CAMBRIDGE, Md. — As PJM considers how to best manage future carbon policies, energy industry experts say the unique challenges the RTO faces can be mitigated with strong coordination between policymakers, stakeholders and grid staff.
“You’re not the only ones looking at this,” Dirk Forrister, CEO of the International Emissions Trading Association, said during the General Session of PJM’s Annual Meeting, at the Hyatt Regency Chesapeake Bay Golf Resort, Spa & Marina, on Wednesday. “It is material, and it seems to be an issue, in terms of public sentiment, that’s coming up more and more.”
Forrister, who once served as chairman of the White House Climate Change Task Force under President Bill Clinton, said the U.S. remains an “outlier” internationally as other countries embrace carbon pricing, with varied levels of success.
“Come on in, the water’s fine,” he said. “To get to the levels of climate protection that governments want, it implies a level of reduction that we haven’t seen before.”
PJM isn’t the first RTO to tackle carbon pricing, but its challenge of balancing the markets between participating and nonparticipating states proves unique compared with NYISO and CAISO.
In New York, NYISO is close to voting on a set of rules to price carbon that would include border charges for imported power and credits for exported power — just one way PJM could handle flows among its 13 states and D.C. (See More Details Divulged on NYISO Carbon Pricing Study.)
In CAISO, where power also flows to and from regions without carbon-reduction goals, operators prioritize curbing emissions over importing energy from the cheapest resources. It’s a focus that Ben Grumbles, Maryland’s secretary of the environment, encourages PJM to take as it examines how pricing could work across the grid.
“A carbon-constrained energy sector is absolutely the future,” he said. “Never lose sight of the fact that the goal should be to reduce emissions.”
Maryland and Delaware both participate in the Regional Greenhouse Gas Initiative, a coalition of Northeast and Mid-Atlantic states committed to capping carbon emissions from the power sector. Emissions have been cut in half since 2014, and more than $3 billion have been reinvested into cleaner energy and ratepayer reductions, Grumbles said.
“In RGGI, the key is to have the environment secretary for the governor and the energy regulators together so we can we find common ground,” he said. “It takes time.” He also emphasized the importance of preserving state sovereignty and protecting consumers from “windfall profits.”
Anthony Giacomoni, senior market strategist for PJM, said an ongoing internal study is quantifying the market impacts of a systemwide carbon price, versus a regional or sub-regional system.
“We want to enable state policies while preserving economic and competitive dispatch,” he said, noting that minimizing “carbon leakage” remains a top priority. “High prices will have very high leakage and, as a result, prevent states from reaching carbon-reduction goals.”
Staff are also considering one-way and two-way border adjustments as other tactics to minimize the impact on nonparticipating states and maintain a level playing field for dispatching generation. While not an “exhaustive” study of all the ways PJM could accommodate carbon pricing, Giacomoni said the RTO hopes it will better inform policymakers and stakeholders of the market impacts.
He said staff will provide an update on study results at the May 15 Market Implementation Committee meeting, with a plan to release the full analysis later this summer.
ERCOT said Wednesday that its final resourceadequacy assessment for this summer indicates “a potential need” to enter energy emergency alert (EEA) status in order to maintain system reliability.
The Texas grid operator is forecasting a peak demand of 74.9 GW, 1.4 GW higher than the all-time record of 73.5 GW set last July. ERCOT will meet that demand with 78.9 GW of available capacity, a slight increase from its spring assessment of resource adequacy.
South Texas transmission lines | CPS Energy
The good news: ERCOT’s planning reserve margin for the summer has increased to 8.6% from an historic low of 7.4%. The grid operator’s target reserve planning margin is 13.75%.
“At this reserve margin level, it’s more likely we’ll have to use additional resources available under emergency operations procedures on several occasions this summer,” ERCOT’s Dan Woodfin, senior director of system operations, said during a media call Wednesday.
“We’re confident we’ll be able to maintain the reliability of the system as a whole. That’s our job,” Woodfin said in response to persistent questions about the possibility of blackouts this summer.
“It’s probably one of the lowest planning reserve margins on record — based on all the data we’ve seen historically — going into a summer peaking area,” John Moura, NERC director of reliability assessment, told the electric reliability organization’s Member Representatives Committee in St. Louis on Wednesday. “So [there are] certainly some challenges, but I believe the operators have the right tools in order to keep the system stable and operating the system reliably.”
