ERCOT is “much more likely” to deal with “emergency-alert type conditions” this summer given the system’s 7.4% reserve margin, CEO Bill Magness told his Board of Directors and the Texas Public Utility Commission last week.
“With the lower reserve margin, you’re just increasing your risk that any kind of circumstances — low wind, generation outages, extreme weather — could cause challenges on the system this summer,” Magness said during the board’s Feb. 12 bimonthly meeting. “That means bringing on resources we have available and the tools for dealing with that.”
ERCOT CEO Bill Magness (right) details preparations being made for the summer months.
Magness said the city of Garland’s December decision to indefinitely mothball the 470-MW coal-fired Gibbons Creek Generating Station has “effectively reduced” ERCOT’s reserve margin from 8.1%. The grid operator, which has a target planning reserve margin of 13.75%, avoided taking emergency measures last summer despite extreme heat and an 11% reserve margin.
The board took the news calmly as Magness detailed preparations being made for the summer months. Chief among those is the creation of a Gas-Electric Working Group, designed to facilitate reliability coordination between the natural gas and electric industries and ensure clear communication.
GEWG Chair Chad Thompson, ERCOT’s senior manager of operations engineering and support, stressed during the group’s first meeting Feb. 15 that the grid operator doesn’t want to interfere with existing relationships.
“[We] don’t want to get in the middle of your business. ERCOT wants to be a facilitator,” Thompson said.
The GEWG stems from a November gathering that PUC Chair DeAnn Walker held with several trade associations, municipalities, and other members of the electric and gas sectors. The PUC encouraged owners of gas-fired generation facilities, gas pipelines and electric utilities that serve the pipelines to participate in the working group.
“If we do get into a load-shed event, we want a clear understanding of where the critical facilities are,” Thompson said.
Walker has also convened meetings with ERCOT market participants and other stakeholders, similar to what she did before last summer. During the commission’s Feb. 7 open meeting, she said she has received significant input, “Some of it the same as last year.”
ERCOT has gathered transmission owners to ask that any planned outages be limited to off-peak periods and that restoration times be shortened. It will release its final seasonal assessment of resource adequacy on March 5, providing a scenario-based analysis of its summer expectations.
Texas Competitive Power Advocates, a trade organization representing about 60% of Texas generation, has said its member companies are planning to invest $100 million in existing facilities in ERCOT to prepare their fleets for summer demand.
ERCOT’s load and demand projections through 2023 | ERCOT
Advanced Energy Economy and the Sustainable FERC Project last week petitioned FERC for a declaratory order regarding ISO-NE’s possible attempt to retroactively apply new performance standards that would affect the eligibility of energy efficiency resources participating in the RTO’s capacity market.
The petitioners also asked the commission to clarify the appropriate process for changing the terms of market eligibility for EE resources.
ISO-NE’s graph shows the value of energy efficiency resources. | ISO-NE
The Feb. 13 filing cited a series of recent phone calls made by ISO-NE staff to Forward Capacity Market participants with qualified EE capacity resources. During those calls, staff members said that the RTO intends to change how it measures the demand reduction value of EE resources for participation in the FCM.
“ISO-NE staff indicated that the ISO may potentially do so retroactively and without seeking commission approval for these changes, even though the contemplated changes could significantly change the quantity of the resources that have already qualified for, and cleared, the most recent Forward Capacity Auction, FCA 13,” the groups said.
The complaint specifically alleges that the changes may include new “net-to-gross” conversion factors to revalue EE resources, factors “never previously required of, nor imposed on, market participants,” nor defined or described in the RTO’s Tariff or manuals.
The petitioners pointed out those factors were not included in most market participants’ FCA 13 measurement and verification documents — “the qualification determinations which were filed with, and have been accepted by, the commission for participation in FCA 13.”
“ISO-NE has created uncertainty about the methodology it will use to calculate demand resource values going forward, and this is causing real and continuing harm to the capacity market,” the petitioners wrote.
The RTO says the discussed changes are not a settled matter.
“We raised the matter of measurement and verification with EE providers recently and intend to have a more full and complete discussion before any changes would be made,” ISO-NE spokesman Matthew Kakley said.
But one key environmental group is skeptical of the RTO’s intent.
“New England’s grid operator is proposing to change the rules midstream and out of the public eye, without explaining what the new rules would be,” said Bruce Ho, a senior advocate at the Natural Resources Defense Council. “This is absurd. Federal regulators need to step in and ensure that energy efficiency resources get a chance to compete fairly in the capacity market. Any changes to the established market rules must be subject to careful consideration and review.”
The two complainants said they filed the petition to “provide greater certainty” to New England EE resources in the near future.
“The measurement and verification changes proposed by ISO-NE in its phone calls would substantially impact the energy efficiency market in New England, reducing the value of energy efficiency resources in the FCM, driving up prices and ultimately forcing ratepayers to pay higher prices,” they said. “Petitioners and our members and partners hope to work cooperatively to address these issues with ISO-NE in the stakeholder process moving forward.”
ERCOT CEO Bill Magness said last week that the grid operator will use favorable budget variances to fund the addition of real-time co-optimization (RTC), as it has been directed to do by the Texas Public Utility Commission.
ERCOT’s Board of Directors gathers for its February meeting.
In delivering his CEO report to the ERCOT Board of Directors during its regular bimonthly meeting Feb. 12, Magness said staff have identified $43.7 million in favorable variances that would cover the project’s estimated $40 million cost. Much of the variance is because of aggressive interest rate assumptions set in 2017, Magness said.
