MISO and PJM officials will entertain stakeholder proposals for interregional reliability projects even though none of the 19 reliability upgrades currently planned near the RTOs’ seam offers opportunities for collaboration, RTO officials said last week.
The 10 projects in PJM’s Regional Transmission Expansion Plan include four in American Electric Power’s zone, one in East Kentucky Power Cooperative, three in Duke Energy Ohio/Kentucky, one in Rochelle Municipal Power’s zone in north-center Illinois and one that crosses AEP’s and DEOK’s zones on the border of Ohio and Indiana.
This month’s IPSAC meeting included an estimated timeline for approval of interregional market-efficiency transmission projects between PJM and MISO. | MISO, PJM
The nine projects in MISO’s 2017 MISO Transmission Expansion Plan include two in ITC Transmission’s zone, three in ITC subsidiary Michigan Electric Transmission Co.’s zone, one in Consumers Energy, one in American Transmission Co. and two in MidAmerican Energy.
Interregional reliability projects are analyzed on the basis of avoided costs. Comparisons of the MISO and PJM plans “have not identified any high potential areas for an interregional reliability project,” the RTOs said at the March 24 Interregional Planning Stakeholder Advisory Committee meeting.
PJM is expected to open a proposal window for interregional projects around May. MISO will accept proposals at any time.
Market Efficiency Projects
Meanwhile, the RTOs are evaluating eight market efficiency project proposals submitted in the window that closed Feb. 28. The grid operators received proposals for three upgrades and five greenfield projects from six respondents. The projects ranged in cost from $1 million to $198 million. (See “2017 MEP Identification Underway,” FERC Signals Bulk of NIPSCO Order Work Complete.)
PJM is currently updating its PROMOD model for 2017 and plans to begin calculations around May 1. Stakeholders who have critical energy infrastructure information (CEII) clearance and been approved to receive the model should expect access somewhere around the end of April or the beginning of May, PJM’s Chuck Liebold said.
The project benefits will be compared during the summer to determine interregional cost allocation, and the best projects will be identified in the fall. Recommendations to the respective boards will be made in November or December.
FERC Filings
On Dec. 30, the RTOs filed joint operating agreement changes defining the study process, benefits and interregional cost allocation for targeted market efficiency projects (TMEPs) (ER17-718).
Related tariff filings, defining the new TMEP project type and how costs of such projects would be allocated regionally, are due from each of the RTOs by April 29.
PJM’s Transmission Owners Agreement-Administrative Committee (TOA-AC) closed a 30-day comment window on March 23.
MISO is considering its regional cost allocation rules for such projects in the Regional Expansion Criteria and Benefits Working Group. Stakeholders discussed a proposal based on congestion contribution at the February and March working group meetings. Another working group meeting is tentatively set for April 7 to continue discussions.
AUSTIN, Texas — The growth of distributed energy resources is not yet causing reliability problems, and accurate mapping and localized pricing signals should address concerns in the future, ERCOT said last week.
Based on installed capacity and current growth rates, DER does not pose “an immediate or near-term reliability concern,” the Texas grid operator said in a report released Thursday.
The report says ERCOT’s DERs are “characterized by a combination of low energy prices and an absence of regionwide regulatory incentives, leading to a penetration growth rate” much slower than in California and other regions.
“[We] are making sure we don’t have any reliability issues,” COO Cheryl Mele told members of the Technical Advisory Committee during its monthly meeting. “No current issues exist. That’s not the driver here, other than trying to stay ahead of what can be a growing resource in the ERCOT grid.”
Mele said the ISO’s first priority is to begin discussions with transmission and distribution service providers (TDSPs) about mapping resources larger than 1 MW. Those discussions will take place within the TAC’s Reliability and Operations (ROS) and Wholesale Market subcommittees.
ERCOT estimates there were 900 MW of DER interconnected with the grid as of December 2015, based on annual reports filed at the Public Utility Commission of Texas by TDSPs in competitive-choice areas. Another 200 MW are thought to be deployed in non-opt in entity (NOIE) service territories (those not competing in the ERCOT market).
The ISO said there were about 90 registered DER units, primarily diesel generators and some rooftop solar, as of March.
| Meridian Solar
“As these resources grow, deployment of DER with capacity greater than 1 MW could result in some reliability concerns, depending on their location and level of concentration on the grid,” the report said.
ERCOT currently compensates DERs with zonal prices. Mapping those resources will allow for locational pricing and result in their more appropriate response to transmission constraints.
Definitions
The report said DER can be anything from large, fossil-fueled reciprocating engines to small rooftop solar systems. It includes an updated definition of DER: “Generation, energy storage technology or a combination of the two that is interconnected at or below 60 kV and operates in parallel with the distribution system.”
Further discussion will be needed if the definition is expanded to include demand response, ERCOT said.
The ISO said it believes “the foundation to the reliable and efficient management of this future distributed grid is visibility” through more detailed collection of DER data from TDSPs. It does not propose to model or operate the distribution system, leaving that to the distribution providers.
