) MISO has yet to issue proposals on any of the 2018 recommendations, though it is working on new capacity accreditation requirements that could address two of the six recommendations. The RTO also discussed possible improvements to the logging and documenting of emergency procedures with the Monitor last year.
Markets Competitive, but Trouble Brewing
Patton also reported that offers into the MISO markets throughout 2019 were highly competitive.
“The prices were about as competitive as they could be. The MISO markets always performed very competitively,” Patton told board members.
Real-time prices for the year averaged just $26/MWh in the footprint, driven by cheap natural gas and a 2% decrease in average load, while a cooler year overall brought lower demand, he said.
By the IMM’s count, 3.3 GW of resources retired in MISO last year. Of those megawatts, almost 90% were coal generation. Patton said more than 4.5 GW of new capacity entered MISO over the same time, including nearly 2 GW of natural gas capacity in MISO South and more than 2 GW of less dependable nameplate wind capacity.
“Nuclear and coal resources are under a tremendous amount of pressure, mainly because gas prices are so low,” Patton said.
Patton predicted a continued gradual loss of coal resources in MISO, making the need for reliable capacity resources more pressing. He said the retirements make MISO’s possible rethink of its capacity resource accreditation even more crucial. Capacity accreditation must be doled out according to resource’s ability to serve capacity reliably, he said.
“It’s likely to be one of the most unpopular proposals among participants, since it’ll look like we’re taking capacity credits away. It’ll be a heavy lift because it’ll look hostile — or at least adverse to their interests — to participants,” Patton said.
“What’s striking about this [report] is the theme of a resource mix in transition,” Wright said.
The Monitor also reserved space in the report to decry the continued use of a vertical demand curve and advocate for a sloped demand curve in the PRA.
Save for a high zonal price in Lower Michigan in this year’s capacity auction, the PRA produces prices that are “close to zero and generally represent less than 2% of the revenue needed to support investment in new peaking resources,” Patton said. “These prices have really hammered the merchant generation and forces them into retirement … or selling capacity outside the footprint.”
Addressing its board earlier this month, MISO said there was a “lack of assurance that the existing resource adequacy construct will … promote participant investments that ensure sufficient resources are available to meet load in all time periods.”
According to MISO’s Tariff, the RTO’s leadership has 120 days, until Oct. 16, to make a public response to Patton’s recommendations.
MISO has temporarily backed off requiring load-serving entities to provide the location and capacity values of distributed energy resources for its planning models.
Planning Modeling Manager Amanda Schiro said the requirement for LSEs to provide counts of inverter-based DERs on distribution systems has been downgraded to a request for 2021.
Schiro said this year’s request is only intended to allow MISO to get a better handle on DER siting. She said the RTO is only in a “data-gathering mode” to possibly introduce future modeling improvements that better capture DERs.
MISO wants LSEs to provide more explicit DER estimates for transmission planning models by 2022.
DERs are registered in the capacity market but not represented in the RTO’s planning models, Schiro said. She said DER integration into reliability planning and operations and market systems will soon necessitate a modeling change.
Summer peak load continues to drop slightly every year, and DERs could play a role in that, Schiro said.
“We want to plan for the situation we’re going to find ourselves in,” she said.
For now, MISO needs more information to decide how to represent DER in modeling, Director of Planning Jeff Webb said.
“We’re trying to just get an understanding of what’s out there,” he said, agreeing with stakeholders that MISO must engage in more discussion with LSEs before it adopts a new approach for better estimating DER in planning models.
Some LSE representatives have expressed skepticism over MISO’s DER modeling goals.
WEC Energy Group’s Chris Plante said many LSEs already include in their forecasts any DERs they have insights into. He also said it might be impossible for MISO to locate all DERs.
“In some cases, it might not be practical to model some DERs because some might be behind the customers’ meter, and we have nothing to do with it,” Plante said.
MTEP Transfers Under Study
MISO has defined the transmission transfers it will study in its 2020 Transmission Expansion Plan (MTEP 20) to determine the system’s capability for handling various transfer scenarios.
The RTO is studying nine transfers under the MTEP 20 voltage stability analysis, which seeks to find future “soft spots” that might cause contingencies on the system. Three of the transfer scenarios will focus on transfer paths from Minnesota to areas in Wisconsin and Illinois, while two others focus on exports into the Downstream of Gypsy area near New Orleans from other Entergy territories.
The analysis also includes:
Minnesota and North Dakota’s exports into Manitoba Hydro territory;
Indiana and southern Michigan’s exports to the St. Louis area;
exports from Iowa into the MISO Central planning region of Indiana, Illinois, western Kentucky and eastern Missouri; and
MISO South to the West of the Atchafalaya Basin load pocket straddling Texas and Louisiana.
Additionally, MISO is studying five transfers under its NERC-required transfer study, used to determine the ability of the MISO system to handle possible power transfers across the footprint:
Ontario’s Independent Electricity System Operator to MISO’s East planning region;
MISO Central to the North planning regions in both directions; and
PJM’s Northern Illinois territory to the rest of its footprint east of Indiana.
Nearly all the transfers were chosen based on heavy historical usage; however, the PJM transfer was selected because of an influx of wind generation additions in the area by 2025.
At the end of last month, MTEP 20 contained 510 proposed projects at a combined $4.06 billion. (See Price Tag Rising for MTEP 20.) Those figures will remain fluid as MISO finalizes the transmission package over the next three months.
MTEP 20 is also on a shorter-than-usual timeline this year.