The PUC last month directed ERCOT to proceed with RTC’s implementation. Commission Chair DeAnn Walker has said that RTC would bring economic and operational benefits to the market. (See Texas PUC Responds to Shrinking Reserve Margin.)
Staff have said it will take four to five years to implement RTC, the process of procuring energy and ancillary services simultaneously in the real-time market every five minutes to find the most cost-effective solution for both requirements.
Magness said he would provide a clearer picture during the board’s April meeting, following a financial audit that determines the final variances.
“As we know from past projects, until we get the protocols written and we know what we’re building, it’s hard to get a much better estimate than the one we’ve provided,” he said.
As for the interest assumptions, Magness said, “We’ll be reupping those and changing those to where we accurately believe we are in 2020 and 2021.”
Staff Present Transmission Planning Report
Jeff Billo, ERCOT’s senior manager of transmission planning, briefed the board on the grid operator’s transmission planning practices, assuring them that staff carefully match projects and needs.
“We take our job very seriously, and we only build what needs to be built,” he said.
Annual transmission costs — charged to consumers to pay for ERCOT’s system — have steadily risen from about $1.3 billion in 2008 to nearly $3.5 billion in 2017. Billo said the rise can be attributed to the Competitive Renewable Energy Zone (CREZ) project, natural load growth and Far West Texas load growth.
According to NERC’s 2018 long-term reliability assessment, ERCOT’s 1.76% 10-year forecasted growth rate trails only that of the Western Electricity Coordinating Council’s Rocky Mountain Reserve Group subregion (1.8%).
“A strong economy leads to load growth,” Billo said.
ERCOT’s Jeff Billo explains the grid operator’s transmission planning processes.
Much of the CREZ project, a 345-kV infrastructure build connecting wind-rich West Texas with urban centers, went into service in 2013. Almost $5 billion was invested that year alone, resulting in a $700 million one-time bump in transmission costs, he said. However, CREZ has also provided a strong 345-kV backbone as ERCOT works to meet the growing petroleum-fueled load growth in the Permian Basin, where peak demand has doubled since 2009.
“Without CREZ, we would have seen a significant amount of transmission needed for far West Texas,” Billo said. “It’s been a challenge keeping up with that growth.”
He said transmission upgrades incorporate double-circuit capability and higher-voltage lines to be able to meet even higher loads in the future. ERCOT has conducted special assessments to try and get ahead of that higher growth.
“Based on 2018 forecasts and studies, our plan is sufficient,” Billo said.
A wave of wind and solar projects in West Texas — “There’s more wind and solar existing or planned than CREZ’s capacity,” Billo said — and increased LNG activity on the Gulf Coast will result in more load growth and congestion. ERCOT has already approved the Freeport Master Plan Project to address LNG growth, and the work to integrate Lubbock Power & Light’s load is expected to relieve constraints in that region. (See “Regulators Grant Preliminary Approval to Sharyland-LP&L Projects,” Texas Public Utility Commission Briefs: Feb. 7, 2019.)
Board Approves Leadership for 2019
Magness introduced Jeyant Tamby to the directors as an ERCOT senior vice president and its first chief administrative officer. Tamby, who was among the officers ratified by the board for one-year terms, served as former CEO H.B. “Trip” Doggett’s (2010-2016) chief of staff. He will bring together many of ERCOT’s corporate functions into a more efficient structure, Magness said.
Magness, who was elected to another one-year term as CEO, also announced the retirement of Human Resources Vice President Diane Williams, who joined ERCOT in 2014.
“I’ve seen pictures of her grandchild,” he joked. “I can’t convince her to stay.”
Craven Crowell and Judy Walsh were re-elected to the board as chair and vice chair, respectively. However, Walsh has stepped down as chair of the Finance and Audit Committee and will be replaced by unaffiliated director Terry Bulger.
The board also confirmed ENGIE’s Bob Helton and the Office of Public Utility Counsel’s Diana Coleman as chair and vice chair, respectively, of the Technical Advisory Committee.
ERCOT, SPP, MISO Hammer out Coordination Plans
ERCOT Assistant General Counsel Nathan Bigbee said staff have revised a coordination plan with SPP and, pending final direction from the board and additional comments, will negotiate the final revisions with its neighbor.
ERCOT has been working on a new bilateral agreement with SPP since 2016 as a result of its switchable generation resource (SWGR) policy review. ERCOT began similar discussions with MISO last year. The three grid operators met to jointly discuss coordination principles and develop updated agreements and are currently taking their coordination plans through their respective stakeholder processes.
Bigbee said the plans offer greater detail around switchable-unit operations during emergency situations. The biggest change authorizes the requesting grid operator to issue directives upon receiving notification of an SWGR’s release. The controlling grid operator is required to notify the resource’s operator that the unit is needed to address an emergency condition in the neighboring region.
The release can be denied should the SWGR’s release “cause or exacerbate” an emergency condition. In the unlikely event of a simultaneous emergency scenario, primary control is assigned to the grid operator when the SWGR’s capacity has been nominated to satisfy that operator’s supply adequacy or capacity planning requirements.
“You may be asking, ‘We don’t even have a capacity market in the ERCOT region. How can we ever be primary?’” Bigbee said. “If the capacity has been nominated to satisfy supply adequacy requirements in the region, then it’s considered to be our capacity. We presume that capacity is going to be available on peak, unless you’ve submitted a notification under the protocols that says the capacity is obligated elsewhere by a contractual obligation during peak-load season.”
ERCOT will post the plans’ final executed versions on its website.
Board Approves Ancillary Service Changes
The board approved the TAC’s recommendation to tweak ERCOT’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010. (See “TAC Endorses Granularity to Ancillary Services Products,” ERCOT Technical Advisory Committee Briefs: Jan. 30, 2019.)