However, ERCOT said it will work with market participants through the stakeholder process to develop a standardized method for mapping DER units to their loads. The ISO said this will improve situational awareness of DER activity on the grid and “allow for stakeholder consideration of localized pricing signals” to support reliability.
The ISO also proposes working with stakeholders on a process for competitive choice and NOIE distribution providers to monitor the accumulation of clusters of unregistered DER (less than 1 MW). It estimates there are more than 11,000 such facilities in its market and more than 12,000 in NOIE territories.
When the combined connected capacity of these smaller units exceeds an agreed-upon threshold, the TDSPs would work with ERCOT to determine the best method for mapping them.
The new report updates a concept paper published in August 2015 that laid out a potential framework for DER participation in the wholesale market, which identified reliability concerns from a large deployment of DER.
The TAC is expected to refer the report to the ROS and WMS at its April meeting.
BOSTON — The nation’s smallest state doesn’t get to crow very often. But at the New England Restructuring Electricity Roundtable on Friday, Commissioner Carol Grant of Rhode Island’s Office of Energy Resources basked in applause as moderator Jonathan Raab said the state deserved to take a “victory lap” for putting into operation the first offshore windfarm in the U.S.
Not just the U.S., Grant corrected: “The first in the Western Hemisphere.”
The 30-MW Block Island Wind Farm, which began commercial operations in December, is a small step toward meeting the state’s “strategic goal” of 1,000 MW of “clean energy” by 2020, announced by Gov. Gina Raimondo on March 1. The state currently is little more than one-tenth of the way, with 138 MW operational, Grant said.
Although the governor’s challenge is not a legislative mandate, Grant said the legislature has enacted policies that will get Rhode Island halfway to the goal.
“The success of the Block Island Wind Farm is a big help in persuading people that anything is possible,” she said. “The reason we’re really fortunate in this region is that we actually have the ability to collaborate across states. In a small jurisdiction like Rhode Island, that helps because there’s brain power just across the border to the north.”
Grant joined Massachusetts Secretary of Energy and Environmental Affairs Matthew Beaton and Connecticut Deputy Commissioner for Energy Mary Sotos in briefing an audience of policymakers, stakeholders and analysts on how their states are attempting to transition to clean energy with minimal market disruption.
“I wouldn’t underestimate how much the rest of the country looks to New England for our experience in renewable energy and a lot of this thought leadership, experience with regional gas transmission,” Sotos said.
“The core of our energy strategy boils down to three elements: cost, carbon and reliability,” Beaton said. “We have some of the highest costs in the nation and we have to be cognizant of that in the commonwealth. … We have some of the most aggressive carbon reduction goals, the legislature having mandated a 25% reduction by 2020 and 80% reduction by 2050.”
After his presentation, Beaton left for a meeting with Gov. Charlie Baker, while his deputy, Undersecretary Ned Bartlett, stayed behind to answer questions. The first came from Raab, who asked for the main ingredients in the “secret sauce” for a sustainable renewable energy policy. Bartlett answered that “the challenge is to bring the reality of time-differentiated pricing into the solar market,” adding that open and inclusive markets create choices.
ISO-NE Previews Economic Study
A second panel at the roundtable featured Bob Grace, president of consulting firm Sustainable Energy Advantage; Jamie Howland, director of climate and energy analysis for the Acadia Center think tank; and Michael Henderson, ISO-NE director of regional planning and coordination.
Henderson presented a draft version of the RTO’s 2016 Economic Study, soon to be finalized before the grid operator’s Planning Advisory Committee. Phase I of the report analyzes production costs and related metrics, while Phase II discusses several market and operational issues.
Henderson referred his listeners to “a lot of great work being done by the U.S. Department of Energy, and particularly [the National Renewable Energy Laboratory], in modeling what the ISO needs to use in terms of wind and photovoltaics. A lot of those databases are essential to the planning process. But I leave it to you and the developers to come up with the costs. We don’t do that at the ISO.”
Responding to Henderson’s slideshow, Richard Levitan of Levitan & Associates asked, “It looks like there’s an annualized transmission [cost] of $1.5 [billion] to $2 billion to accommodate the build of clean energy and green energy in northern New England. … That transmission result [locks] onshore wind in northern New England.”
Henderson acknowledged that a “very, very large-scale wind development” in northern New England would require a “quite expensive” transmission expansion. “To facilitate it in some of the first steps, the ISO is doing a number of cluster studies now where we’re looking at inputs on the order of 2,400 MW in the north country. … Whether or not it’s economical — the way we want to go in the region — [I] leave that for others: someone who wants to consider policy, costs or metrics other than what we considered in this report.”
Grace used his own metrics to show the increase in renewable supply entering the New England market. “This is the wind projects coming online, this is increasing imports, this is biomass refurbishment. It’s a lot of different things hitting us at once, but it puts us in a new place.”
Howland discussed the potential of incorporating distributed resources into planning through “active load management, which is our term … for smaller-scale demand management that is more flexibly dispatched and automatically dispatched.
“So it could benefit hot-water heaters … and then energy storage in the region,” he said.
The last question of the day went to Henderson: Have you looked at the effect of pricing pressure from solar and wind?