MISO announced earlier this year that it will revise the MTEP 20 schedule to allow the Board of Directors’ System Planning Committee an additional month to review the transmission package prior to the full board vote in early December. That means the PAC will review, then vote on, whether to recommend the draft MTEP 20 report about a month earlier than usual, in September instead of October. (See “MTEP 20 Schedule Change,” Northern Focus for MTEP 20.)
PAC Chair Cynthia Crane has said the truncated MTEP timeline caused “some consternation” among stakeholders. “As much as everyone wants to give the board extra time to review, it’s going to take a month out of the process to form the MTEP,” Crane reported to the MISO Steering Committee in February.
PJM’s load-side stakeholders were disappointed last month when they failed in their bid to give the RTO control over end-of-life (EOL) transmission planning.
But the joint stakeholders rebounded at the June 18 Members Committee meeting, recording a 69% win that culminated more than four years of battles with PJM’s Transmission Owner sector. The victory sets up a showdown at PJM Stakeholders Endorse End-of-Life Proposal.)
How did the joint stakeholders pull off their comeback, after falling short in votes in May? A review of voting records and interviews with more than a dozen stakeholders indicate it was the joint stakeholders’ gains among the Generation Owners and Other Suppliers sectors that turned the vote after days of intense lobbying by both sides.
“In all the time I’ve been involved in the stakeholder process, I’ve never seen so much outreach on an issue,” said Ed Tatum, vice president of transmission for American Municipal Power, which led the joint proposal with Old Dominion Electric Cooperative (ODEC), the PJM Industrial Customer Coalition (ICC) and LS Power. “That includes PJM and the [TOs] as well as our group.”
End of Life Task Force
AMP, ODEC and the PJM ICC have been fighting to increase the transparency of the EOL process since at least February 2016, when they won approval of a senior task force to consider development of RTO-wide criteria for EOL transmission facilities. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)
Some TOs have established criteria for such projects under FERC Form 715, while others consider them supplemental projects — improvements not required for compliance with PJM system reliability, operational performance or economic criteria. The RTO does not approve supplemental projects but does study them to ensure they won’t harm reliability.
PJM says TOs’ supplemental projects totaled almost $3.4 billion in 2019, more than double the less than $1.5 billion in regionally planned baseline projects. It was the fifth year out of the last six in which the costs of supplemental projects exceeded those of baseline projects.
Load interests, who noted that much of the grid is 30 to 50 years old and in need of replacement, say EOL projects should be planned regionally by PJM to optimize and control spending. LS Power would like to see the projects eligible for competitive bidding under Order 1000.
The group ended its work five months after FERC approved the TOs’ request to move language governing supplemental projects from PJM’s Operating Agreement to Tariff Attachment M-3, while requiring changes to improve transparency. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
In January 2019, AMP and ODEC won 69% support of the Markets and Reliability Committee for changes to Manual 14B that would give PJM more control of supplemental projects. PJM officials refused to implement the changes, however, saying they would conflict with FERC rulings. After months of negotiations, AMP and LS Power reached agreement with the TOs on manual language to prevent TOs from proposing supplemental projects designed to meet regional needs. (See PJM TOs Sign off on Supplemental Project Deal.)
Last fall, Tatum won approval of a new issue charge that resulted in five special MRC meetings to consider “Transparency and End of Life Planning” — discussions that resulted in the joint stakeholders’ EOL proposal and PJM’s alternative.
The joint stakeholders’ proposal would amend the OA to require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date. The projects would be included in five-year planning models and potentially opened to competitive bidding.
The Transmission Owners Agreement-Administrative Committee (TOA-AC) laid out its own EOL proposal, which aligned with the position of PJM staff, in proposed amendments to Attachment M-3 (ER20-2046). It would require TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with Regional Transmission Expansion Plan reliability violations would be included in a competitive window seeking “the more efficient and cost-effective solution.”
The TOs say the proposal would increase transparency and improve planning coordination with PJM while honoring their rights and responsibilities over asset management. The joint stakeholders contend it would do little to improve transparency or change the status quo.
Element of Surprise
The TOs gave notice on May 7 that they were considering the M-3 amendments, starting a 30-day clock to accept comments before they could make the filing under Section 205 of the Federal Power Act. Their action forced the joint stakeholders to seek a vote at the May 28 MRC meeting — earlier than stakeholders had planned, Tatum said. “We felt like it might have been a little too soon, but we had to give it a run,” he said.
The stakeholders garnered 64% support for the proposal in a sector-weighted vote in the MRC, then 62% on a procedural vote to bring the matter before the Members Committee — both short of the two-thirds threshold required.
The stakeholders felt more confident heading into the June 18 vote, after addressing what they said was misinformation about their proposal.
One stakeholder said some members were concerned the proposal would “mess up” the interconnection queue. Others were told TOs “couldn’t replace a pole without going to the stakeholders.”
“There were a lot of things that were being said about our proposal that weren’t entirely accurate,” Tatum said. “We talked to a lot of folks to make sure they had an unbiased view of the facts and the focus.”
“It really did require a lot of listening on our part … to address the concerns” that caused the failed May vote, said Susan Bruce, who represents the PJM ICC. “You had to do old school get-out-the-vote discussions.”
“In the last four or five years, I can’t think of more grassroot-level voting calls than I received on this issue,” one stakeholder said. “I had folks on both sides reaching out to me. … There was almost none of that before the prior [May] vote.”
The joint stakeholders gained 21 supporters on June 18 among those absent in May and also won over one member that had abstained. All told, 30 more members voted in June than in May (from 128 to 158), an increase of almost one-quarter.
The joint stakeholders lost six “yes” votes from May: four to abstentions and two to absences. But none of the original “yes” votes joined the TOs in opposition. Meanwhile, four “no” votes switched to “yes,” and four other “no” votes abstained.