Woodfin and ERCOT Manager of Resource Adequacy Pete Warnken said the grid operator has a number of tools at its disposal should operating reserves drop to 2.3 GW and force an EEA 1 declaration — the lowest emergency rating. At that point, ERCOT can take emergency imports from SPP over DC ties, use emergency response service and institute load-reduction measures, among other options.
“We have the tools and procedures in place,” Warnken assured his audience.
The ERCOT reserve margin for the summer months (June-September) was raised thanks to the return of a 365-MW NRG gas-fired unit, 111 MW of upgrades to 12 generating units and an increase in the amount of DC tie imports. (See NRG to Bring Back Gas Plant for Summer 2019) The grid operator’s Board of Directors in April approved a change to import forecasts, basing them on the amount of power that could be brought in during emergency conditions and not historical forecasts.
The fall assessment forecasts a peak demand of just over 61 GW, with more than 84 GW of capacity available.
The updated CDR includes an additional 733 MW of installed wind and solar capacity. It also includes 517 MW of battery storage as being newly eligible for inclusion.
The updated CDR forecasts above-normal growth in demand of 2.5 to 3% through 2022. Oil and gas development in West Texas and new industrial facilities on the Texas Gulf Coast account for much of that growth, ERCOT said.
The grid operator expects the reserve margin to reach 15.2% in 2021, when almost 6 GW of planned resources in the interconnection queue, primarily wind and solar projects, become eligible for the CDR. It projects the reserve margin will dip back below 8% in 2024, when peak demand is expected to exceed more than 84 GW.
Rich Heidorn Jr. contributed to this story from St. Louis.
CAMBRIDGE, Md. — PJM stakeholders gathered for a special Members Committee meeting on Tuesday at the Hyatt Regency Chesapeake Bay Golf, Resort & Marina as part of the RTO’s Annual Meeting.
After a “challenging” and “humbling” 2018, PJM CEO Andy Ott said the RTO will better lead stakeholders in 2019 as it works to adapt the grid to emerging state policies and renewable technology.
“It’s not enough anymore to just have reliability at the least cost and have open, competitive markets,” he said during his keynote address Tuesday. “We need to listen to that as an entity. But it’s not just PJM alone. It’s all of us. We’re all in it together.”
While he admitted the ongoing fallout from the GreenHat Energy default looms large, Ott said PJM is working hard to implement staffing and procedural changes that were recommended as part of an independent probe into the situation. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)
He also said PJM will keep an “open mind” as it works to incorporate energy storage and possible carbon pricing into its markets in the coming years and requested clear direction from stakeholders and federal regulators on those issues.
Nothing ‘Magical’ About RPM
Stu Bresler, PJM’s senior vice president of markets and operations, said stakeholders might want to reconsider what market mechanism best accommodates growing generation subsidies as states continue enacting policies to reduce carbon emissions.
“Markets have worked, but we recognize there’s nothing magical about the Reliability Pricing Model,” he said. “It’s one option as far as resource adequacy is concerned. At some point, maybe we ought to talk about whether there are other alternatives we should look at that could better incorporate the policy goals out there that aren’t necessarily RPM as we know it today.”
The comments came during PJM’s “Year in Review Panel,” in which leaders from each department discussed the challenges and successes experienced throughout 2018.
“Well, there’s no shortage of challenges,” said Joe Bowring, PJM’s Independent Market Monitor, citing continued regulatory uncertainty that is beginning to affect investments in the grid. “The challenges are simple to say, very difficult to do. How do we maintain competitive markets?”
But it wasn’t all doom and gloom from the Monitor, who also praised the implementation of hourly offers and five-minute settlements for setting better price signals, especially with gas-fired generation.
Steve Herling, PJM vice president of planning, noted that increasing stakeholder transparency remains a top priority for staff. “It’s critical that stakeholders understand the assumptions, the analyses and the decision-making process,” he said. “We’ve done a lot over the past couple of years to enhance transparency, but we understand there is a lot more that needs to be done.”
Likewise, PJM’s Vice President of Operations Mike Bryson said that addressing fuel security issues should continue to be top-of-mind for stakeholders. “Each year we get surprised by a different aspect of the evolving fuel mix,” he said.
FTR Forfeiture Calculation Change Endorsed
Members endorsed calculation changes for financial transmission rights forfeiture to be incorporated in the Operating Agreement.
PJM and the Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on- and off-peak FTRs. (See “First Read on Change to FTR Forfeiture Calculation,” PJM MICBriefs: March 6, 2019.)
FTR forfeitures are intended to discourage traders from cross-market manipulation. Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the endorsed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.