Henderson said the RTO’s analysis found that even with a large-scale development of renewables, “there are still very, very, very significant periods of time when natural gas remains on the margin” in the region.
The analysis also showed renewables on the margin, particularly in light-load periods like May. “And by the way, all that load occurred in the middle of the day, so … there were many days when [energy storage] would be feeding the network at night and drawing from the network during the day, which is kind of the opposite of the way we think of storage operating today,” Henderson said.
Pseudo-Tie Proposals Too Complex for Some Stakeholders
WILMINGTON, Del. — PJM officials Thursday delayed a vote on its proposed standardized agreements for pseudo-ties, but that didn’t stop complaints from stakeholders who say the rules will be overly burdensome.
“From our standpoint, this pseudo-tie business is starting to get out of control,” American Municipal Power’s Ed Tatum said at the Markets and Reliability Committee meeting. “The stakes are getting higher and more draconian.”
The issue is particularly important for AMP, he said, because it put a lot of effort and resources into creating a pseudo-tied unit.
Mike Borgatti of Gabel Associates voiced similar concerns, noting the multiple layers of rules from separate RTOs that they would soon have to follow.
PJM officials had planned last week to seek stakeholder endorsement of a pro forma pseudo-tie agreement, a reimbursement agreement for pseudo-ties into PJM and related Tariff and Operating Agreement revisions.
But PJM’s Jacqui Hugee announced at the beginning of her presentation that the proposals were being removed from voting consideration. She said a “beneficial revision” had been suggested at the last minute that PJM wanted to include in the proposal, though she didn’t detail what the proposal was.
NRG Energy’s Neal Fitch walked through the entire document in his reintroduction for approval of a problem statement and issue charge on investigating replacement capacity, but it was only one word that truly hung up other stakeholders. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)
Characterizing the amount of cleared replacement capacity as “high” didn’t sit well with CPower’s Bruce Campbell. “It’s data,” he said.
“Are you willing to negotiate on the fly here? Why don’t we just delete the word high?” Fitch asked.
While Campbell considered that, others stepped in with an assortment of suggestions. The revision attempts eventually resulted in minor clarifications that removed the word “high.”
Tom Rutigliano of consulting firm Achieving Equilibrium had concerns with requiring “resources to be deemed physical” and asked that the benefits of replacement transactions also be noted in the problem statement. Fitch declined, saying they could be discussed within the group assigned to the problem statement.
“I will make my commitment to you that, to the extent that you or your clients want to identify benefits, you are more than welcome to,” he said.
The problem statement was approved by acclamation with 10 objections and three abstentions.
IMM’s Proposed Fuel-Cost Policy Changes Denied
After months of debate, rule revisions in Manual 15 and the Operating Agreement regarding hourly offers and fuel-cost policies received committee endorsement, but not without a lengthy final debate. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)
Independent Market Monitor Joe Bowring proposed changes that concerned stakeholders and PJM, including posting its evaluation in the online Member Information Reporting Application (MIRA), reserving the right to communicate information to PJM that it doesn’t communicate to the market seller and codifying in the rules that it will provide PJM with a recommendation whether to approve or reject a proposed policy.
Catherine Tyler Mooney, who works for the IMM firm Monitoring Analytics, explained that the changes would provide transparency regarding the Monitor’s participation in the fuel-cost policy approval process, addressing a source of confusion for stakeholders. She said PJM proposed similar additions to Manual 15 as a result of conversations with the IMM. The key differences in PJM’s and the IMM’s versions were the reference to MIRA and the inclusion of the Monitor’s recommendation, which was suggested by FERC in its Feb. 3 order.
Stu Bresler, PJM’s senior vice president of operations and markets, objected to referencing MIRA and the Monitor’s recommendation in the manual because it’s the only manual that requires Board of Managers approval for revisions. If technology or procedures change, it will require a long process to update the manual, he said. The Monitor is welcome to provide its recommendation voluntarily to PJM, but the Tariff doesn’t require it, so the manual shouldn’t require something different, Bresler said.
Bowring said MIRA is mentioned elsewhere in the manual, so it would need to be revised anyway if methods change, and that PJM should not block it from committing itself to providing more information than required.
Stakeholders were concerned that PJM and the Monitor were far apart on this issue, but PJM’s Suzanne Daugherty assured them that wasn’t so.
“I don’t think [the difference] is big. I think it’s specific,” she said.
Stakeholders remained concerned that approval from PJM doesn’t necessarily guarantee approval from the Monitor, which might still make a referral to FERC.
“It’s like your [PJM] approval doesn’t mean anything,” one stakeholder said.
Stakeholders were also concerned with the Monitor suggesting it might keep information from them.
“I’m struggling with what you would tell to PJM that you wouldn’t tell to the market seller,” GT Power Group’s Dave Pratzon said. “If you only share the details of why [a policy passed or failed] to PJM, you put the market seller in a tough position.”