The Nodal Protocol revision request (NPRR863) creates a new ERCOT contingency reserve service (ECRS) and modifies responsive reserve service to become primarily a fast frequency response (FFR) service. The changes are designed to provide the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix, and to allow resources to earn compensation for providing primary frequency response.
ERCOT’s ancillary services design has remained the same, as wind, solar and battery resources increase their market presence.
ExxonMobil Power and Gas Services’ Glen Lyons, representing the consumer market segment’s industrial sub-segment, abstained from the vote. Lyons noted the four opposing votes cast during the TAC meeting by industry consumer groups, which opposed the implementation timeline.
FFR will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.
The board approved eight other NPRRs and two Other Binding Documents revision requests (OBDRRs) on its consent agenda:
NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart, and how activities will be settled during those events.
NPRR871: Gives ERCOT a mechanism to conduct a reliability review through its normal study process of customer- or resource-funded transmission projects, but without providing a recommendation.
NPRR886: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
NPRR905: Provides resettlement to reflect the proper distribution of the congestion revenue rights balancing account.
NPRR907: Replaces the M1a component of the total potential exposure calculation with a value that can vary based on non-banking business days and ERCOT holidays following the specific operating day. The M1a component sets a time period reflecting the number of days between an operating day and the beginning of a mass transition of the market participant’s electric service identifiers.
NPRR910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market, and subsequently receives a reliability unit commitment instruction.
NPRR911: Reinstates previous language in the applicable protocol sections for determining the real-time LMPs of logical resource nodes for online combined cycle generation resources (CCGRs), following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
NPRR915: Defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy offer curve.
OBDRR010: Codifies that the high sustained limit for a resource will continue to be included in the online capacity considered in operating reserve demand curve (ORDC) pricing even when that resource has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives a RUC instruction. Related to NPRR910.
OBDRR011: Shifts the ORDC’s loss-of-load probability curve by 0.25 standard deviations in 2019 and by the same measure in 2020, resulting in a single blended ORDC curve.
CARMEL, Ind. — MISO will this year draw on three sets of contributors to create its load forecast for 2020 transmission planning.
The RTO said last week it has moved ahead with a proposal to have Purdue University’s State Utility Forecasting Group (SUFG) and consulting firm Applied Energy Group (AEG) work with 20-year forecasts provided by load-serving entities.
By June, MISO will have its first load forecast based on the four 15-year future scenarios it uses annually in its Transmission Expansion Plan. Throughout last year the RTO had been examining how it could coordinate its annual load forecasting with its annual transmission planning.
Until the compromise was struck late last year, MISO had put a temporary hold on ordering more independent load forecasts from the SUFG. LSEs will now develop 20-year base load forecasts that include monthly predictions for energy and non-coincident peaks, which the SUFG will use in its state-by-state forecast.
The LSEs will also compile demand-side data separately for AEG, which will use the figures to develop demand-side management potential used in RTO planning. (See MISO Presents Load Forecasting Compromise.) MISO plans to compile and check forecast data and serve as a liaison between all parties.
“The original goal of this merged proposal is to provide more clarity, consistency and efficiency to load forecasting,” MISO adviser Ling Hua said at a Feb. 13 Planning Advisory Committee meeting.
MISO will begin building models in May for resource forecasting as part of MTEP 2020.
MISO’s 140-plus LSEs received load forecast surveys in mid-January and were expected to respond by Feb. 15. The RTO said it will next month check the submitted data for completeness.
Veriquest Group’s David Harlan said he still didn’t see how MISO’s new process will translate into new load shapes.
Hua said the RTO isn’t aiming for new load shapes for 2020’s MTEP, just a more detailed forecast.
“We’re envisioning that this is going to be an incremental step. For this time around, we’re going to implement more granular load data, but updated load shapes will be for the next time around,” she said.
MISO to Process Hybrid Interconnections Under 1 Form
MISO plans to allow generating facilities using more than one fuel source — or hybrid resources — to submit a single request to join the interconnection queue, pending FERC approval.
The current Tariff prohibits customers from designating two fuel types on an interconnection request, but MISO’s proposal will allow them to submit a hybrid generating interconnection on a single application.
MISO transmission | MISO
The revised interconnection request form will allow interconnection customers to “check all that apply” for fuel sources, including a line for storage, a change that will ease an “administrative burden,” MISO said. Hybrid interconnection requests are technically already permitted by the RTO, just under separate applications.
“It’s the same policy, just a practice change,” Resource Interconnection Planning Manager Neil Shah said.
MISO plans to file the proposal by the end of the month.
The RTO also plans to make a similar interconnection Tariff filing this month, clarifying that it allows two facilities to share a single point of interconnection, provided it, both facility owners and the transmission owner sign an agreement. (See MISO Queues up Interconnection Options.)
Draft Rules Discourage Weak Grid Interconnections
In an effort to ward off inverter-based instability, MISO is firming up rules requiring inverter-based generators seeking to enter the interconnection queue to provide a specific set of calculations and documentation.
The RTO has already drafted new Business Practices Manual language, although stakeholders at a Feb. 12 Planning Subcommittee meeting urged it to take a more active role in calculations before finalizing rule changes. (See MISO Moving to Head off Inverter-based Instability.)
Under current practice, interconnection customers must submit short-circuit ratios (SCRs) to MISO before the close of the first decision point in the interconnection queue, while TOs must calculate and report fault megavolt-ampere values to those customers. In addition, the customers must also either submit manufacturer documentation showing that their generation can steadily operate or an Electromagnetic Transients Program-based study report showing stable operation for the inverter-based resource.