Incumbent Board Members Re-elected
Three incumbent members of the Board of Managers won re-election bids: Terry Blackwell, O.H. Dean Oskvig and Mark Takahashi will each serve another three-year term.
The Western Energy Imbalance Market chalked up another future member Wednesday after Tucson Electric Power signed an agreement with CAISO saying it will join the real-time market in April 2022.
The Arizona utility’s move comes just two weeks after Spokane, Wash.-based Avista announced it would be joining up with the EIM at the same time, potentially bringing the market’s participation level to 15 out of 37 balancing authorities in the West. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)
With Arizona Public Service already trading in the market, and Phoenix-based Salt River Project slated to join in April 2021, TEP’s membership will expand the EIM’s reach to include all of Arizona’s major population centers. TEP, a subsidiary of Canada-based Fortis, serves about 417,000 electric customers in the Tucson metropolitan area.
TEP estimates that participation in the EIM will save the utility about $13 million annually.
Tucson Electric Power expects to sharply increase its renewable energy portfolio with a new wind farm in southeastern New Mexico. | Tucson Electric Power
“The EIM will help TEP save money for customers by expanding our real-time access to renewable power and other low-cost energy resources across the Western grid,” Erik Bakken, vice president of system operations and environmental at TEP, said in a statement.
TEP owns or controls 2,531 MW of generating capacity, including 255 MW of utility-scale solar and 80.4 MW of wind; its service area also contains about 220 MW of commercial and residential rooftop solar. In March, the utility announced it would sharply expand its renewable energy portfolio with the construction of the 247-MW Oso Grande Wind Project in southeastern New Mexico.
The utility operates 2,175 miles of high-voltage transmission, with key links into wind-rich New Mexico and the neighboring balancing area of Public Service Company of New Mexico, whose own plans to join the EIM in April 2021 have been complicated by moves by state regulators. (See PNM’s Bid to Join Western EIM Gets Approved in Part.)
The EIM’s current members are APS, Idaho Power, NV Energy, PacifiCorp, Portland General Electric, Puget Sound Energy, Powerex and the Sacramento Municipal Utility District, which began transacting last month. The Los Angeles Department of Water and Power and Seattle City Light also are scheduled to go live in April 2020.
CAISO last month said the EIM has yielded $650.26 million in benefits for its members since being launched with PacifiCorp as its first member in November 2014.
BOSTON — Rejecting ISO-NE’s concerns over “disrupting” the interconnection queue, the NEPOOL Participants Committee voted Friday to broaden the RTO’s proposed rules for obtaining surplus interconnection service (SIS) under FERC Order 845.
Order 845, approved in April 2018, set pro forma minimum standards for large generator interconnection procedures and agreements. FERC said SIS, which would allow a customer’s affiliate or a third party to obtain unused interconnection service and would encourage more efficient use of existing infrastructure (RM17–8). (See FERC Order Seeks toReduce Time, Uncertainty on Interconnections.)
NEPOOL members agreed to allow surplus interconnection service when capacity is available on a periodic basis, such as for customers with peakers or intermittent generation. ISO-NE would have limited it to capacity available on a continuous basis. | RENEW Northeast
The PC voted 67.58% in favor of an amendment by RENEW Northeast, an association of renewable energy providers and advocates, which said the RTO’s proposal did not comply with Order 845 because it would restrict SIS to a continuously available megawatt quantity and not allow periodically-available service. Order 845 said the service could be used at interconnections for generating units that operate infrequently, such as peakers, or that often operate below capacity, such as renewable generators. The amendment was introduced at the Transmission Committee by the Union of Concerned Scientists, a RENEW member.
RENEW also said the RTO’s proposal would restrict surplus interconnections to “non-material modifications to existing generators,” a more restrictive standard than FERC called for in its February order on rehearing (RM17-8-001; Order No. 845-A). (See ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)
In addition to allowing periodically-available service, the amendment eliminates the RTO’s “non-material” restriction.
After approving the RENEW amendment, which NEPOOL will file with FERC, the members rejected ISO-NE’s original proposal, with only 54.2% of votes in favor.
Transmission Owners’ Amendments
In addition to its provisions on SIS, ISO-NE’s proposed compliance filing deviated from FERC’s pro forma generator interconnection agreement (GIA) regarding customers’ option to build, prohibiting it in cases that would require the moving or outage of existing transmission equipment, NEPOOL counsel Eric Runge said in a memo to members.
