Page 1062 – RTO Insider

March 10, 2019

Showdown Set on PJM Must-offer Exceptions

By Christen Smith

VALLEY FORGE, Pa. — Members of the PJM Market Implementation Committee on Wednesday set up a showdown over whether the RTO can force capacity resources into energy-only status for failing to meet Capacity Performance requirements.

About 61% of MIC voters endorsed an Exelon proposal that would allow capacity resources to voluntarily switch to energy-only status but would not allow PJM to force such a switch. Eighty-five percent also said they preferred the Exelon rules over those proposed by PJM and approved by the MIC in November. The votes made the Exelon proposal eligible to be considered by the Markets and Reliability Committee next month.

Both proposals, which would require changes to Manual 18 and the Tariff, will receive first reads at the March 21 MRC meeting. However, the November proposal will be voted on first at the April 25 MRC meeting because it was previously approved by the MIC, winning 79% support. The Exelon proposal will only get a vote if the November proposal fails to clear the necessary two-thirds sector-weighted threshold.

MIC members Wednesday also preferred Exelon’s proposal over a joint plan from PJM and the Independent Market Monitor that received only 35% support, below the 50% threshold for consideration by the MRC. About 49% preferred the PJM-IMM plan to the November proposal.

Remand

The original MIC-endorsed plan was remanded back to the committee in December after the MRC agreed further discussions were needed. It would require existing capacity resources not offered in three consecutive auctions to change to energy-only status. Capacity interconnection rights (CIRs) of such resources would be terminated one year from the switch to energy-only, unless the rights holder submits a new generation interconnection request within that year using those same CIRs.

The PJM-IMM proposal would have added to the November proposal a requirement that any resource receiving a must-offer exception file a plan showing how it will become able to satisfy CP requirements in order to retain capacity status. The requirement would be effective with the 2023/24 delivery year. Resources would be granted exceptions for no more than two auctions. (See PJM MIC to Vote on Alternative Must-offer Exception Rules.)

“Both [the original proposal and PJM-IMM addition] have a requirement for units with CP must-offer exceptions to go energy-only after a certain amount of time,” PJM’s Pat Bruno said. “The main difference between the two is the way that they would be required to go energy-only and how soon that would take effect.”

Sharon Midgley, Exelon | © *RTO Insider*

Exelon said it did not support a mandatory switch to energy-only because stakeholders were not in consensus on the issue, which raised equity issues over resources’ potential loss of CIRs. Intermittent resources are exempt from must-offer rules.

“We were able to support the compromise approach previously endorsed by the MIC,” Sharon Midgley, senior manager of wholesale market development for Exelon, said Wednesday. “Exelon does not support the PJM-IMM alternative proposal. We have concerns with the mandatory process and concerns with the CIR inequities between traditional generation resources and renewables.”

‘Unlevel Playing Field’

Other generation owners agreed with Exelon’s objections.

David “Scarp” Scarpignato, Calpine | © *RTO Insider*

“If you have renewable resources that aren’t offering into auctions … they should probably forfeit CIRs for all the same reasons,” said David “Scarp” Scarpignato of Calpine. “Allowing energy-only wind resources to have CIRs and to say generators of other types aren’t allowed to is a completely unlevel playing field. It’s more than problematic. It’s contrary to the Operating Agreement.”

Consultant Roy Shanker agreed that PJM should subject renewables to the same requirements as traditional resources.

“If we can hold the CIR without being CP based on an exemption, then they get to do that,” he said. “To Scarp’s point, then they, just like everybody else, should be expected to forfeit CIRs under the same conditions. We passed the hurdle a long time ago that those definitions of capacity resources within CP being different going forward. They go hand in hand. To me, there’s no reason to partition between anyone.”

John Brodbeck, EDP Renewables | © *RTO Insider*

John Brodbeck of EDP Renewables argued companies like his pay for interconnection upgrades and receive CIRs in return. “When you pay for something, you want to own it,” he said.

Load interests, however, said generators’ focus on who owns CIRs muddles the issue. Carl Johnson of the PJM Public Power Coalition said some legacy generators stand to lose CIRs for which they never paid.

“Some may have [paid], many have not,” he said. “As topology has changed, a lot of legacy generators did not pay for them. Loads have.”

March 8, 2019

WECC Board Continues Focus on RC Transition

By Hudson Sangree

The Western Electricity Coordinating Council continued to deal with issues related to this year’s reliability coordinator transition at its board of directors meeting in Salt Lake City on Wednesday.

Among the matters heard was an update from Peak Reliability CEO Marie Jordan on the wind-down of the company’s operations this year as CAISO, SPP and BC Hydro prepare to take over RC functions across the Western Interconnection by the end of 2019. (See Peak Reliability to Wind Down Operations.)