“I understand that you want to know everything that’s said to PJM about your fuel-cost policy,” Mooney acknowledged, adding that the Monitor makes all of its issues with a fuel-cost policy clear to both the market seller and PJM. Bowring later explained as an example that the Monitor might provide information to PJM of discussions it had with the market seller, so the information would be redundant for the market seller.
Mooney concluded the discussion by stating that “when PJM proposes changes to the manual to provide the details of how it implements the Tariff, it is allowed. When the Monitor wants to provide details of how it performs its responsibilities, it is not allowed.”
The manual and OA revisions were ultimately approved following minor language changes.
Transmission Owners, Customers Clash over Infrastructure Replacement
PJM’s Paul McGlynn presented an update on work in the Transmission Replacement Processes Senior Task Force that has not been halted by FERC’s Order to Show Cause. In August, the commission questioned whether PJM transmission owners are complying with their local transmission planning obligations, specifically with respect to supplemental projects, as required by Order 890. (See “Transmission Replacement Activity Hiatus Extended,” PJM Markets and Reliability and Members Committees Briefs.)
McGlynn said work has continued on a Transmission Cost Information Center, which the task force feels isn’t covered under the order. Sub-groups have completed the design of the tool, and PJM will construct it, he said.
Despite the hiatus, tension in the task force remains, which was highlighted by an exchange between Exelon’s Gloria Godson, who represented the PJM TOs, and AMP’s Tatum. Godson stated that PJM TOs have a strong commitment to transparency and provide their assumptions, methodologies and detailed project information as appropriate. However, she cautioned against stakeholders expecting uniformity from TOs because their processes are not all the same.
“Companies may do things differently and uniformity may not be an appropriate request,” she said.
Tatum clarified that his impression has been that transmission customers are not seeking uniformity. Rather, he argued, customers are asking for the detailed information necessary to be comfortable with owners’ infrastructure upgrade and replacement proposals. Another $1 billion in supplemental projects has been proposed, he noted, along with $860 million in “immediate need” projects that bypass the Order 1000 competitive bidding process.
Godson took exception to Tatum’s call for additional detail, saying he has “hijacked” the Sub-Regional Transmission Expansion Planning Committee in the past and “held court” for the entire meeting to make his point. Tatum rejected her characterization, and John Farber of the Delaware Public Service Commission staff interjected in his defense.
“Not being an engineer, I rely on Ed’s input,” Farber said. “So I don’t consider it holding court.”
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 13: Emergency Operations. Revisions developed in response to new NERC standards.
A problem statement and issue charge presented by Bob O’Connell of Panda Power Funds regarding calculation of opportunity costs for units with less than three years of historical LMPs. The initiative will evaluate whether the opportunity cost calculator included in PJM’s Markets Gateway produces the same results as that used by the Monitor. It also will consider updating the calculators to reflect the nonperformance penalties under Capacity Performance. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)
A draft charter for the Modeling Generation Senior Task Force, an outgrowth of the Combined Cycle Owners User Group, which concluded that a more detailed generator model for combined cycle units might also be applicable to other steam units. The task force will consider expanding the model used by PJM to improve the ability to represent components of all generation types.
A draft charter for the Incremental Auction Senior Task Force, which will consider changes to the Incremental Auction process and structure, excess capacity sales, and PJM participation in the auctions.
Members Committee
PJM Outlines Potential Impact of FERC Rulings on Auctions
PJM’s Jen Tribulski explained the implications of several FERC proceedings on PJM’s Base Residual Auction in May.
FERC staff issued an order on March 21 that accepted PJM’s November filing on seasonal capacity and resource aggregation. Tribulski said this allows PJM to apply the new rules to the auction, but also that the commission could review the case and require refunds if it comes to a different conclusion when it regains a quorum. The auction, which will begin on May 10, is for the 2020/21 delivery year. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)
Tribulski acknowledged that the staff order was vague regarding what portions of the order it thought might not be just and reasonable. “It was boilerplate language, but I agree with you, we don’t know what aspect if any they are really honing in on,” she said.
NRG’s Brian Kauffman asked what was meant by FERC’s suspension for a “nominal period.” Tribulski said it was a one-day “flash” suspension, but didn’t offer additional details regarding FERC’s intentions.
She also explained the potential implications of PJM’s March 9 filing regarding external capacity enhancements. If FERC doesn’t issue an order by May 9, the rules automatically go into effect and will be applicable for the BRA starting the next day. If FERC orders a suspension subject to refund and further proceedings that expires prior to the auction, PJM will still implement the new rules, Tribulski said. However, if FERC issues a deficiency letter or a suspension that continues beyond the auction date, the BRA will be conducted under the existing rules, she said.
VALLEY FORGE, Pa. — It took months to get PJM’s latest stakeholder initiative on the capacity market started, but there is no shortage of interest now that it’s begun.
More than 20 stakeholders attended the Capacity Construct/Public Policy Senior Task Force’s second meeting on Monday — with another 100 conferencing in — to spend more than five hours discussing 63 design-concept suggestions for revising the RTO’s capacity market.
Early on in Monday’s session, Steve Lieberman of American Municipal Power asked for confirmation that a suggested November timeline for deliverables is only a general target and not a specific goal. Dave Pratzon of GT Power Group suggested that such a deadline would allow revisions to be in place for next year’s Base Residual Auction.