The stakeholders made big gains among the Generation Owners, picking up six votes to rise from 56.5% of the sector (13 of 23) to 82.6% (19 of 23). Among members of the PJM Power Providers, voting affiliates for seven supported the proposal while three members abstained, including two, Advanced Power (voting as Carroll County Energy) and Talen Energy, which had voted “no” in May.
Vistra Energy (voting as Dynegy Marketing and Trade), Eastern Generation and Wheelabrator Falls, which had voted “no” in May, flipped to the “yes” column. The stakeholders also won backing from five generators that hadn’t voted in May: Cape May County Municipal Utilities Authority, CPV Power Holdings, Pixelle Specialty Solutions, Tenaska Power Services and NRG Power Marketing.
NRG Energy “supports using competition to control transmission costs in PJM and voted accordingly today with consumer interests and others at the RTO’s Members Committee,” Travis Kavulla, vice president of regulation for NRG, tweeted after the vote.
By one count, the RTO’s renewable generators split with six “yes” votes, three “no” votes and six abstentions. “What happened was the competitive generators all lined up behind the proposal, while the renewable crowd kind of sat on the sideline,” one stakeholder involved said.
Financial Traders Side with TOs
The stakeholders also peeled off enough Other Suppliers to squeak out a majority in the sector, rising from 40% in May (14 of 35) to 51% (26 of 51).
They added 12 “yes” votes — including Conoco Phillips, BP Energy and NextEra Energy Marketing, which had abstained or not voted in May, and Direct Energy, which switched from “no” to “yes.” The TOs were able to add only four “no” votes.
Sixteen of 21 financial traders in the OS sector opposed the joint stakeholders, with two voting “yes” and three abstentions. Eleven of the companies that voted against the stakeholders are represented by attorney Ruta Skučas of Pierce Atwood. | Pierce Atwood
The joint stakeholders would have cleared the two-thirds threshold at the May MRC meeting had they been able to flip four OS votes. RTO Insider reported previously that it was a bloc of financial traders that turned the sector against the stakeholders’ proposal in May. (See “Financial Traders Joined TOs in Opposition,” PJM TOs Outline End-of-life Tariff Amendments.)
Sixteen of 21 financial traders in the OS sector opposed the joint stakeholders, with two voting “yes” and three abstentions. Ten of the companies that voted against the stakeholders are represented by attorney Ruta Skučas of Pierce Atwood.
Several stakeholders noted that financial traders have been at odds with load interests, who have questioned whether the traders bring value to PJM markets.
In 2017, the Financial Marketers Coalition, led by Skučas, vigorously opposed a rule change supported by the PJM ICC and Electric Distributor sector that reduced bidding locations for increment offers, decrement bids and up-to-congestion transactions by almost 90%. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
In May 2019, the Organization of PJM States Inc. (OPSI) pressed PJM to act on a recommendation from the independent consultants’ report on the GreenHat Energy default that the RTO conduct a general review of the financial transmission rights market and consider potential reforms. The RTO announced last month it will hire a consultant to help it consider whether the FTR and auction revenue rights markets should be changed to ensure more of the benefits go to load-serving entities rather than financial traders. (See PJM ARR/FTR Review Could Pit LSEs vs. Financial Traders.)
With that review looming, one stakeholder speculated that the financial traders were engaged in vote trading with TOs. “That’s the only conclusion I can come to,” the stakeholder said. After the May vote, the stakeholder added, “there was a huge get-out-the-vote effort in the Other Suppliers sector to counter the financial traders.”
Skučas declined to discuss her clients’ reason for their votes, saying, “I am also concerned and disheartened that a stakeholder could not reach the conclusion that a fellow stakeholder group was substantively weighing disputed issues and reaching a position that differed from their own.”
As they had been in May, the Electric Distributor and End-Use Customer sectors were almost unanimous in supporting the joint stakeholders in June. The End-Use Customers sector added two “yes” votes in the June vote (from 17 to 19), remaining unanimous.
Consumer advocates from D.C. and nine of PJM’s 13 states — Delaware, Indiana, Maryland, New Jersey, Kentucky, Pennsylvania, North Carolina, West Virginia and Ohio — supported the proposal. Representatives for Virginia, Illinois, Michigan and Tennessee did not vote.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said it is difficult to get participation from all CAPS members for a variety of reasons; some states need more time to obtain voting authority.
Although OPSI took no position on the vote, staff for the New Jersey Board of Public Utilities and the Kentucky Public Service Commission spoke in favor of the proposal at the June MC meeting.
The EOL issue is particularly important for New Jersey, as Public Service Electric and Gas has led all PJM TOs since 2005 in spending on supplemental transmission projects. PSE&G spent $10.3 billion on supplemental projects between 2005 and 2019. Only one other TO, American Electric Power ($7.96 billion), spent more than $4 billion. PSE&G spent more than $5 million on supplemental projects per transmission line circuit mile over the period. Second-ranked Baltimore Gas and Electric spent less than $1.5 million per mile.
Asked to explain the discrepancy, a PSE&G spokesman declined to comment, saying only “we’ll pass.”
PSEG has led all PJM transmission owners since 2005 in spending on supplemental transmission projects, which include end-of-life facilities and are excluded from competition. | PJM
Public Power
The Electric Distributor sector was unchanged at 96.6% in the June vote, with support from all but one of the 29 voting.
All but two of the 21 members of the PJM Public Power Coalition represented by Carl Johnson voted for the stakeholders’ proposal. (Most of the coalition is in the Electric Distributor sector; members that don’t have load in PJM are registered as Other Suppliers.) Similarly, all nine members of the Public Power Association of New Jersey (PPANJ) voted “yes.”