Clean Grid Alliance’s Rhonda Peters argued that the RTO isn’t allowing interconnection customers enough time in the queue to pull together all the required documentation.
“It’s not cheap to hire a consultant to put together a model,” Peters added.
She also suggested that MISO calculate the SCRs for customers, given the lack of a standard method for calculating. All interconnection customers should be working from the same set of assumptions, she said.
Other stakeholders urged MISO to take the reins in crafting SCR values at the beginning of the definitive planning phase of the queue.
Shah said MISO can examine taking a more involved role in calculating the SCR values, adding that the SCR is a simple calculation, if customers are working off accurate grid information.
“To my understanding, calculation of the SCR takes no more than 20 minutes if you have the right models in place,” Shah said.
The RTO asked for more stakeholder feedback on the draft rules through Feb. 26.
MISO expects current policy and economic trends to persist from 2020 to 2035, suggesting only slight changes to the four futures that guide the planning behind the MTEP.
“MISO believes there has been minimal changes since the MTEP 19 futures, and we’re in the same place trend-wise where we were last year,” Planning Manager Tony Hunziker said during the Feb. 13 meeting.
The RTO in 2017 began developing 15-year futures meant to be reused over multiple annual planning cycles after staff noticed little year-to-year change in forecasted trends. (See MISO to Recycle Tx Planning Scenarios for 2019.)
MISO’s four 15-year futures include a base case/limited fleet change scenario, continued fleet change future, an accelerated fleet change future, and a future in which distributed and emerging technologies become more widely used in the RTO’s footprint.
For MTEP 2020, MISO plans a simple refresh of its underlying data, including new capital cost data, demand forecasts, fuel forecasts, generation retirement projections, renewable targets and updated statistics on the interconnection queue, Hunziker said. The futures will be discussed again in April and finalized in June.
Veriquest’s Harlan said he wanted MISO to discuss the possibility of an additional future during the workshop, asking for a fifth future that illustrates an increasing reliance on imports in local resource zones and the closing physical gap between generation and load as gas and coal units retire. Other stakeholders asked that the RTO start including findings from its ongoing renewable integration impact assessment in MTEP futures. (See Study: MISO Grid Needs Work at 40% Renewables.)
MISO has said it may consider working on completely new future scenarios for MTEP 2021.
WASHINGTON — Compared to the rancor often on display when the Senate Energy and Natural Resources Committee discusses topics like climate change or grid resilience, Thursday’s hearing on preventing cyberattacks on the bulk power system (BPS) was less partisan, with senators soberly asking informational questions.
That was, until it was Sen. Angus King’s (I-Maine) turn to speak.
“There’s a weird calmness about this hearing,” King said at the session, which featured FERC Chairman Neil Chatterjee, NERC CEO Jim Robb and Karen Evans, assistant secretary of the Department of Energy’s new Office of Cybersecurity, Energy Security and Emergency Response (CESER). “This is not a threat. This is happening now. We are under attack! This isn’t something that may happen next year or two years from now. And I’m not revealing anything classified in the sense of quoting news articles and presentations by the Department of Homeland Security. We are in a very dangerous place, and I just think this has to be … an emergency, an urgent situation.”
King has previously called for the federal government to develop an “offensive response” to attacks on the grid and other critical infrastructure, a proposal he repeated Thursday. (See “Sen. King Calls for ‘Offensive’ on Cyberthreats,” Overheard at NECPUC 71st Annual Symposium.)
Growing Concern
In late 2015, the Associated Press reported that “so many attackers have stowed away in the largely investor-owned systems that run the U.S. electric grid that experts say they likely have the capability to strike at will.”
The report did not cause much of a stir in the energy industry at the time. But concern has steadily grown, especially since the revelations of Russian hackers’ attacks on Ukraine’s electric grid and their interference in the 2016 U.S. presidential election.
The U.S. Intelligence Community’s 2019 Worldwide Threat Assessment, released late last month, reported that “Russia has the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure — such as disrupting an electrical distribution network for at least a few hours — similar to those demonstrated in Ukraine in 2015 and 2016. Moscow is mapping our critical infrastructure with the long-term goal of being able to cause substantial damage.”
The report also said that “China has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks — in the United States.”
King asked Robb to confirm that “Russians are already in the grid.” Robb declined to answer.
“Well can you comment on a public story about something released by the Department of Homeland Security?” King asked.
“Uh, no,” Robb replied.
After a brief pause, King said, “OK, let me ask another question. Do any of our utilities have Kaspersky [Lab], Huawei [Technologies] or ZTE equipment in their systems?” Kaspersky is a Russian company, while the latter two are Chinese.
“We issued a NERC alert —”
“I didn’t ask you if you issued an alert,” King interrupted, repeating the question.
“Not to my knowledge,” Robb said. In response to another question from King, Robb also said NERC had not surveyed utilities.
“I think that’d be a good idea, don’t you?” King said.
“I’ll take that on,” Robb replied.
“I don’t mean to come off as negative,” King said later. “I just think this has to be addressed with a real sense of crisis.”
Sen. Martha McSally (R-Ariz.) agreed.
“If I close my eyes, this sounds like a hearing from 19 years ago in many ways,” she said. “And I don’t want to take away from some of the things that have been done, but what has changed in 19 years — more rapidly than us figuring out how to defend, protect, share information and do whatever it takes — is the threat is real and it’s happening.”
“I worry we’re not moving fast enough,” Sen. Martin Heinrich (D-N.M.) said, “especially in a world where it’s often viewed that if it works, just leave it alone.”