Lieberman said the main focus should be to ensure the revisions are “complete and not half … complete.”
“There’s another word I would usually use there,” he added.
PJM’s Dave Anders, who facilitated the meeting, thanked him for not enunciating it.
One stakeholder noted that FERC has scheduled a technical conference May 1-2 on the interplay of state policies and wholesale markets in PJM, NYISO and ISO-NE (AD17-11). “If there is a compliance obligation that comes out of that tech conference, are we able to expand this task force to discuss it?” she asked.
Anders confirmed that the task force can vote to expand its scope in such a situation, but it must receive approval from the Markets and Reliability Committee to revise its charter. He went on to set other ground rules, including how the wide variety of stakeholder interests in this process will be handled. Instead of allowing “diametrically opposed” goals to both be approved as independent objectives of the group, he proposed using a poll to evaluate levels of support for each option.
“We’ll expose where the differences are,” he said.
Stakeholders took immediate interest in hashing out the definition of “missing money,” which NRG Energy’s Pete Fuller said should adhere to its original concept of focusing on revenue levels that support future investment, not on ensuring individual units are able to break even on a daily basis.
“It’s much more of a market-confidence stance,” he said.
Mike Cocco of Old Dominion Electric Cooperative agreed that the phrase “has lots of different meanings to lots of different people.”
To him, “missing money” means the additional revenue source from the capacity market that is necessary with a cost capped energy market to achieve the desired level of reliability. It does not mean revenue adequacy for all generators. He said the capacity market should provide the designed level of reliability at the lowest possible cost.
PJM’s Tim Burdis provided a review of state policy initiatives that are impacting, or could impact, the RTO’s capacity market. He said such initiatives tend to fall into four categories: standards to attain, such as emissions reductions; direct contracts; appropriations such as zero-emissions credits; and regulations.
Exelon’s Jason Barker took issue with categorizing ZECs as appropriations, saying they are more closely aligned with renewable energy credits, which Burdis had categorized as “standard attainments.”
The task force’s next meeting will be April 21. The location has not been set, but Anders confirmed that it won’t be at PJM’s offices due to scheduling conflicts.
NEW ORLEANS — MISO will soon make a filing to add more confidentiality and legal definitions to its alternative dispute resolution process, stakeholders learned at the March 22 Advisory Committee meeting.
With the changes, data exchanged during alternative dispute resolution meetings covered by nondisclosure agreements will be treated by the RTO as confidential or as Critical Energy Infrastructure Information.
MISO will invite other entities to participate in resolution meetings if their “participation is indispensable to resolution of the dispute.” The RTO will also be allowed to dismiss the dispute or “discontinue the informal dispute resolution process if such entity declines to participate in the dispute.”
MISO Deputy General Counsel Eric Stephens said the RTO already uses the concept of indispensable parties but is looking to codify it.
The revisions also clarify MISO’s ability to grant relief such as damages, which is “subject to the potential need for a waiver from FERC,” the RTO said.
MISO will also pass its responsibilities to recommend sanctions and give referrals for investigations to its Independent Market Monitor. Stephens said the RTO did not think it was appropriate to recommend sanctions or instigate investigations as a result of the resolution process. The new language also clarifies that MISO will not facilitate dispute procedures for contracts that are not service agreements or rate schedules under its Tariff.
MISO will also extend the initial timeframe for final resolution of an informal dispute from 90 to 180 days. “Our experience over the last two years has taught us that these take on average about 180 days,” Stephens said. He added that the timeframe could be extended by another 90 days before the RTO ends attempts to facilitate discussions, and the dispute is either dropped or escalated into a court proceeding.
The changes will be made to Tariff Attachment HH. (See “MISO Stakeholders to Hear Changes to Alternative Dispute Resolution,” MISO Steering Committee Briefs.)
Stephens said MISO will accept stakeholder input through April 12 and plans to file the new procedures for FERC approval by May 1.
NEW ORLEANS — In its first-ever current events discussion, the MISO Advisory Committee focused on moving on after the RTO’s failed capacity auction redesign.
MISO Executive Director of Market Design Jeff Bladen told the committee on March 22 that the RTO is open to revisiting discussion on another capacity auction solution only if stakeholders want it.
On Feb. 2, FERC rejected MISO’s proposed Competitive Retail Solution, which would have applied a sloped demand curve and three-year forward capacity auction to the RTO’s retail-choice areas.
The commission said bifurcating the RTO’s capacity market by holding a forward capacity auction for competitive load three years prior to the current Planning Resource Auction would create too much price volatility and uncertainty. A market-wide clearing process that operates within a single set of transmission capability constraints and supply offers is more efficient than a bifurcated market, FERC said. (See MISO Won’t Seek Rehearing on Auction Redesign.)
Entergy Vice President Matt Brown and other stakeholders said MISO should abandon its search for a solution to resource adequacy concerns in the competitive areas and focus on other ways to improve the PRA, including creating external resource zones and adding a seasonal aspect.