“For the most part, there was support among the public power entities to having PJM do a broader look at replacing facilities that reach their end of life,” said Johnson, a consultant for Customized Energy Solutions. “And there was interest in having FERC finally give us a clear determination” on whether its CAISO rulings apply to PJM, he added, saying stakeholders have made convincing arguments on both sides.
PJM has said its role is limited by the two FERC rulings, which concluded that equipment replacements that result in only incidental increases in system capacity are asset management decisions under TOs’ exclusive control, not planning matters subject to FERC Order 890. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
“For us, [transmission] is a very big component of our cost, particularly in the PSEG territory,” said Brian Vayda, executive director of the PPANJ. “Transmission is on the verge of overtaking the cost of the commodity on a per-megawatt basis.”
Vayda said his members, who serve 75,000 customers, are keenly aware of the importance of reliability and resilience. “But we’re very concerned about the escalating costs and the lack of transparency that has always been an issue with supplemental projects.”
Margin of Victory
Backers of the joint stakeholders’ proposal said they were gratified by the widespread support they received.
“The joint stakeholders put tremendous time and effort into educating stakeholders on the need to push PJM into a grid of the future approach that includes competition and a regional perspective,” Poulos said. “It was amazing to see stakeholders rally behind the proposal with only the transmission owners, financial traders and a handful of renewable interests voting against it. On a major issue like this, it is quite impressive to see a unified position from the vast majority of stakeholder interests.”
“The key takeaway for me is that a majority of every sector other than the TOs supported the joint stakeholder proposal,” ODEC’s Adrien Ford said. “That is powerful to me.”
“There were 94 companies that voted in support of this. That’s a lot of companies,” LS Power’s Sharon Segner said.
Tatum said the joint stakeholders are eager to have FERC opine on issues that have provoked disagreement among PJM members, including the applicability of the two CAISO orders and the PJM TOs’ rights under the OA, Tariff and Consolidated Transmission Owner Agreement (CTOA).
After the June 18 MC vote, AMP Transmission and ODEC filed a motion to have the TOs’ Attachment M-3 filing dismissed. They contend the TO’s 30-day notice was issued without a formal vote of the TOA-AC, as they say is required by the CTOA. As PJM TOs, AMPT and ODEC have seats on the committee.
Outgoing TOA-AC Chair Takis Laios, of AEP, had said a vote wasn’t necessary because a “supermajority” of the TOs had approached him and said they had the votes necessary for a Section 205 filing they wanted to take before stakeholders.
Tatum acknowledged that AMP and ODEC could not have blocked the TOA-AC from approving the Attachment M-3 changes. But had the TOs followed the CTOA rules, Tatum said, “we would have known this was coming.”
As in the May votes, the TOs were near unanimous in opposition to the joint stakeholders on June 18 (11 of 13 “no” votes in May to 12 of 14 “no” votes in June). The only defectors were two merchant transmission operators, Linden VFT and Neptune Regional Transmission System, who supported the joint stakeholders.
TO representatives did not respond to requests for comment for this story.
During debates before the MRC and MC, the TOs and PJM said the stakeholders’ OA changes violate the CTOA by attempting to give the RTO authority over asset management decisions, making it in the words of Exelon’s Robert Taylor “substantively and legally flawed.”
In a May 22 letter, 10 of the TOs said the joint stakeholders proposal is “not in the best interest of our customers and will impair system reliability and safety.”
PJM said the joint stakeholders’ proposal to amend the definition of supplemental projects and create a new category of EOL projects under the RTO’s planning authority “is beyond the scope of authority transferred to PJM under the CTOA.”
Alex Stern, director of RTO strategy for PSEG Services, told the MC on June 18 that the TOs spent six months trying to work with other stakeholders only to find “divide and a disconnect” in the stakeholder process. He said the OA changes will hinder, not facilitate, “the grid of the future.”
Tatum disagreed. “I honestly believe this is how [the PJM stakeholder process] is supposed to work. There’s nothing broken about this in any stretch of the imagination.”
He said he has been encouraged by PJM’s new CEO, Manu Asthana, who he said has shown a willingness to listen to other stakeholders. “The stakeholder process can work when PJM’s fingers are not on the scale,” he said.
Erik Heinle, of the D.C. Office of the People’s Counsel, said the transmission assets being replaced now were built under different business models — before retail choice, renewable generation, demand response and other innovations.
“We want to see more oversight by PJM. We want to see it fulfill its role as the regional transmission planner.
“PJM has been great about being a leader on the market side. They’ve been less good about bringing that leadership on transmission,” he said. “I am concerned that PJM is not always a neutral player.”
Asked to respond, PJM referred to General Counsel Chris O’Hara’s comments at the June 18 meeting — at which he said the RTO would file the OA changes with FERC although it disagrees with them — and the Board of Managers’ May 27 letter to the joint stakeholders defending PJM’s EOL proposal.
“These issues will be ultimately settled at the FERC,” said spokeswoman Susan Buehler.
FERC has approved NERC’s request for a $3.8 million budget variance to support development of the ERO Secure Evidence Locker (SEL), part of the organization’s Align software project to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise (RR19-8).
NERC requested the variance on June 8, after receiving authorization from the Board of Trustees the previous month. (See “Align Expenditure Moves to FERC for Approval,” Align Tool Set for 2021 Rollout.) NERC’s filing did not provide a reason for the modification.
The organization will pursue a 60-month term for the loan rather than the normal 36 months because of current low interest rates. Annual debt servicing costs are expected to total $430,000 from 2021 to 2025 and will be incorporated in the Business Plan and Budgets for those years. NERC also estimates $570,000 in software, support and maintenance expenses for the ERO SEL in 2021 — based on licensing agreements with hardware and software vendors — with slight increases expected in future years.