Mandatory Pipeline Standards?
Both Chatterjee and Robb told the ENR Committee that NERC’s mandatory reliability standards for electric utility companies are among the many ways the organization guards against cyberattacks. “Mandatory standards, coupled with effective mechanisms to share information, provide robust and flexible tools to protect the BPS,” Robb said.
Chatterjee noted that he and Commissioner Richard Glick wrote an article in June last year expressing their concern about the Transportation Security Administration’s oversight of natural gas pipeline security, concerns vindicated by a Government Accountability Office report in December that found TSA is hampered by staffing constraints and vague criteria for identifying critical facilities. (See GAO Critical of TSA Pipeline Security Efforts.)
“Since the publication of that op-ed, I’ve been pleased to hear from many members of the natural gas pipeline community, who have expressed their appreciation for these concerns and willingness to continue taking steps to improve their security posture,” Chatterjee said in remarks echoing those he had made the day before at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.
Chatterjee told both the NARUC audience and the Senate committee that he had met with TSA Administrator David Pekoske “and was impressed by his focus on this vital issue, as well as his pledge to taking further action to improve TSA’s oversight of pipeline security.”
Speaking to reporters at the NARUC meeting Wednesday, Chatterjee said he met with Pekoske and TSA staff near the end of last month. “It was clear that they were taking seriously the concerns that Commissioner Glick and I had raised [and] also were taking very seriously the GAO report that pointed out things that could be improved about the process. And so, I feel very good about the actions that industry has taken and that TSA and DHS have taken to address some of the concerns that we raised.”
But he declined, both with reporters and under questioning by King and Heinrich, to say whether he thought the responsibility should remain with TSA or shift to a different agency. In the June op-ed, he and Glick wrote, “Given the high stakes, Congress should vest responsibility for pipeline security with an agency that fully comprehends the energy sector and has sufficient resources to address this growing threat.” They suggested DOE, noting the recent creation of CESER.
He also declined to say whether there should be mandatory reliability standards for pipelines, saying that they were “one way” but “not necessarily the only way” to protect them.
“Of course there should be mandatory standards for gas pipelines!” King said. “They’re part of the electric system. … It seems to me we’ve already passed this effective system for the electric utilities, and Mr. Chairman, I’m with you 100%, but I just don’t want you to hedge about it. I think you should come right out and say, ‘We got to do this.’”
Chatterjee noted that TSA has the authority to issue mandatory standards. “It would take Congress to make that change,” he said.
“I think we should all be thinking about this question,” Heinrich said to his colleagues. “Where is the right place to do this?”
NYISO’s Business Issues Committee on Wednesday approved revisions to the Installed Capacity (ICAP) Manual to reflect new capacity values for the upcoming 2019/20 capability year, particularly the amount of import capacity allowed from neighboring control areas.
Hoël Wiesner, ICAP market operations analyst, told the BIC that GE Multi-Area Reliability Simulation program (MARS) simulations were performed on the locational minimum installed capacity requirements (LCR) MARS database to determine the volume of capacity imports allowed without violating the loss-of-load expectation (LOLE) criterion.
The Business Issues Committee approved ICAP manual revisions that specifically address capacity imported from NYISO’s neighboring control areas. | NYISO
The analysis excluded interface facilities having unforced capacity deliverability rights, the controllable lines from PJM into New York and the Northport-Norwalk Harbor intertie 1385 line.
The methodology took the initial 2019/20 final installed reserve margin (IRM) database as updated for the LCR study and modeled grandfathered imports consistent with the IRM study, then determined the imports for each control area individually by increasing imports on ties until the LOLE levels in the base case were met, Wiesner said.
“Once we have these individual limits set, we perform a simultaneous run by increasing the ICAP imports based on the individual limits, beyond the grandfathered imports, until the LOLE levels in the base case are met,” he said.
“These ICAP imports, added to the grandfathered imports, determine the final limits on each control area interface,” Wiesner said.
The final values for the capability year are 1,112 MW for PJM; 279 MW for New England; 1,114 MW for Hydro-Quebec; and 128 MW for Ontario — for a total import limit of 2,633 MW.
The next steps are finalizing the values and publishing them to the automated market system by March 1, emailing the marketplace when those values are finalized, and beginning the first-come, first-serve import rights process March 6, he said.
Broader Regional Markets Report
NYISO on Jan. 27 implemented software to resolve technical issues related to offer caps under FERC Order 831, precluding the need for a requested waiver.
The ISO had implemented software to comply with Order 831 in December, while requesting a limited waiver to resolve an outstanding implementation issue, Rana Mukerji, senior vice president for market structures, told the BIC in presenting the monthly Broader Regional Markets report.
The ISO will continue discussions on the issue at future working group meetings, while targeting to seek stakeholder approval from the BIC and Management Committee by the end of the first quarter, Mukerji said.
Natural Gas Prices Spike 50% in January
NYISO locational-based marginal prices averaged $50.93/MWh in January, up by about 25% from December and down around 50% from the same month a year ago when natural gas prices surged during a severe cold snap, Mukerji said in delivering the monthly operations report. Day-ahead and real-time load-weighted LBMPs came in higher compared to December.
Year-to-date monthly energy prices averaged $52.99/MWh, a 48% decrease from a year ago. January’s average sendout was 449 GWh/day, compared with 425 GWh/day in December and 463 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $6.11/MMBtu for the month, up 50% compared with December but down nearly 66% from a year ago.