“I think our stakeholders have been very clear — and FERC has been very clear — that an Eastern-style capacity market is not right for MISO,” Brown said. “From our perspective … it’s time to let this go.”
NRG Energy’s Tia Elliott said Illinois’ legislation subsidizing nuclear plants and a Michigan law increasing the state’s renewable portfolio standard should not be considered a fix for climate warming concerns. Although the Trump administration hopes to kill EPA’s Clean Power Plan, MISO could be faced with similar environmental regulations in the future, she said. “The political landscape could swing again, and we could be back in the same situation.”
Minnesota Public Utilities Commissioner Matt Schuerger reminded stakeholders that ensuring adequate capacity is the responsibility of individual states.
OMS-MISO Survey Dispute Revisited
The committee also returned to stakeholders’ accusations that MISO and the Organization of MISO States have overstated a possible capacity shortfall through their joint resource adequacy survey. (See Differences Persist over OMS-MISO Survey Improvements.)
After a stakeholder pointed out that ERCOT was sued last year in an ongoing fraud case over misleading capacity reports, OMS member and Arkansas Public Service Commission Chairman Ted Thomas defended the survey.
“There isn’t a perfect way to do it. It’s a survey; it’s not a utility planning document,” Thomas said, adding that the survey was meant to help states understand their neighbors’ actions as they develop their own integrated resource plans.
Thomas said that if a utility is “dumb enough” to use the survey as a planning document, the utility deserves to get sued, not the producers of the survey. He also blamed local media for promoting a sky-is-falling narrative, saying reporters often don’t understand the survey results.
“Try explaining this stuff to a newspaper reporter,” he griped.
The economic and environmental challenges of replacing Indian Point are formidable. So are the grid reliability challenges.
Any attempt to minimize these impacts is a disservice to New Yorkers who face, at best, an uncertain energy future due to rising prices, higher carbon and other toxic emissions, and lower grid reliability.
For more than 40 years, Indian Point has been the backbone of New York’s electricity system. It generates 2,069 MW of power, providing 25% of the electricity for New York City and the surrounding region. In fact, the plant generates enough power for 2 million New York homes and the same amount typically produced by four or five natural gas natural plants.
Indian Point
Except for scheduled refueling outages, it generates baseload power 90% of the time, with no emissions. Even though we have up to four years to replace Indian Point’s power, it is very difficult to get anything approved and built in New York, including renewable energy facilities, in such a relatively short period of time.
Price Pressures
Replacing the supply of Indian Point’s power to meet the growing demand for electricity in New York will not be easy. But it is not only the resulting supply gap that puts upward pressure on electric power prices.
Improvements in the transmission grid necessary to bring new power to New Yorkers will be enormously expensive. Such infrastructure investments are particularly necessary and costly if the power must be transported over long distances, or if there is greater reliance on intermittent renewable power sources.
Other power sources are also subject to sharp price fluctuations. During the hottest days of the summer and the coldest of the winter, it is difficult for New York to get sufficient amounts of out-of-state natural gas, which also drives up prices at these critical times.
Also, the massive amount of renewable energy power needed to replace Indian Point is daunting and simply not practical. Replacing 1,000 MW, less than half of Indian Point’s generation, with solar power requires 45 to 75 square miles of land and 260 to 360 square miles for wind power.[1] For perspective, Manhattan is only 22.8 square miles of land.
Emissions
Indian Point also generates tremendous amounts of electricity with nearly zero carbon or other toxic emissions. The other critical question is not if toxic emissions will increase when Indian Point closes, but by how much.
California, Florida, Wisconsin and Vermont have all experienced greater reliance on fossil fuels and very significant increases in pollution after closing nuclear power plants.[2]
In fact, when advocating for New York’s upstate nuclear plants, Chairman of Energy and Finance for New York Richard Kauffman said, “Without our upstate nuclear fleet, 31 million tons of CO2 would be released in just two years, the equivalent of adding 6 million cars to the road — resulting in an additional $1.4 billion in public health and other societal costs. New York would have to rely on more expensive and dirtier power.”[3]
Grid Reliability
New York is fortunate that Indian Point will be operating until 2021. In fact, were the plant to close today, the state’s grid would not be reliable, according to NYISO.[4]
The costs of blackouts are enormous. The New York City comptroller found that the 2003 blackout cost the city more than $1 billion in lost wages, spoiled food and other costs.[5]
Blackouts are also a danger to public health. Researchers from Johns Hopkins University also studied the 2003 blackout and documented that it resulted in 90 deaths.[6]
Looking beyond the societal and economic costs of daylong blackouts, having an unreliable grid will make New York a very unattractive place to do business, especially for companies that are high-intensity users of electricity, such as manufacturers and high-tech companies.
Looking Ahead
Plans by state policymakers to address the issues resulting from the early shutdown of Indian Point should be transparent and thoughtful. Input from affected communities and organized labor are a must. We must address both environmental and economic issues to minimize adverse impacts on the regional economy and the ecology. Believing that Indian Point’s power can simply be replaced by energy efficiency or an enormous increase in renewables is not realistic.