Release schedule for Align and SEL as of March 23. NERC has said that Release 1 of the SEL may be delayed from Q4 2020 to Q1 2021 because of the COVID-19 pandemic. | NERC
SEL to Provide Secure Data Storage
Align grew out of the CMEP (Compliance Monitoring and Enforcement Program) Technology Project, begun by NERC in 2014. After NERC selected BWISE Information Security to develop the Align tool in 2018, the organization set its rollout date for September 2019. However, the project was delayed last summer because of concerns over the vendor’s sale to SAI Global, an Australia-based company whose investors include Baring Private Equity Asia, a Hong Kong-based private equity firm. (See NERC Investigating Chinese Tie to Software Vendor.) NERC CEO Jim Robb said earlier this year that the tool is now expected to be released in the first quarter of 2021.
NERC CEO Jim Robb | ERO Insider
The SEL was conceived as a way to provide secure storage where potentially sensitive information collected as evidence can be kept separate from work papers managed through the Align tool itself. Security features of the SEL and training of CMEP staff will prevent the improper access, use or transfer of evidence stored in the locker. NERC’s development plan includes an independent third-party security review of the SEL before launch; the organization expects to conduct annual reviews thereafter.
Several regional entities maintain their own digital lockers to store evidence associated with NERC’s Critical Infrastructure Protection reliability standards. NERC says the SEL, which will store “evidence associated with CMEP processes,” is not intended to replace these systems and that, in fact, REs are welcome to construct their own lockers for CMEP evidence as an additional security measure, though all such systems are expected to “meet certain functionality criteria.”
NERC originally planned to roll out the SEL in an update to Align, but development was accelerated at the request of registered entities last year after the tool’s first delay. As of the Align team’s most recent stakeholder update in March, it was targeting a fourth-quarter release for the SEL, though in its variance request, NERC said a delay to the first quarter of next year may be necessary “due to supply chain disruption caused by the COVID-19 health crisis.”
FERC last week denied a complaint by Amtrak challenging the transmission rates charged to the railroad company by PPL and seeking more than $12.5 million in refunds (EL19-78).
Exelon’s Constellation NewEnergy (CNE) supplies electricity to the Amtrak-owned Conestoga substation outside Lancaster, Pa., from or through the nearby Safe Harbor hydroelectric plant, which is directly connected to the substation. Amtrak alleged in its May 2019 complaint that it is being assessed “unreasonable” charges by PPL for network integration transmission service (NITS) because no PPL transmission facilities are used to deliver energy to it from Safe Harbor.
PPL, which formerly owned the substation, holds a “floating easement” there, allowing energy generated at Safe Harbor to be delivered to the transmission system to serve third parties. The power needed by the railroad flows through the substation to serve its rail system at Parkesburg and Royalton in Pennsylvania, and at Perryville, Md.
An Amtrak train stops at a station in Lancaster, Pa.
Amtrak complained that PPL’s NITS charges for energy delivered from Safe Harbor to Conestoga to serve Parkesburg and Royalton have “no basis in the physical configuration of the substation, operation or Amtrak’s consumption patterns.”
FERC found that PJM’s Tariff provisions applied appropriate NITS charges at the Conestoga substation because Amtrak indicated it receives most of its power from Safe Harbor, which is a network resource.
“Although Amtrak claims that PPL violated the PJM Tariff by calculating Amtrak’s Parkesburg and Royalton load based on an unfiled methodology, Amtrak’s fundamental argument is that Amtrak should not be charged for NITS for its load at Parkesburg and Royalton if the power Amtrak is supplied by its retail supplier does not flow across PPL’s transmission facilities,” the commission wrote, saying that the railroad is seeking transmission services “that are inconsistent with the PJM Tariff and commission policy.”
Map of Amtrak service at Conestoga | FERC
Amtrak also acknowledged that on “rare occasions” when Safe Harbor is unable to meet energy demands, power flows in through PPL’s Manor substation on PPL lines, across Safe Harbor’s frequency converter and into the Conestoga substation.
FERC responded that having a backup power source “is what it means to take and rely on network service” and that a transmission provider like PPL “plans and provides for firm transmission capacity sufficient to meet the customer’s current and projected peak loads.”
“Given these benefits, it is appropriate that Amtrak bears the costs associated with its reliance on the transmission system, as its retail supplier, CNE, is a network customer relying on a network resource,” the commission wrote.
New England needs a CO2 price of $25 to $35/ton by 2025, rising to $55 to $70 by 2030, to meet states’ carbon emissions goals, according to a report released Wednesday by the New England Power Generators Association (NEPGA).
The report, prepared by the Analysis Group, says carbon pricing is essential to preserving wholesale electric competition and ensuring the least-cost path to meeting the New England states’ 2050 goal of reducing economy-wide greenhouse gas emissions by almost 80% compared with 2015 emissions.
Projected CO2 emissions changes by sector under high electrification | Analysis Group
While other studies have focused on the 2050 end-state, said NEPGA President Dan Dolan, “this report provides a viable pathway to meet New England’s climate change responsibilities by producing needed investments in electricity supplies and enabling electrification in transportation and heating.”
A multisector carbon price is essential to the “deep and continuous investments” needed to electrify transportation and heating and build the power system infrastructure to support the transition, the report says. “Without a multisector approach, the financial signal for electrification in transportation or residential heating would be undermined because CO2 emissions have only been valued in the electricity sector,” it says.