Distillate prices rose compared to the previous month but were down 9.7% year-over-year. Jet Kerosene Gulf Coast averaged $13.25/MMBtu, up from $12.54/MMBtu in December. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.20/MMBtu, up from $12.84/MMBtu.
January uplift increased to -25 cents/MWh from -29 cents in December, while total uplift costs, excluding the ISO’s cost of operations, came in higher than December.
The ISO’s local reliability share jumped to 32 cents/MWh in January from 23 cents the previous month, while the statewide share dropped to -57 cents/MWh from -52 cents.
The Thunderstorm Alert cost in New York City was $0, unchanged from December.
CARMEL, Ind. — MISO on Tuesday said it will explore whether to alter its long-term planning models to factor in expectations for an increased number of outages.
The RTO initiated a review of outage assumptions in those models after its research showed that outages are more prevalent than represented, stakeholders learned at a Feb. 12 Planning Subcommittee meeting. The current approach to outage modeling may result in long-term reliability planning models that permanently underestimate the actual volume of outages, it found.
MISO Senior Manager of Expansion Planning Edin Habibovic said the RTO could summarize its experience over the last few years as one in which it faces an aging fleet with generation retirements, which amplify the effects of the outages among remaining generators.
“The question we’re trying to answer here is to assess historical generation and transmission outages and see if they line up with the current planning assumptions,” Habibovic said.
The grid operator’s existing long-term models only consider historical planned outages lasting longer than six months, resulting in “few planned outages being embedded in the models.” Only one planned transmission outage and no generation outages were applied to the two- and five-year out models in the 2018 MISO Transmission Expansion Plan.
For forced outages, MISO’s annual MTEP assessment simulates the removal of approximately 2.8 GW for a P3 NERC contingency event and 5.1 GW for extreme events. In reality, the historical outage average varies from 2 to 9 GW of unavailable generation throughout the year.
MISO also said the frequency and duration of forced and planned outages are usually higher and longer than expected. As a result, planning models “may be overstating” the future ability to import generation and reliably serve load in some areas where generation and transmission outages occur more often than planned.
Director of Planning Jeff Webb said long-term planning models are analyzed against NERC planning standards that test system reliability for one or two outages, when in real time there are actually “tens” of concurrent outages throughout the footprint. He added that he wasn’t sure how a more realistic set of outage assumptions would affect long-term reliability planning, and said the new effort was meant to examine that question.
“As we see more and more data that shows this gap, the question is ‘Boy, what does the performance of the grid look like if we matched it with reality?’ It could be that something changes; it could be that nothing changes,” Webb said. “There are many lines out, many generators out in every single hour of the year. Shouldn’t we look at a model that mimics that day?”
MISO said it can use its historic forced outage rate to exclude poor performing generators from redispatch in the models then assess system performance in the five-year and 10-year cases. Habibovic said the RTO would study those cases against those the current process produces to see if long-term reliability needs are affected by real-world outage numbers. He also said it would be helpful to identify potential reliability risks to the transmission system as early as possible.
Habibovic said if MISO modeled its poor performing generators as unavailable, it would have resulted in about 19 GW and 22 GW of systemwide unavailable generation in the 10-year base case model and the five-year sensitivity base case models in MTEP 18, respectively.
MISO will look into excluding the worst-performing generators from long-term modeling in MTEP 2020, Habibovic said. He asked for stakeholders’ comments on the approach by Feb. 28.
The RTO will also perform data analysis on transmission outages to see if it should change transmission availability assumptions in long-term planning models, MISO adviser Matt Tackett said.
Meanwhile, in last year’s annual NERC-required extreme event assessment, MISO found that two simultaneous facility outages are likely the most common cause of cascading events, with the most severe scenario occurring when two local generation plants go offline simultaneously.
This week, the Independent Market Monitor said it continues to monitor short-notice outages in MISO South, including planned outage extensions and unreported outages and derates. The Monitor said in January that short-notice and unreported outages continue to be “significant” in the region.
Vineyard Wind on Thursday announced it has partnered with Anbaric Development Partners in proposing up to 1,200 MW of offshore wind in response to a solicitation by the New York State Energy Research and Development Authority in consultation with the New York Power Authority and the Long Island Power Authority.
The joint venture, Liberty Wind, submitted three different proposals sized at 400, 800 and 1,200 MW — each of which couples energy generation with transmission components.
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New York’s Public Service Commission last July authorized state agencies to procure 800 MW of offshore wind energy by the end of this year after Gov. Andrew Cuomo set a target of 2,400 MW by 2030. Last month, he dramatically upped that goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
Vineyard, a 50/50 partnership between Copenhagen Infrastructure Partners and Avangrid Renewables, last May won a contract from Massachusetts for a 1,200-MW offshore wind project off Martha’s Vineyard. Anbaric helped build the 660-MW Neptune HVDC cable linking PJM to Long Island, and also contributed to the 660-MW Hudson project connecting midtown Manhattan to the RTO.
Anbaric also has several interconnection requests and slots with NYISO, including for a 500-MW HVDC line and 800-MW AC line connecting into Ruland Road on Long Island, as well as a 1,200-MW HVDC line and additional 800-MW AC connection into the Farragut substation in Brooklyn. (See Anbaric Pushes Offshore Grid Plans.)
The Liberty Wind proposal includes fabricating foundation components at a port facility near Albany and transporting them down the Hudson River to the project site in the Atlantic Ocean.
“Our team’s extensive offshore wind experience from around the world and nearby in New England, where we are building the nation’s first utility-scale offshore wind project, allows us to deliver the best project for New York,” Vineyard CEO Lars Thaaning Pedersen said in a joint statement with Anbaric CEO Ed Krapels.