New York consumers and businesses need to brace for the impact that Indian Point’s closing will have and be fully and clearly informed of what the impact will be in terms of monthly electric utility bills, air quality, and grid reliability.
Rob DiFrancesco is the executive director of the New York Affordable Reliable Electricity Alliance (New York AREA), a diverse organization of major business, labor, and community groups including Entergy, the owner-operator of Indian Point. Founded in 2003, New York AREA’s mission is to ensure that New York has an ample and reliable electricity supply, and economic prosperity for years to come.
[1]Nuclear Energy Institute, “Land Requirements for Carbon-Free Technologies,” Analysis, June 2015. Information appears in a chart at the beginning of the document and is discussed throughout. Retrieved on March 14, 2017 https://www.nei.org/CorporateSite/media/filefolder/Policy/Papers/Land_Use_Carbon_Free_Technologies.pdf?ext=.pdf
[2]Nuclear Energy Institute, “Can California Cut Its Carbon Without Nuclear? Doubtful.” Analysis, June 30, 2016. Items appear in charts and are discussed throughout the text. Retrieved on March 13, 2017 https://www.nei.org/News-Media/News/News-Archives/Can-California-Cut-Its-Carbon-Without-Nuclear-Doub
[3]NY State of Politics, “Cuomo Energy Czar Blasts Anti-Nuke Subsidy Campaign,” News story with accompanying link to the letter from Richard Kauffman, October 5, 2016. Information appears in the fifth paragraph of the letter. Retrieved on March 10, 2017 http://www.nystateofpolitics.com/2016/10/cuomo-energy-czar-blasts-anti-nuke-subsidy-campaign/
[5]USA Today/Associated Press, “Blackout cost estimated at up to $6 billion,” August 10, 2003. Information appears in the 13th paragraph. Retrieved on March 10, 2017 http://usatoday30.usatoday.com/news/nation/2003-08-19-blackout-cost_x.htm
[6]Reuters, “Spike in deaths blamed on 2003 New York blackout,” January 27, 2012. Information is summarized in the eighth paragraph and discussed throughout the article. Retrieved on March 13, 2017 http://www.reuters.com/article/us-blackout-newyork-idUSTRE80Q07G20120127
Bernard W. Dan resigned unexpectedly from NYISO’s Board of Directors last week, less than a year after joining.
Dan
Dan announced his resignation at the board’s March 21 meeting. NYISO Chairman Michael Bemis relayed the news to stakeholders at the board’s Liaison Committee meeting afterward.
“Mr. Dan was interested in pursuing other opportunities,” NYISO spokesman Dave Flanagan confirmed. “He felt it was best to leave the board to avoid any potential conflicts.”
Flanagan declined to provide any details about Dan’s plans. Asked about plans to replace Dan on the 10-member board, Flanagan said, “Stakeholders will work that out through their normal process.”
Dan did not respond to an email asking for comment.
Turnaround Exec
Dan’s LinkedIn page describes him as a “Board Advisor, CEO and Turnaround Executive.”
He has been a senior advisor to the board of directors of OneChronos Group since 2015. The company, a startup that has gone through Y Combinator’s accelerator program, says it is building a new type of financial exchange that will make trading cheaper.
Dan was the CEO of Sun Holdings, which trades in stocks, currencies, futures and bonds, for five years ending in July 2015.
Dan also had a nearly two-year stint at MF Global, a broker of exchange-traded futures and options. After joining in June 2008 as the chief operating officer for North America, he rose to become CEO. He resigned in March 2010 and was replaced by former New Jersey Gov. Jon Corzine. The company, which filed for bankruptcy protection in October 2011, settled a lawsuit with its auditors, PricewaterhouseCoopers, on March 23.
Before joining MF Global, Dan was CEO of the Chicago Board of Trade, taking part in its initial public offering in 2005 and its sale to the Chicago Mercantile Exchange in 2007.
AUSTIN, Texas — The ERCOT Technical Advisory Committee agreed last week not to pursue a change in how ISO operators commit and dispatch resources, agreeing with a Wholesale Market Subcommittee study that the software changes required would not produce sufficient production cost savings.
The TAC then asked the subcommittee to begin working on real-time co-optimization of reserves.
The ISO developed an in-house software platform to perform multi-interval real-time market (MIRTM) simulations for selected operating days from 2015 and 2016. The study found MIRTM is feasible for both fast-responding generation resources and load resources with temporal constraints. But the feasibility study concluded that “the estimated cost[s] are in excess of the measured benefits and therefore insufficient to support [moving] forward with MIRTM at this time.”
ERCOT’s real-time market dispatches and prices energy in single five-minute intervals and does not consider potential changes in system conditions more than five minutes into the future. As a result, it is unable to coordinate the commitment of combustion turbines and demand response resources that are available within 10 to 30 minutes but unable to respond within five minutes.
The study was ordered to determine whether the ISO could improve the efficiency of its short-term commitment decisions by analyzing multiple consecutive five-minute intervals to determine the most economical commitment and dispatch.