Keeping key staff on board at Peak and maintaining high operational standards are among the top priorities, Jordan told WECC board members.

WECC’s board and committees meet in Salt Lake City. | *WECC/Kirha Quick*

Another issue discussed was WECC’s proposed process for requesting key data and information from the incoming RCs under NERC Rules of Procedure Section 1600. The planned move reflects the new operating conditions in a multiple-RC environment rather than one exclusively overseen by Peak, WECC staff said.

“We’ve been working internally for about the past nine months to put this together in anticipation of moving to the multi-RC environment and want to make sure that WECC maintains its options for the receipt of information,” WECC General Counsel Steve Goodwill said.

“Because a Section 1600 request would only apply to U.S. entities, not to our Canadian or Mexican partners [such as BC Hydro], we need a different mechanism to collect data from them,” Goodwill said.

WECC had provided the draft Section 1600 request to incoming RCs and NERC, “totally informally but just for their review and comment before we started any formal process,” Goodwill said. WECC incorporated their comments and changes, and in February it initiated a formal Section 1600 request, he said. The final draft was submitted to NERC and FERC last month for a 21-day comment period, which will be followed by a 45-day period starting Friday for stakeholder comments.

The WECC board still must give final approval to the request. “We would like to have that in place by mid-June at the board meeting so that as the RCs go live, we can issue the data request to them,” Goodwill said. CAISO will assume the RC role for its existing territory on July 1, “so that keeps us on the right timeline.”

Peak Reliability Update

At WECC’s last board meeting in December, speakers expressed concerns about the multiple turnover dates involved in the Western RC transition, each of which could provide opportunities for errors. (See RC Transition Fraught with Pitfalls, WECC Hears.)

WECC’s board of directors meet Wednesday. From left to right: Chair Kristine Hafner, President and CEO Melanie Frye, Gary Leidich and Richard Campbell. | *WECC/Kirha Quick*

After CAISO, BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside its footprint on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.

Another area of concern was the ability of Peak to hang on to essential staff members through the long transition.

After announcing it would get out of the RC business and end operations, Vancouver, Wash.-based Peak saw a number of employees depart, Jim Shetler, general manager of the Balancing Authority of Northern California and chair of Peak’s Member Advisory Committee, told the WECC board in December. Some Peak employees in Washington and Colorado took positions with electricity entities in those areas, he said.

To stem attrition, Peak detailed the severance packages that employees will receive if they stay with the company until they’re no longer needed, he said. With that, Shetler said, “the unplanned departures, I expect, will come down quite a bit.”

Peak said in January that of its 169 staff members at the start of 2018, 23 had left by the end of the year. Peak’s RC department declined from 42 staff members to 34 throughout 2018.

Jordan’s presentation to the board seemed to partly confirm Shetler’s prediction that the attrition would abate with increased transparency and communication with employees. Staffing levels in Peak’s RC department have held steady since October, Jordan’s presentation showed, though some engineering and IT employees continued to depart through February.

March 8, 2019

FERC Blocks GridLiance Oklahoma Tx Acquisition

By Robert Mullin

FERC on Wednesday rejected GridLiance High Plains’ plans to acquire transmission assets from Oklahoma-based People’s Electric Cooperative, finding the company failed to prove the transaction would not have an adverse impact on rates (EC18-122).

The proposed deal would have seen GridLiance take over 55 miles of 138-kV lines and a substation from People’s, which provides electricity to about 15,000 members across 11 Oklahoma counties and operates a 4,500-mile distribution and transmission network.

People’s Electric Cooperative line in Oklahoma | *People’s Electric Cooperative*

Completion of the transaction was subject to FERC accepting GridLiance’s proposal to earn an annual transmission revenue requirement on the assets by moving them under the company’s commission-approved rates in SPP. The co-op is not a member of the RTO.

In making its case for the acquisition, GridLiance contended the rate impact would be small: about $2.7 million, based on a $14.9 million net book valuation of the assets. It said “non-quantifiable” benefits would offset those costs.

In rejecting GridLiance’s request, the commission acknowledged that the transaction “on its face” resembled those of similar proposals it had approved in the past. Like GridLiance, the buying party in each of those deals acknowledged the acquisition would increase rates for transmission customers, “which the commission has acknowledged ‘is not unexpected’ when the transaction involves ‘ownership changes from a not-for-profit utility to a for-profit business with a different capital structure, tax obligations and the need to earn a return,’” the commission wrote, citing a previous decision.

In each of those transactions, applicants contended that the rate increases were justified by the non-quantifiable benefits of transmission company ownership and therefore not “adverse.”