“This is the first leg of a well-designed New York ocean grid for offshore wind that will help achieve Gov. Cuomo’s goal of building a planned offshore grid,” Krapels said.
NYSERDA issued the request for proposals for the projects in November (ORECRFP18-1).
Federal regulators Tuesday approved PJM’s revisions to its market efficiency planning rules, despite protests from transmission developers that the changes will underestimate future generation needs and associated costs.
The FERC order, effective Feb. 13, approves the RTO’s updates to Section 1.5.7 of its Operating Agreement that would exclude from market efficiency planning — with exceptions — generation either with only an executed facilities study agreement (FSA) or with an executed interconnection service agreement (ISA) under suspension (ER19-562).
Change Late in RTEP Submission Cycle
The rule change comes near the tail-end of the long-term transmission planning window opened in November, which accepts proposals capable of reducing future congestion. (See PJM Market Efficiency Rules Could Slip Deadline.) Developers can submit projects through the end of February.
Under previous market efficiency rules, PJM included in-service generation and generation with either an executed ISA, an executed interim ISA for which an ISA is expected to be executed or an executed FSA. Excluding generation with executed FSAs only occurred on a case-by-case basis after review with the Transmission Expansion Advisory Committee.
West Penn Power linemen check a new 138-kV line. | FirstEnergy
The 15-year scope also projected levels of new generation and retirements. If models anticipated PJM would fall short of its reserve requirement in any of the proceeding years, the analysis would suggest transmission enhancements addressing potential congestion.
PJM said its robust capacity market, however, means the likelihood of missing reserve requirements over the next 15 years remains slim, leading to a “vast overstatement” of future generation needs and cost. The RTO’s internal analysis encompassing 1999 through 2018 concluded only 36% of generation projects with executed FSAs or ISAs under suspension reached commercial operation, compared with 70% of projects with executed ISAs or wholesale market participation agreements.
“PJM adds that including all projects either with only an executed FSA or with an executed ISA that is under suspension skews the market efficiency models towards including too much generation, which results in an unrealistic estimation of congestion,” FERC said in its ruling.
The new rules exclude such projects from the market efficiency analysis, unless a generator’s specific circumstances or forecasted system reserve margins require staff to reconsider. PJM said it will invoke this unit-by-unit process “rarely,” but always “in an open, transparent process in consultation with the TEAC, and will identify the specific generation projects based on articulable factors that justify their addition.”
Stakeholder Objections
The revisions prompted interventions from developers and the Independent Market Monitor, all of whom argue excluding the projects will underestimate generation needs and mask related costs, skewing what is considered “the best picture of generation to be added” in the eyes of all market participants, stakeholders and state commissions.
The Monitor said eliminating all the early-stage generation from the analyses threatens PJM’s even-handed approach in managing competition between transmission and generation. It also criticized the RTO for not incorporating such uncertainty into forecasts of future congestion, expected fuel costs and construction of transmission projects.
FERC dismissed the Monitor’s concerns over competition, saying that improving the accuracy of PJM’s market efficiency analysis outweighs any possible advantage the new rules may give transmission projects over generation. It also disagreed with developers who argued under-representation of generation will bias the analyses, agreeing with PJM that such changes will lead to more accurate modeling.
“While it may be worthwhile for PJM to work with its stakeholders to undertake some of the suggested analysis, the issue here is limited to whether PJM’s proposed Operating Agreement revision is just and reasonable,” FERC said. “We find that it is.”
PJM’s Brian Chmielewski will lead a special meeting of the TEAC at 10 a.m. Feb. 20 to discuss the rule changes with stakeholders.
Pacific Gas and Electric proposed spending up to $2.3 billion this year on grid hardening and increased line inspections and vegetation management to prevent the ignition of wildfires.
The utility would also expand the scope of its public safety power shut-off (PSPS) program — the “de-energization” of lines during high-threat periods — to include its entire service territory of 5.4 million customers (16 million residents), meaning that even those living in low-risk areas could face shut-offs.
The Witch Fire, sparked by power lines and driven by Santa Ana winds, tore through San Diego County in 2007. | State Farm
PG&E and California’s other investor-owned utilities presented their wildfire mitigation plans (WMPs) in person to the state Public Utilities Commission during an all-day session in San Francisco on Wednesday.
The IOUs filed written plans Feb. 6 in accordance with SB 901, which required more detailed fire prevention strategies after two years of catastrophic wildfires in Northern and Southern California. (See Federal Judge to Review PG&E’s Wildfire Plan.)
PG&E’s wildfire plan drew the most interest — and scrutiny — from state officials and members of the public attending the relatively subdued hearing.
California fire investigators last year determined the utility’s equipment sparked at least 17 of the fires that swept through the state’s wine country in 2017, and the company is under suspicion for causing last November’s Camp Fire in Butte County, the deadliest and most destructive in state history.
Facing more than $30 billion in potential wildfire claims, PG&E last month filed for Chapter 11 bankruptcy protection.
‘Paradigm Shift’
Sumeet Singh, Pacific Gas and Electric | PG&E
In opening his presentation, Sumeet Singh, vice president in charge of PG&E’s community wildfire safety program, spoke about the “unprecedented level of risk we’re facing in the state of California” from wildfires.
“When you look at the last three years, nine of the 20 most destructive wildfires happened since 2015. And when you look at the associated damage, nearly 72% of the structure damage occurred within that time frame,” Singh said. He added that the volume of vegetation “plays a key role” in wildfire risk, and that vegetation “becomes more pronounced” in the forested regions of Northern California that constitute a large swath of PG&E’s territory.