Although the ISO-NE motion failed, the RTO is expected to file it with FERC, nonetheless. It includes provisions by transmission owners Eversource, National Grid and Avangrid, as represented by the Participating Transmission Owners Administrative Committee, that would allow them to collect “actual costs,” rather than “agreed upon” costs as in the pro forma, for overseeing customers who choose to build interconnection facilities.
ISO-NE Fears ‘Disruption’
ISO-NE had contended the RENEW amendment “conflates” SIS with a different provision in Order 845 that allows for co-location of more megawatts behind a point of interconnection but requires control technology to limit the output to the requested interconnection service levels and requires the filing of a new interconnection request.
In a memo circulated to NEPOOL members hours before the meeting, the RTO said its proposal “fully complies with Order No. 845 while not disrupting the existing interconnection framework used in conjunction with the markets.”
The memo said New England’s capacity network resource interconnection service (CNRIS) and network resource interconnection service (NRIS) “directly correlate to an interconnection customer’s desired level of participation in the New England markets, which do not utilize a system of physical rights like the pro forma services.”
CNRIS and NRIS are only available on a continuous basis.
“The RENEW approach proposes to ignore the unchanged requirement that a material modification requires a new interconnection request [and] calls for significant interconnection studies to be performed outside of the orderly queue process without addressing how those studies would be prioritized and coordinated with the evolving system changes that are articulated by the interconnection queue and other planning processes.”
RENEW disagreed, saying Order 845 requires the RTO to utilize an expedited study process outside of the queue to process SIS requests.
“We recognize ‘outside of the queue’ requests are disruptive, but that’s what the commission’s order said,” Susan Muller, of Boreas Renewables, who presented the RENEW amendment, told RTO Insider. “We’re not suggesting new applications behind the point of interconnection be approved if it causes any reliability problems.”
The RTO’s compliance filing is due May 22.
[See our Editor’s Note: We’re in the Room in NEPOOL!]
BOSTON — The NEPOOL Participants Committee on Friday retroactively approved Tariff revisions filed by ISO-NE on May 1 to address FERC’s concerns over the RTO’s initial compliance filing in response to the commission’s Order 841 rulemaking on energy storage.
ISO-NE’s initial Dec. 3 compliance filing proposed two types of energy storage: continuous storage (batteries and other resources that can transition nearly instantaneously between charging and discharging at any MW level within their range) and binary storage (facilities such as pumped storage whose physical constraints prevent them from quickly changing from charging to discharging) (ER19-470).
The commission issued a deficiency letter on April 1 asking the RTO to explain whether a continuous storage facility would be compensated for lost opportunity costs if it were dispatched for reserves rather than energy. (See “Questions to ISO-NE Touch on Reserves” in FERC Asks RTOs for more Details on Storage Rules.)
The RTO’s May 1 response said “any resource, including a continuous storage facility, dispatched for reserves rather than energy is compensated for lost opportunity costs (which would result from foregone energy sales) via the real-time reserve clearing price, not [net commitment period compensation].”
Facilities that have insufficient available energy to run at their full capacity for a full hour should not receive an opportunity cost payment because their own physical limitation creates the suboptimal dispatch, the filing said.
ISO-NE said it “is very concerned” that paying an opportunity cost payment would likely entail complicated settlement calculations and could create perverse incentive for continuous storage facilities “to maintain relatively small amounts of stored energy in order to be paid this opportunity cost frequently.”
The commission also had asked whether some continuous storage facilities may have start-up or no-load costs, such as costs for cooling a storage facility that is online but not dispatched.
The RTO said such a case was more likely to be an example of a fixed cost, incurred independent of its commitment and dispatch instructions, rather than a no-load cost.
“In a hypothetical universe in which batteries were committed and decommitted by ISO-NE, it seems likely a battery would incur the same cooling costs when it was offline awaiting a start-up instruction as it would incur once it was online at zero megawatts. If this is the case, these costs would be fixed costs,” it said.
Alternatively, it said, if a portion of cooling costs varies with output, that portion would be considered a variable cost. Cooling costs would be characterized as a no-load cost only if, when ISO-NE issues a shut-down instruction to an online resource dispatched to zero megawatts, the resource’s costs decrease by a discrete amount.
ISO-NE said it does not believe this to be the case for any costs likely to be incurred by continuous storage facilities.
Fuel Security Reliability Reviews
The committee approved revisions to Planning Procedure (PP) 10, Appendix I regarding fuel security reliability reviews for Forward Capacity Auction 14 (delivery year 2023/24) with 69.5% support.