Daily net load variability (January 2035) | Analysis Group
The study employed production cost modeling to determine the carbon prices needed in 2025, 2030 and 2035 to ensure “revenue sufficiency” for the resources required to meet GHG reductions without state or federal procurement mandates or subsidies.
Although the carbon prices calculated are lower than the estimated social cost of carbon, “they would allow for market competition to drive evolution of the region’s power system without state-mandated procurement of specific generation resources,” the study says. “The lower range of CO2 emission prices for 2025 recognizes that certain New England states have already made long-term contractual commitments that provide the financial support needed for various zero-emission resources to be brought into service or remain operational.”
The volume of zero-emission resources needed by 2030 and 2035 will increase the frequency of zero-price energy hours, putting downward pressure on prices and requiring a higher carbon price for them to remain viable without subsidies, it says.
The study assumed light-duty electric vehicle penetration of 25% in 2025, 60% in 2030 and 90% in 2035. Similarly, it assumed 25% of homes heating with oil, propane or natural gas would switch to electric by 2025, rising to 50% by 2030 and 75% in 2035.
Lower Household Prices?
Although a carbon price would increase wholesale power prices, it “would not drive up consumer costs materially if states choose to rebate carbon revenues,” the study says.
It projects that average residential household energy costs would actually decline by 2035 under electrification.
Without the transition, the study posits annual household energy costs will rise from less than $6,000 currently to almost $8,000 by 2035. Costs would be less than $7,000 with electrification and a carbon price, it said.
Electrification of the transportation sector would be the biggest source of GHG reductions. While residential heating electrification would produce only “modest contributions” to GHG cuts, it would turn ISO-NE from a summer- to a winter-peaking region by 2030.
Estimated average annual consumer energy costs for households that adopt electric vehicles and convert home heating system from fuel oil or natural gas to electric heat pumps | Analysis Group
The study also notes the increasing need for flexible electric sector resources to respond to increased hourly net load variability. More variable renewable resources and the addition of EV and heating loads would increase average hourly ramping requirements to more than 15,000 MW at times in winter, it says.
“Even assuming a significant quantity of technologically feasible energy storage resources, the availability of existing fossil fuel generators will be vital over at least the next one to two decades” for ISO-NE to manage the change in load shape and growth in daily ramping needs, it says.
Competitive markets with efficient carbon pricing could save consumers $100 million to $300 million ($2020) between 2026 and 2035 compared with reliance on utility-administered resource procurements.
A carbon price would allow technology-neutral competition; reduce reliance on out-of-market contracts that lock in long-term costs; ensure financing in the absence of long-term contracts; increase incentives for developing new supply-side and demand-side technologies; and encourage consumer use of demand management, the study says.
Historical and expected economy-wide greenhouse gas emissions by state | Analysis Group
“It is obvious that establishing enhanced carbon pricing in electric energy markets is not an easy path to take from political and regulatory perspectives,” it says. “Yet pursuing these objectives through state-mandated programs and procurements will almost certainly achieve the results imperfectly, and at costs in excess of what would result through efficient carbon pricing. …
“The absence of an effective carbon-pricing mechanism is a fundamental challenge to continued reliance on competitive markets,” it says, calling the Regional Greenhouse Gas Initiative insufficient. “Absent adoption of a carbon price in energy markets, the pace and magnitude of additions of out-of-market, procurement-based resources will likely undermine the continued relevance of wholesale markets in New England as a vehicle for resource development and investment. … Carbon pricing in energy markets is not an easy path to take, but it may be the only one that can preserve the operation of competition for the benefit of consumers.”
FERC denied CAISO’s request to reconsider its rejection of the ISO’s proposal to adopt a “net export limit” to help entities in the Western Energy Imbalance Market avoid unintended consequences of market power mitigation.
But the commission’s June 18 order denying rehearing clarified that its initial ruling did not imply that unmitigated bids would be effective in determining LMPs for serving load in an import-constrained balancing authority area (BAA) subject to local market power mitigation (ER19-2347).
The commission’s Sept. 19, 2019, order nixed the ISO’s proposal to introduce a net export limit that would have allowed EIM entities to limit the additional dispatch of resources when resources’ bids are reduced because of their BAAs becoming subject to bid mitigation. (See CAISO Goes 2 for 3 on EIM Hydro Rule Changes.)
Active and pending participants in the Western EIM | CAISO
As FERC explained in its order, “the optional feature would [have allowed] EIM entities to limit net transfers out of the mitigated BAA to the greater of: (1) the pre-mitigation transfer quantity, or (2) the base transfer quantity, plus, for both (1) and (2), the sum of the flexible ramping up awards in the market power mitigation run in excess of the BAA’s flexible ramping-up requirement.”
CAISO intended to enforce the rule in both the 15-minute and real-time markets to ensure that every interval limit was determined separately.
In rejecting the provision, FERC ruled that it was “inconsistent” with the EIM’s market power mitigation framework and “not an appropriately calibrated solution to the concerns CAISO identifies.”
“In particular, CAISO’s proposal could weaken CAISO’s market power mitigation process by allowing EIM entities to withhold generation through the submission of high supply bids and restricting EIM transfers out of their BAAs,” the commission wrote.
In seeking rehearing, CAISO argued that there was no evidence supporting FERC’s conclusion that the proposed net export limit would encourage EIM entities to withhold generation. In fact, CAISO said, the net export limit would encourage suppliers to offer greater levels of supply into the EIM because “it was designed to eliminate the existing incentive for an EIM entity, if it wishes to limit the amount of energy that its resources may have to sell at mitigated prices, to only offer the minimum amount of required supply.”