But in Wednesday’s decision, the commission pointed out that its approvals were based on the specific facts at play in each request. GridLiance, the commission said, failed to back up its promised benefits, or show that they would offset the proposed rate increases.

FERC questioned GridLiance’s claim that the acquisition would increase reliability for retail customers receiving service over People’s transmission system, noting that only 47 MW of load are being served by the transmission feeds being acquired.

“Without further evidence as to the reliability benefits of the transaction, we cannot find that the benefits of increasing the reliability of service to this relatively small amount of retail load is sufficient to offset the rate increase resulting from GridLiance’s acquisition of the assets,” the commission said.

The commission also rejected GridLiance’s contention that the transaction would provide the non-quantifiable benefit of promoting transmission company ownership of facilities.

“This argument simply restates the general holding of the commission’s cases described above without explaining how GridLiance’s ownership of the assets provides benefits that offset the projected rate increase,” FERC said.

The commission also rebuffed GridLiance’s claim that its ownership would improve operations and efficiency in SPP, pointing out that while the lines could be made more reliable if looped into the RTO’s system, they would still be primarily serving the same small volume of industrial load. “GridLiance has failed to demonstrate how placing the assets under SPP’s control would maximize the use of the assets, minimize the need for new transmission or provide new avenues for transmission expansion,” the commission said.

Finally, FERC rejected GridLiance’s argument that the acquisition would further the commission’s goal of increased RTO participation among publicly owned utilities.

“Here, the addition of 55 miles of transmission facilities whose only use is to deliver power to industrial customers does not materially add to the size or scope of SPP, nor has it been shown to provide other material benefits to SPP,” the commission concluded.

March 8, 2019

Capacity Market Sellers Anxious over Uncertain PJM Auction Rules

By Christen Smith

VALLEY FORGE, Pa. — Capacity market sellers expressed anxiety Wednesday over PJM’s “parallel path” for its upcoming Base Residual Auction, urging staff to consider delaying the auction until FERC clarifies the minimum offer price rule (MOPR).

Stu Bresler, PJM senior vice president of operations and markets, said the RTO is asking capacity sellers to adhere to BRA timelines under current rules as a preventative step in case the commission provides no additional guidance before the auction, which has already been delayed to Aug. 14.

FERC last summer granted PJM’s request to delay the auction in response to the commission’s June ruling requiring the RTO to revamp its MOPR to address price suppression from rising state subsidies for renewable and nuclear power (ER18-2222). (See FERC OKs Delay of PJM Capacity Auction.)

PJM filed its proposed MOPR changes Oct. 2 and said a FERC ruling by March 15 would keep the August schedule on track (EL18-178, ER18-1314, EL16-49).

But at Wednesday’s Market Implementation Committee, PJM’s Jeff Bastian said the RTO had no indication when a ruling would be made.

Bastian then walked stakeholders through the upcoming deadlines in what he called its “parallel path” to the August auction, for delivery year 2022/23. The document called for sellers to confirm whether they will be offering resources with “actional subsidies” by March 17 — a deadline stakeholders said was unreasonable.

Staff said they believe only the MOPR will be subject to change in the pending ruling. But they acknowledged the auction might need to be pushed back again if the ruling is not issued soon.

“I would concede that at some point we would get to where it would be impossible to proceed and we would have to look at delaying the auction,” Bresler said. “I don’t have a specific date I can give you at this point.

“I think any delay has some kind of a consequence, so that’s why we are trying to avoid it,” he continued. “We wouldn’t want to go past next May’s auction, obviously. Anything in between has a certain level of negative consequences with it, but I think it gets worse as we go through time.”

Stakeholders balked at the plan, insisting it contradicted the arguments made in PJM’s original delay waiver that its market suffers without certainty.

“It’s hard, as sellers, to know what to provide for MOPR,” said Jason Barker of Exelon. “This new path no longer allows us as sellers to evaluate FERC’s new conditions. This is going to be problematic for market sellers. You guys realize that and wrote it in your Tariff waiver request. Now we seem to be slavishly following a schedule and not the needs balanced in the FERC order.”

Adrien Ford of Old Dominion Electric Cooperative echoed Exelon’s sentiments and complained about the persisting uncertainty across PJM’s markets.

“I don’t feel like there is a single market I can give an update [to colleagues] on with any certainty,” she said. “Then to add this on top of it? I just think it’s going to be really problematic for capacity market sellers.”

John Horstmann, Dayton Power & Light | © *RTO Insider*

John Horstmann of Dayton Power & Light pressed PJM for more time.