The RTO conducts the review on resources that submit retirement de-list bids to determine whether they are needed for reliability.
The changes were approved after NEPOOL attorneys added language to the motion to clarify that supporting the changes to the PP “shall not be construed as support for the ISO’s broader planning for fuel security and resource retention.”
But that wasn’t sufficient to win the votes of the End Users sector, which was unanimous in opposition. End Users Chair Liz Delaney said many in her sector believe ISO-NE’s fuel security model is overly conservative and could lead to expensive contracts to retain unnecessary generators. “It’s hard to separate the assumptions from the operation of the model,” she said in an interview.
The Generators, Transmission and Publicly Owned Entity sectors were unanimous in support. Suppliers were mostly in support (13.43% in favor) and Alternative Resources mostly opposed (5.66% in favor).
The proposal had fallen just short of the required two-thirds vote at the Reliability Committee April 24.
ISO-NE asked for the changes, saying they would:
Improve modeling of injections from local gas distribution company satellite LNG storage facilities;
Maintain the oil inventory levels from the 2017/2018 winter;
Shape the conventional hydroelectric generation output;
Provide additional time for offshore wind resources to demonstrate their contractual commitments; and
Expand the kinds of entities that can provide evidence of contractual commitments under state procurements to include transmission companies, distribution companies and the New England States Committee on Electricity (NESCOE).
The RTO’s Norman Sproehnle told the Reliability Committee in April the changes “cover a variety of optimistic scenarios which minimize the potential for retaining resources unnecessarily.”
Among other things, the changes replaced the assumed replenishment for oil-fired generation from “one proxy tanker truck per hour” to 202 barrels per hour when reorder levels are reached. The RTO clarified oil inventory levels apply to oil-only resources and dual-fuel resources that operate primarily on oil during the winter; it said dual-fuel resource tank inventory levels apply to dual-fuel resources that operate primarily on natural gas during the winter.
It also promised to perform an “informational analysis” for an additional 500 MW of offshore wind being developed under a state procurement with an in-service date for winter 2023/24, which is not included in the base model.
Resources participating in Forward Capacity Auction 14 will be modeled in the study with an in-service date of Jan. 1, 2024, one month later than the original Dec. 1, 2023, deadline.
Consent Agenda
The PC approved four rule changes on the consent agenda, following unanimous approvals at lower committees:
Operating Procedure (OP) 17 (Load Power Factor Correction): Revisions to Appendix C to update company names, and additional, minor grammatical revisions. Approved by the Reliability Committee March 20.
Market Rule Section III.1.9.1.2(a) (Offer and Bid Caps): Revisions to simplify implementation of the day-ahead market (DAM) offer capping approach under Order 831. Recommended by Markets Committee at its April 9-10 meeting.
GIS Operating Rules: Revisions to the NEPOOL generation information system (GIS) operating rules to enhance searching and sorting capabilities of public reports and importation of requested billing adjustment (RBA) data into the GIS. Recommended by the Markets Committee at its April 9-10 meeting.
Reasonable Effort Timelines for Interconnection Studies: Tariff revisions increase from 45 to 90 days the “reasonable efforts” deadline for ISO-NE and transmission owners to complete interconnection feasibility studies after receipt of an executed study agreement. Increases the deadline for completing system impact studies from 90 to 270 days after the receipt of the study agreement, deposit, technical data and demonstration of site control, if required. ISO-NE requested the change to “better align with the expected duration of the study efforts given the scopes of work involved” in the studies. Recommended by the Transmission Committee April 17.
Load Relief, GMD
The committee approved on a single vote changes to OP-2, -4, -4A and PP-11, which were recommended by the Reliability Committee in separate votes on April 24.
Revisions to OP-4 and OP-4A adjust the estimates of load relief from OP-4 actions to be based on a generic 25,000-MW load amount rather than the 50/50 load forecast in the capacity, energy, loads and transmission (CELT) report. Revisions to PP-11 implement requirements under NERC reliability standard TPL–007-3 (Transmission System Planned Performance for Geomagnetic Disturbance (GMD) Events). The NERC standard includes requirements for performing a GMD vulnerability assessment; providing geomagnetically induced current (GIC) flow information; performing transformer thermal impact assessments for a GMD event; and gathering GIC monitor and geomagnetic field data.
— Michael Kuser and Rich Heidorn Jr.
[See our Editor’s Note: We’re in the Room in NEPOOL!]