“We are concerned that CAISO’s proposed incentive for greater participation in the EIM is likely to produce outcomes that are not just and reasonable. Contrary to CAISO’s assertions, the direct effect of the proposed net export limit would be to allow EIM entities to limit the dispatch of their resources if they are mitigated in the market power mitigation run,” FERC wrote.
In its motion for clarification, CAISO faulted FERC for “failing to explain how the existing local market power mitigation system and the participation in the proposed net export limit feature can result in ‘unmitigated bids … determin[ing] the dispatch to serve load outside of the EIM entities’ BAAs.’”
FERC said that wasn’t the case.
“We acknowledge that all supply bids in an import-constrained BAA would continue to be subject to mitigation under CAISO’s proposal. However, the proposed net export limit would allow an EIM entity to cap its net transfers and the restriction on supply would affect dispatch in the exporting BAA and in other BAAs,” it said.
FERC denied a complaint filed by Anbaric Development Partners seeking an order for PJM to allow developers of offshore transmission “platforms” the ability to obtain injection rights.
In its decision filed June 18, the commission ruled that Anbaric failed to demonstrate that the PJM Tariff is “unjust and unreasonable” because of the RTO’s refusal to allow three proposed offshore transmission projects to receive transmission injection rights (EL20-10).
Anbaric and other transmission developers argued to PJM that having individual wind farms build separate radial lines to shore will be more expensive, more environmentally intrusive and less resilient than networked open access facilities that multiple wind farms could use.
Anbaric is focusing much of its efforts on areas off the coast of Massachusetts, which is seeking aggressively to develop offshore wind. | Bureau of Ocean Energy Management
“PJM’s interconnection analyses require a source and a sink and controllability in order to meet operational requirements, such as measuring congestion and assessing deliverability,” the commission wrote. “Rather than ‘picking winners and losers,’ these requirements enable PJM to ensure that its transmission system operates reliably and efficiently. Any merchant transmission facilities that meet these Tariff requirements may seek interconnection to the PJM system.”
PJM’s Tariff allows merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. In early 2019, stakeholders approved a problem statement that considered allowing merchant transmission developers to request injection rights for non-controllable AC transmission offshore, but after six special sessions, members opted to refrain from changes. (See “PJM Recommends Sunsetting Offshore Wind Special Sessions,” PJM PC/TEAC Briefs: Sept. 12, 2019.)
Anbaric — which helped build the 660-MW Neptune HVDC cable linking PJM to Long Island and the 660-MW Hudson project connecting Manhattan to the RTO — filed the FERC complaint after the stakeholder process failed. It is still planning a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, Anbaric Pushes Offshore Grid Plans.)
In March 2018, Anbaric submitted interconnection requests for two proposed AC transmission platform projects seeking 1,100 MW of injection rights, but PJM told the company it would need to partner with a generator to obtain the rights under current Tariff rules.
Anbaric envisions a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, NYISO and ISO-NE. | Anbaric Development Partners
Then in June 2018, Anbaric submitted an interconnection request for a proposed DC transmission platform project seeking a 1,200-MW injection into Public Service Electric and Gas’ transmission system in North Brunswick, N.J. After completing a feasibility study that assumed the injection, PJM informed Anbaric in November 2019 that it would only model the project without injection rights.
The company argued to FERC that there are no technical reasons for blocking transmission platform projects, citing transmission built to deliver onshore wind from Texas’ Competitive Renewable Energy Zones and California’s Tehachapi Pass. FERC dismissed the argument, saying PJM already has the “State Agreement Approach” in its Regional Transmission Expansion Plan (RTEP) process that can be used for transmission to offshore wind.
The commission last week issued a notice that it will hold a technical conference on Oct. 27 to discuss “whether existing commission transmission, interconnection and merchant transmission facility frameworks in RTOs/ISOs can accommodate anticipated growth in offshore wind generation in an efficient and effective manner that safeguards open access transmission principles and to consider possible changes or improvements to the current framework should they be needed to accommodate such growth.”
Commissioner Bernard McNamee issued a concurring statement in the Anbaric order saying the technical conference will allow FERC to hear from industry experts about the challenges and opportunities of developing offshore wind projects.
“A key element to gaining access to offshore wind is the construction of and access to transmission to bring wind-generated electricity onshore to the grid,” McNamee wrote in his statement. “As discussed in today’s order, there are a number of complicated issues involving open access, financing and jurisdiction that need to be confronted.”
First came the wind turbines, then solar panels. Battery storage followed, and now RTOs and ISOs are faced with integrating hybrid energy resources.
The main barrier to their integration? The RTOs and ISOs themselves.
“All of the markets are having conversations but in different stages and with different scopes,” said Jason Burwen, vice president of policy for the U.S. Energy Storage Association, during a recent online panel discussion facilitated by his organization. “We are starting to see how different markets are going to take this on.”
Grid Strategies President Rob Gramlich, who last year authored a paper for the ESA on the subject, says regulations have not kept up with technology and the markets. He thanked FERC for pursuing “some” reforms but noted the commission’s recent orders on storage (841) and interconnections (845) don’t address hybrid resources.
“It’s been just incredibly fast how much the market has changed,” he said during ESA’s June 11 discussion. “Hybrid doesn’t even appear in those rulemakings. That’s not the fault of FERC. It’s just that nobody raised it. The market has moved faster than policy.”
Hybrid resources are generally considered to be co-located pairings of two different technologies. Most of these resources consist of solar or wind installations paired with batteries, the “core technology driving hybridization,” Gramlich said. Batteries are highly scalable and modular, making them suitable for generation sites, integrating them into the wires’ infrastructure, or locating them with the customer.