ERCOT will share the study with the Board of Directors during its April 4 meeting. If approved, the study will be filed with the Public Utility Commission of Texas.
The WMS now finds itself freed up to take on real-time co-optimization, which shifts the responsibility for providing reserve services to online generation resources with the lowest incremental energy cost. Co-optimization has been the subject of discussion at the PUC, most recently during its last open meeting. (See Texas PUC Wary of Using ERS to Avoid Local Blackouts.)
“We’ve been waiting for [MIRTM] to clear the decks, and the decks have been cleared,” Morgan Stanley’s Clayton Greer said.
“We have an obligation at this point to explore this,” Citigroup’s Eric Goff said. “[The PUC] has given various hints that they’d like additional information. As a stakeholder body, I believe we have the obligation to make those hints and wishes reality.”
TAC Vice Chair Bob Helton, of Dynegy, agreed. With members raising concern over ERCOT’s estimate of $20 million for software changes, he directed the WMS to define a study scope and what components of co-optimization should be analyzed.
Staff Shares Draft Principles for Market Continuity
ERCOT staff shared with the TAC a draft of principles to address the ISO’s lack of guidelines on restarting its markets following outages. The principles do not change existing black start procedures.
Staff raised the issue last year with the board and conducted a workshop in May to frame the discussion around gaps in the processes.
The principles include:
Prioritizing the real-time market’s restart before other markets or activities;
Starting congestion revenue rights auctions and other functions only after the real-time and day-ahead markets are restored;
Expecting limited settlements functionality during market restoration;
Payments being made in “as timely a manner as possible;”
Relaxing credit requirements and releasing cash or other collateral to provide short-term liquidity to market participants;
Seeking emergency funding to pay resources before other alternatives are considered; and
Uplifting market restart costs on a load-ratio share basis after market recovery.
ERCOT staff is expected to build on the principles with more formal procedures.
“This is a good start. ERCOT didn’t have transparent principles before,” Direct Energy’s Read Comstock said.
Committee Approves 16 Revision Requests
The TAC also approved nine other NPRRs, three revisions to the Planning Guide (PGRRs), two revisions to the Load Profiling Guide (LPGRRs) and revisions to the Retail Market Guide (RMGRR) and Nodal Operating Guide (NOGRR).
NPRR776: Aligns protocol language with currently used verbal communication practices between transmission service providers (TSPs), qualified scheduling entities (QSEs) and generation resources. Also identifies new requirements for data TSPs provide to ERCOT, QSEs and the generators. The committee tabled NOGRR167, which aligns the Nodal Operating Guide with NPRR776.
NPRR799: Requires that TSPs and resource entities — generation and load that can reduce electricity usage or provide ancillary services — submit updates to the outage scheduler within one hour of the facility’s outage start or completion.
NPRR802: Clarifies current settlement practices and protocol language, including how reliability unit commitment resources opting out of settlement are treated in calculating real-time online reserve capacity.
NPRR804: Clarifies that ERCOT should post both a systemwide network model and a set of station one-line diagrams, and that the model posting does not disclose data about private-use networks.
NPRR808: Extends the CRR auction process into the third year forward, revises the percentages sold in the auction’s long-term sequence and aligns modifying load zones to the timetable.
NPRR809: Defines the terms “initial energization” and “initial synchronization;” adds a reference to a quarterly stability assessment for interconnecting generation resources when evaluating the need for a generic transmission constraint; and clarifies a resource’s requirements prior to initial synchronization.
NPRR810: Removes the applicability of a reliability-must-run agreement’s incentive factor to reservation and transportation costs associated with firm fuel supplies, and accordingly separates costs in the RMR standby payment equation.
NPRR812: Clarifies short-term system adequacy report language; aligns protocol language with current ERCOT practices and Public Utility Commission of Texas rules for posting resource and load information; and modifies the requirement for posting a RUC initial-conditions report to only include the process as originally intended in NPRR314.
NPRR813: Requires references to service organization controls for the annual ERCOT market settlement audits.
NOGRR166: Eliminates a redundant report of daily operational information that can be found elsewhere on the Market Information System.
PGRR052: Ensures a new generating unit’s operating limits are established by setting a timeline for stability studies following a full interconnection study (FIS), incorporating model data or transmission system changes, not known during the FIS, before a new unit is brought online.
PGRR054: Clarifies the content, review period and process for posting an FIS’ results, and establishes a process for identifying, proposing and implementing solutions to stability issues identified during the FIS.
PGRR055: Defines the process for revising the Planning Guide to first consider PGRRs at the subcommittee level.
RMGRR144: Eliminates the requirement for transmission and/or distribution service providers to maintain a secure list of retail electric provider data numbering systems for all electric service identifiers (ESI IDs) with “switch-holds” — measures to prevent customers with unpaid bills from changing retail electricity providers.
LPGRR060: Provides additional clarification to the load-profiling guide by removing “orphaned language” not captured in LPGRR057, which was approved by the TAC in October.
LPGRR061: Modifies the annual validation timelines for residential and business ESI IDs by starting the validation activities on March 30 and concluding them on Sept. 30 of each calendar year.