Three Mile Island’s fate looks bleaker by the day as Pennsylvania lawmakers on Monday wrapped up a series of hearings that considered subsidizing the state’s nuclear fleet, with some concluding even legislative intervention won’t save the infamous facility.
House Consumer Affairs Committee Chairman Brad Roae (R) said consideration of House Bill 11 will weigh a complex mix of impacts on the state’s economy, energy prices and environmental goals but will likely not make enough difference to prevent TMI from closing in September.
“Even if we did do this, it doesn’t seem like TMI is economically viable,” he said while concluding the committee’s fourth public hearing on the issue. “If we did do this, it would close. If we don’t do this, it would close.”
Exelon’s Three Mile Island
Exelon-owned TMI contains one of the state’s nine nuclear reactors and will begin the months-long deactivation process on June 1 amid dwindling profits as cheaper fossil fuels set prices in the wholesale electricity market.
“If these facilities are lost, they will be replaced primarily by natural gas-fired generators — not wind and solar,” said Kathleen Barron, Exelon’s senior vice president of government and regulatory affairs, in submitted testimony. “Carbon and other harmful emissions will increase. Grid resilience will deteriorate. And costs to consumers will go up.”
One way to fix this, some state lawmakers believe, is to incorporate nuclear power into the state’s Alternative Energy Portfolio Standard (AEPS) program. The AEPS provides tax credits for renewable resources spread across two tiers from which electric distributors must buy 18% of their power by 2021, though recent proposals in both the House and Senate want to push this goal to 30% by 2030. (See Pennsylvania Democrats Back Renewables Subsidy Expansion.)
HB 11 — and the similar Senate Bill 510 — would create a third tier in the AEPS from which suppliers must buy an additional 50% of their power by 2021. (See Pa. Lawmakers Unveil $500M Nuke SubsidyBill.) The new credits would cost ratepayers as much as $550 million each year, making it larger than any other subsidy program nationwide.
Both Exelon and FirstEnergy said HB 11 levels the playing field against polluting fossil fuel plants and appropriately values the carbon-free, reliable power reactors provide 24/7, 365 days a year. FirstEnergy will likely retire its Beaver Valley reactors in 2021 as the company wades through Chapter 11 bankruptcy proceedings. (See Judge Rejects Liability Release inFirstEnergy Reorg.)
PJM’s Independent Market Monitor said in March three of the RTO’s 18 nuclear facilities face revenue shortfalls through 2021. The three plants — Davis-Besse, Perry (both in Ohio) and TMI — each operate just one reactor. The remaining multi-unit facilities, including the subsidized Quad Cities in Illinois, will remain profitable. Even without ZECs, Quad Cities would cover its costs for the next three years, according to the Monitor. (See Monitor Says PJM’s Capacity Market not Competitive.)
Barron has said the Monitor’s prior estimates of profits and losses across Exelon’s three Pennsylvania plants were based on “inaccurate” data. The Monitor previously concluded TMI lost $37 million in 2018, while the Peach Bottom and Limerick plants earned a combined $350 million. (See Nuke Talks Continue in Pa. Assembly.)
Paul Adams, an Exelon spokesperson, clarified on Monday that TMI will remain open if HB 11 passes before June 1. “Absent passage by June 1, TMI will shut down in September,” he said.
Market Impact
Stu Bresler, PJM’s senior vice president of operations and markets, told the committee the grid operator takes no position on either of the bills pending before lawmakers.
“That PJM is neither advocate nor opponent of HB 11 should not, however, be taken as an indication the bill lacks potential impact or consequence to our markets under their current format and structure,” he said, citing a FERC ruling that determined out-of-market nuclear subsidies were distorting PJM’s capacity market.
Bresler also pushed back against the oversimplification of PJM markets that some testifiers have said values the cheapest price for the next five minutes. He noted the RTO manages multiple markets that balance its resource mix and maintain reliability — not just for the next five minutes but for as many as 15 years in the future.
“It is true that PJM’s markets do not inherently value carbon-free generation,” he said, noting “externalities” like carbon emission are not valued in markets without corresponding state policy setting a price. “The omission of such an externality is by no means unique to PJM’s markets. PJM’s markets can, however, be leveraged to bring the benefits and discipline of competition to a state’s carbon mitigation policy goals, but it requires that state to authorize a cost to be assigned to those carbon emissions.”
CARMEL, Ind. — MISO will reconsider its penalty exemption policy for already submitted generation outages, officials told the Reliability Subcommittee May 2.