Solar PV generation is the most common resource paired with batteries, but other configurations include wind-battery, gas-battery and hydro-battery. These resources’ ability to respond to economic signals differently than traditional generators has driven their recent growth.
According to the U.S. Energy Information Administration, some 4.6 GW of hybrid capacity is currently installed, with another 14.7 GW of capacity in the immediate development pipeline. More than 40 GW of hybrids entered generator interconnection queues last year, pushing the total hybrid capacity in RTO/ISO queues to 69 GW.
Hybrid costs are also coming down, further increasing their attractiveness. Gramlich said power-purchase agreement prices in the U.S. dropped from $40-70/MWh in 2017 to $20-30/MWh in 2018 and 2019, mostly due to falling technology costs and tax credits.
Hybrid resources are filling up interconnection queues. | Grid Strategies
“There are big opportunities for adding storage to existing generation. The main problem is the interconnection queues are very slow,” he said. “Everyone knows the interconnection queues are a constant challenge. If one can make a more efficient use of the interconnection service with an existing service or one that‘s made it through some stages of the queue, that’s an efficient way to go.”
“Order 841 opened the floodgates. Hybrids weren’t previously on the radar,” said Rhonda Peters, a principal with InterTran Energy Consulting. “All of a sudden, you had this ability to take variable generation and make it more dispatchable [with energy storage]. But having that ability didn’t mean it was actually possible because we didn’t have policies that allowed for it.”
The panel members all called for FERC and the RTOs and ISOs to get serious about hybrid resources. In his paper for ESA, Gramlich said some near-term changes can be made to improve integration of the resources by treating them as two separate units and harmonizing their participation models.
“However, for hybrid resources to deliver their full value, they may eventually need to be treated as fully integrated single machines, able to optimize what they provide and when they provide it,” he said, noting RTOs’ and ISOs’ current rules do not allow for this flexibility.
“We’re starting to see how different markets are starting to take this on,” Burwen said, indicating ERCOT and CAISO are taking the lead. “ERCOT plans to use an energy storage model for hybrids. That’s instructive of the direction we’re going. Participating as conventional generation might make more sense than [being paired with] existing resource types. It sets a market for where we think you’re going to make the best use of hybrids.”
FERC is seeking industry comments on a proposed incentive framework meant to encourage utilities to make cybersecurity investments above and beyond the requirements of NERC’s Critical Infrastructure Protection (CIP) standards (AD20-19).
Limitations in CIP Standards Recognized
In a white paper published Thursday, FERC described the proposed incentive framework as a complement to the current CIP standards, which the commission called an “effective technical baseline for cybersecurity practices.” A separate Notice of Inquiry, also issued Thursday, is seeking comments on potential gaps in the standards and suggestions on actions the commission can take to improve them. (See related story, FERC Starts Inquiry on CIP Standards.)
The new proposal is not directly connected to the NOI. Although the commission did recognize “certain limitations” in the existing CIP standards and suggested that voluntary actions by utilities as a result of the planned incentives “could be the basis of future” versions of the standards, FERC’s goal is to encourage utilities to pursue innovative — and voluntary — solutions that would protect their own transmission systems as well as the bulk electric system overall, while allowing the industry to:
be more agile in monitoring and responding to new cybersecurity threats;
identify and respond to a wider range of threats; and
create comprehensive solutions for addressing cybersecurity threats.
Such encouragement could take the form of either return on equity and non-ROE incentives, but the commission favored a mix of both approaches based on the type of investments being reported. ROE incentives would apply to specific incremental cybersecurity investments, while non-ROE measures could apply to construction work in progress, recovery of abandoned plant costs and accelerated depreciation, which would allow utilities to mitigate cash flow concerns caused by initiatives with a longer-term payoff.
Alternative Frameworks Proposed
FERC also sought input on how to identify the cybersecurity investments that merit its incentives, proposing two approaches that could be used independently or in combination. Both would reward utilities for going beyond the requirements of the CIP standards but would use a different basis for assessing their success.
| Shutterstock
The first proposed method would encourage entities to apply the current standards in areas where they are not currently relevant. Specifically, several CIP standards apply only to medium- and/or high-impact BES cyber systems, leaving many low-impact systems unaddressed — a distinction that has prompted criticism from security activists. (See NERC Pushes Back on New CIP Standard Challenge.) FERC would provide an ROE adder or other incentive for utilities that voluntarily apply CIP standards to BES cyber systems with a lower impact than those for which the standards were intended.
An advantage of this approach is that utilities and regulators would be working within a framework with which they are already familiar, making the criteria for approving an incentive clear. On the other hand, it would also leave registered entities with little reason to look beyond this framework. For that reason, the commission put forward another approach, under which incentives would be based on the National Institute of Standards and Technology’s (NIST) Cybersecurity Framework. This more open-ended approach would require more work from the commission to assess whether cybersecurity investments meet its goals but would allow greater flexibility and creativity on the part of utilities.
Further Questions
In the white paper, FERC emphasized that it is far from making a decision on the final shape of its incentive framework. To guide its decision-making, the commission is requesting comments on a number of questions, including:
whether the CIP standards or the NIST Framework, or both, should be considered as the basis for incentivizing cybersecurity investments;
how FERC can ensure that the incentive eligibility and applicant evaluation processes are clear and fair;
what guidance FERC can provide on structuring cybersecurity incentive applications;
which components of the NIST framework should be considered for an incentive, and how entities might demonstrate that their cybersecurity expenditures qualify under the framework; and
whether the commission should adopt a sunset date for incentivized cybersecurity investments in order to encourage utilities to keep up to date with a changing security environment.
Comments on the white paper are due within 60 days of its issuance, with reply comments due within 75 days.