Expected to cost between $1.7 billion and $2.3 billion in 2019 alone, PG&E’s plan focuses on preventing ignition and “rapid detection and situational awareness” after fires are sparked, Singh said.
He laid out a dizzying array of measures the utility expects to undertake, including identifying and removing hazardous trees along its 81,000 miles of overhead transmission and distribution corridors; clearing overhang from “the wire to the sky” in high-risk areas; examining the condition of transmission assets in fire-prone areas, including inspecting 685,000 poles; performing “enhanced” line inspections using drones; and adding 400 weather stations to the 200 it installed last year.
“It’s a fairly significant effort that we’ve undertaken,” Singh said.
In its “system hardening” effort, PG&E will seek alternatives for serving people in high-fire districts, including microgrids and battery storage; targeted undergrounding of lines; and rebuilding existing infrastructure with covered conductors and hardened poles — as Singh said the utility is already doing in devastated areas.
Singh also explained that PG&E will expand the scope of the power lines subject to its PSPS from the 7,100 miles in “extreme risk” areas to an additional 25,200 miles in “elevated risk” areas, leaving all the utility’s customers at risk for potential shut-offs — an outcome Singh said was highly unlikely.
CPUC President Michael Picker pointed out that San Diego Gas & Electric has developed tools for a more “granular” threat index to avoid the potential for such widespread shutoffs.
“We’re trying to get there faster and sooner, and that is the reason why we’ve doubled the weather station program,” Singh said. “We’d love to be able to get there this year, but I’m not sure that’s going to be achievable.”
Picker asked about PG&E’s expected timeline for implementing its mitigation plan.
“Do you think of it as three-, five- or 10-year plan?” Picker asked.
“Less than three years. Look at this as a short-term plan,” Singh replied.
Elizaveta Malashenko, CPUC deputy executive director for safety and enforcement policy, questioned the utility’s ability to meet that time frame.
“The plan is very aggressive, but it’s a plan we put together and have a line of sight into,” Singh said. “We have dedicated teams, dedicated individuals focusing on this work.”
Gabe Petlin, CPUC supervisor of grid planning and reliability, pointed out that PG&E currently has only 43 open positions advertised on its website, just two of which were for the more than 700 arborists that Singh said would be needed for the company’s increased vegetation management efforts.
Singh said PG&E is working with “contractor partners” to obtain the expertise. “It’s a model we’ve used for many years,” he said.
During the public comment period on the plan, Robin McCollum, a former tree clearing supervisor for Butte County, called vegetation removal “low-hanging fruit” for PG&E, saying that trees are “a valuable public resource that shouldn’t be squandered.” He also characterized PG&E’s plan for an additional 32 feet of ground clearance around corridors as “very extreme.”
“I think we’re at a point where we should have a paradigm shift in our thinking,” McCollum said. “It’s not the vegetation that causes the problem. It’s not the vegetation that’s the enemy or the target. It’s the wires, the bare wires, that are the hazard. … What we need to do, however long it takes, and at whatever expense … we should insulate those wires.”
SDG&E’s ‘Model’
SDG&E was the first of the three big IOUs to lay out its fire prevention strategy on Wednesday. State officials often cite the utility as a role model for PG&E and Southern California Edison to follow in preventing wildfires.
David Geier, San Diego Gas & Electric | SDG&E
After a series of devastating blazes last decade — including the Cedar Fire in 2005 and the Witch and Harris fires in 2007 — SDG&E’s service area hasn’t experienced fires of that magnitude since, said David Geier, the utility’s senior vice president for electric operations. The CEO of SDG&E’s parent company, Sempra Energy, vowed 12 years ago that “we are not going to have any wildfires caused by [our] equipment ever again,” Geier said.
SDG&E embarked on a program to install hundreds of weather monitoring stations and cameras across its mountain-to-ocean service territory. The weather stations revealed wind gusts up to 101 mph in some locations when the majority of the utility’s grid was built for 60-mph winds, Geier said.
The utility is installing transmission towers constructed to 85-mph wind standards. It has undergrounded or covered many lines, and it inspects all of the 465,000 trees each year, he said.
“We probably know as much about trees as we know about any other asset in our system,” he said.
SDG&E also installed “sensitive ground fault detection” that can cut current by 67% on downed lines, he said.
“That’s the spark that causes the fire,” Geier said.
San Diego Gas & Electric credits its intensive weather monitoring with preventing major wildfires since 2007. | SDG&E
The company has tried to instill its safety culture company-wide, with every employee part of the mission, and consumers have been continually included in the effort through public meetings and outreach, he said.
“One thing is certain,” Geier said. “There’s going to be another fire season.”
SDG&E’s plan is being partially adopted by SCE, which is installing weather stations and cameras across its high-risk fire areas. The utility also has a program of emergency power shutdowns in extreme fire conditions.
Phil Herrington, Southern California Edison | Southern California Edison
SCE will spend about $582 million on fire prevention measures this year, but Phil Herrington, vice president for transmission and distribution, said there’s only so much utilities can do in the face of climate change.
“I think we all recognize this is not a utility issue. It’s a statewide issue,” Herrington told the commission.
SCE will deploy more than 800 weather stations and will have camera coverage of 80 to 90% of its service area by 2020, he said. It inspects about 900,000 out of its 1 million trees annually, and the utility established a central command post to monitor for emergencies “24/7,” he said.
“How far off are you from SDG&E?” Malashenko asked Herrington. Regarding SCE’s mitigation plan, she asked, “How much closer is it going to get you?”
Herrington replied, “We’re looking at making rapid catch-up.”