Under new outage scheduling rules effective April 1, MISO will exempt from penalties planned outages scheduled 120 days or more in advance. Penalties for outages scheduled 119 days to 14 days in advance occur only when MISO’s maintenance margin tool predicts scant resources to cover operations. Outages scheduled fewer than two weeks in advance are subject to generator accreditation penalties if they don’t alter their outage timeline to move out of MISO-defined periods of capacity concern. The rules also dictate that to receive a penalty exemption, the same unit cannot take multiple outages within a 120-day period. (See FERC OKs MISO Outage Scheduling Rules, DR Testing.)
At the May 2 meeting, stakeholders questioned how MISO might apply accreditation penalties to already planned outages.
Under the new rules, MISO shift operator Trevor Hines said, unit owners must submit a new outage request in order to extend an outage already in progress. For outages yet to begin that require a timeline change, unit owners must submit a change request to MISO, which will reevaluate the requested outage based on maintenance margin supply predictions. The reevaluation would put a unit’s previously approved outage at risk of losing its penalty exemption.
Stakeholders asked why MISO would reevaluate shortened outages, questioning how a truncated outage could possibly impact reliability negatively.
Several asked MISO to consider not putting penalty exemptions at risk when a unit is returned early from a planned outage.
Hines said the reevaluation seeks to gauge the impact on other unit outages. He said it’s extremely unlikely that returning early from an outage would cause a dip in capacity projections.
Jeanna Furnish, manager of outage coordination, said the RTO will reevaluate that piece of the new outage rules. She said the focus is only to make sure MISO is aware of early or delayed returns. Hines promised to return to the Reliability Subcommittee with clarifications.
“We do want you to bring your unit back as soon as it’s appropriate and safe to do so. I am hearing that there’s a perception that this is a bad incentive,” Furnish said.
MISO: $2 Million in Penalties for Jan. 30 LMR Underperformance
Less than a quarter of load-modifying resources responding to a late January emergency event performed to MISO standards, the RTO has concluded.
As a result, MISO will issue nearly $2 million in penalties to 26 market participants for underperformance. The RTO also disqualified 21 LMRs for the remainder of the 2018/19 planning year for nonperformance and will assess them $500,000 in penalties. Penalties will be assessed May 31. When LMRs fail to perform, MISO derates the resource proportionally for the rest of the year.
Though the LMRs managed to meet MISO’s scheduling instructions 75% of the time on average through the worst of the cold snap, the RTO said its measurement and verification criteria found widespread under-delivery of demand reduction megawatts. MISO said only 103 of 502 LMRs called on during the event met MISO’s Tariff-defined compliance standards across all hours of the emergency event. LMR performance gradually improved from about 69% of megawatts requested delivered to 97% over the five hours of LMR use.
MISO analyst Scott Thompson said LMR owners should work on making their availability to the RTO more accurate. While LMRs do not have to be available for scheduling instruction outside of the summer months, MISO does require that LMRs communicate their unavailability via the communication system. LMRs can submit availability up to seven days in advance.
“Correct LMR availability is critical to our real-time operations. LMRs need to ensure that availability aligns with their resource capability,” Thompson said.
Thompson also said many LMRs provided more megawatts than MISO requested. He said while the excess was “a good thing,” it also illustrates that LMRs are not providing their most up-to-date capabilities to the RTO. He also said all LMRs at least acknowledged scheduling instructions on Jan. 30.
Thompson also granted that the MISO Communication System — where LMR owners update their availability — “may not be the prettiest tool we have.” The system is currently undergoing an overhaul as part of MISO’s multiyear effort to replace its current market platform with a new cloud-based, modular platform.
MISO has contacted all 26 LMRs owners facing penalties to discuss the event and their penalty amount, Thompson said.
“Everyone was given an opportunity to share and discuss their performance with MISO,” he said.
Customized Energy Solutions’ Ted Kuhn said LMR penalties might need to be reassessed since MISO now requires LMRs to submit year-round availability. (See MISO LMR Capacity Rules Get FERC Approval.) He said the penalties were originally designed to be harsher than penalties for generators because of LMRs’ shorter availability requirements. Now that LMRs must commit to providing availability in all seasons, Kuhn said MISO might consider LMR penalties that look more like generation penalties.
Kuhn also asked if there was a tipping point of how many LMRs MISO can handle in its resource mix. The use of LMRs, which can only be accessed in a declared emergency, has been steadily growing in the footprint over the last few years. RSC Chair Bill SeDoris said the exploration of an LMR saturation point will be added to the committee’s management plan for discussion in the third quarter of this year.
TULSA, Okla. — SPP’s Regional State Committee last week endorsed a policy white paper intended to ensure all net peak demand is carrying the appropriate capacity, as mandated by the RTO’s resource adequacy requirements.
The Distributed Energy Resource Policy addresses whether each DER is treated strictly as a modifier for a load-responsible entity’s (LRE) load or as capacity. Resources identified under the policy do not meet the requirements for firm capacity or deliverable capacity, as defined by SPP’s Tariff.
The paper defines DERs as either “controllable and dispatchable demand responses” (CDDRs) or “controllable and dispatchable” resources (CDRs).
CDDR is a specific program used to reduce LREs’ forecasted peak demand. The resources are not considered as capacity resources, even if they’re registered in the Integrated Marketplace, and can be controlled or dispatched by SPP or the LRE.
CDRs are defined as LRE-controlled or -dispatched resources not registered in the market or not a designated resource. However, they must be able to attest to having firm delivery to load. CDRs cannot be used as a load modifier unless they are non-controllable or non-dispatchable.
The white paper was unanimously endorsed in December by the Cost Allocation Working Group, which reports to the RSC. It has also been endorsed by the Supply Adequacy Working Group, which drafted the paper, and the Markets and Operations Policy Committee. (See “DER White Paper Gains Endorsement,” SPP MOPC Briefs: April 16-17, 2019.)
The white paper will be turned into a business practice and eventually become an attachment to the Tariff’s Attachment AA.
Adam McKinnie, an economist with the Missouri Public Service Commission, told stakeholders that a joint committee of SPP and MISO regulators is reviewing seamstopics for potential development, as suggested by the RTOs’ market monitors.
McKinnie said the SPP RSC-OMS Seams Liaison Committee will have further discussion with the monitors to develop a scope for the work, which the committee expects to finalize in May.
The topics include how transmission planning assumptions limit the ability to identify joint projects; whether rules unique to each market affect seams; whether transaction scheduling/interface pricing can be improved to ensure beneficial market outcomes; and the effectiveness of the RTOs’ market-to-market process.
The committee will likely meet in person during the National Association of Regulatory Utility Commissioners’ July meeting in Indianapolis.
FERC last week ordered settlement judge procedures for four challenges regarding Emera Maine’s proposed transmission rate, summarily deciding on four other challenges and ordering the utility to make a compliance filing within 30 days (ER15-1429).
Emera Maine Service Area | Emera Maine
The commission’s April 30 order accepted in part the challenges to Emera Maine’s annual update filed in May 2018 by the Maine Public Utilities Commission and a customer group. The update proposed transmission service charges to take effect June 1, 2018, under the company’s Open Access Transmission Tariff (OATT) for the Maine Public District, which includes Aroostook County and a small piece of Penobscot County. (Emera Maine provides service under a separate OATT to the Bangor Hydro District: Hancock, Piscataquis and Washington counties and most of Penobscot County.) The customer group included Eastern Maine Electric Cooperative, Houlton Water Co., the Office of Maine Public Advocate, and Van Buren Light and Power District.
The order summarily decided on the correction of certain acknowledged errors in the 2018 annual update, the exclusion of certain costs for land associated with a project not in service, the exclusion of some distribution costs equipment from transmission rates, and the flowback of excess accumulated deferred income taxes (ADIT).
Settlement Issues
The commission said the remaining issues raise questions of material fact that it could not resolve based on the record before it and should be decided at a hearing if not resolved through settlement. The commission directed the chief administrative law judge to appoint a settlement judge within 15 days of the order.
Among those issues are excluding certain regulatory expenses that the complainants say were improperly allocated or directly assigned to Maine Public District transmission customers and excluding costs that may constitute a double-recovery for amortization of merger-related losses.
Two remaining issues are whether to exclude costs attributed to a rebuild of Line 6901 (which opponents say were incurred prior to MPUC authorization and should be considered as a canceled project) and whether some costs attributed to the rebuild should be attributed to other projects.
New Owner
On March 25, ENMAX Corp. announced it had reached an agreement to purchase Emera Maine for $959 million ($1.286 billion CAD) from parent Emera Inc.
The sale is part of Emera’s plan to reduce corporate debt and fund its three-year capital investment plan. Emera said the deal, and the previously announced sale of its New England gas generation portfolio will raise about $2.1 billion CAD.
ENMAX, based in Calgary, Alberta, owns and operates transmission, distribution and generation facilities throughout the province, with 669,000 electricity, natural gas and renewable energy customers.