“This could be life and death for your unit,” he said. “You’ve heard from a number of stakeholders how there’s going to be huge impacts. And yet you want us, without any real Tariff, to comply with all these data submissions because they might be enforced. Of course, they might not. ‘Oh yeah, and we want it in a week and a half.’ Where’s the reasonableness in that?”

“What we appear to be doing is asking people to make irreversible decisions based on rules that may change,” said Joe Bowring, PJM’s Independent Market Monitor. “It sounds like PJM’s theory is move forward with existing rules and just be prepared for changes.”

March 7, 2019

SPP Briefs: Week of March 4, 2019

SPP celebrated the fifth anniversary of its wholesale market by noting it had produced the nation’s lowest electricity costs, saving market participants $2.7 billion, and exceeded initial projections for annual net savings.

In making its case, SPP cited a 2018 FERC market r e port that listed its average year-to-date monthly day-ahead prices in October at $29/MWh. The Southeast region came in second at $31/MWh.

SPP had projected the Integrated Marketplace would yield $100 million in annual net savings to market participants when it was brought online in March 2014. Instead, it said, the markets have “dramatically outperformed expectations” by producing an average of $570 million in annual savings from lowered production costs, reductions to excess capacity requirements and other efficiencies.

“Our market has continually proven itself to be one of the wisest investments our members have made,” SPP CEO Nick Brown said in a state m ent referring to the market’s economic and reliability benefits. “It has also set us up for continued success well into the future.”

The Integrated Marketplace added day-ahead generation dispatch, congestion management and real-time balancing solutions to SPP’s market offerings. At the same time, the RTO consolidated the 16 balancing authorities (BAs) in its 14-state footprint to coordinate next-day generation, increasing access to lower-priced renewable energy and energy reserves.

SPP said wind energy made up 3% of its annual energy production (6 of 176 GWh) in 2008. Last year, the RTO produced 276 GWh of energy, with wind accounting for 23% of that figure. It has seen a peak wind penetration level of 64%.

“A decade ago, serving even a quarter of our load with variable, renewable generation wouldn’t have been possible, but today it is almost a daily occurrence,” Vice President of Operations Bruce Rew said.

Conservative Operations Alert Ends

SPP ended two-and-a-half days of conservative operations on Tuesday after successfully meeting high demand, despite subzero temperatures in the northern portion of its footprint. The RTO issued the conservative operations alert about midnight March 3, lifting it shortly after noon Tuesday.

Spokesman Derek Wingfield said SPP was able to mitigate the loss of 2.5 GW of generation from derates and failures to start in the cold weather, primarily in the southern part of the footprint.

SPP saw peak loads, all in the 7 a.m. hour, of 41.1 GW on March 4; 40.6 GW on March 5; and 39.3 GW on March 6. The RTO hasn’t met demand that high since September 2018.

Temperatures in Bismarck, N.D., dipped to -15 degrees Fahrenheit on March 3, before rising to 22 F on Wednesday.

SPP, Members Prep for Summer in Arctic Temps

Temperatures were 18 F on Tuesday as SPP staff and market participants gathered in Omaha, Neb., for — ironically enough — a workshop on summer preparedness.

Staff said a new summer peak is unlikely. SPP expects average heat during the early summer months across its footprint, with a 33 to 40% chance of above-average temperatures in later months. It also gave a 33 to 40% chance of above-average precipitation in early summer months, with average precipitation later in the season.

SPP’s all-time peak demand of 50.6 GW came in July 2016. Demand in 2017 was 50.5 GW, dropping to 49.7 GW last summer.

Staff reviewed with members last summer’s performance, when the only critical moments came during the shoulder months. SPP issued a hot-weather alert in May and a level 2 emergency energy alert in September, both during periods of above-average heat and low wind.

“We have tight capacity issues because we try to run a tight ship,” SPP’s Jon Langford said.

Staff is working on its 2019 summer assessment, using power flow and voltage stability analyses.

— Tom Kleckner

March 7, 2019

PJM Operating Committee Briefs: March 5, 2019

VALLEY FORGE, Pa. — PJM’s Operating Committee breezed through a light agenda during its March meeting on Tuesday.

Frequency Response Performance Underwhelms

The number of generators providing primary frequency response (PFR) in 2018 fell short of PJM’s expectations, according to the RTO’s most-recently analyzed d a ta.

Danielle Croop, PJM senior engineer of operations and analysis, told the Operating Committee PFR-capable generators didn’t respond as anticipated during five low-frequency events selected for evaluation throughout the year, at times providing less than half the megawatts PJM expected.

“These five events are the only ones that met the [PJM] criteria for 2018,” Croop said. “There’s usually about 25 or 30 events that meet [NERC’s] BAL-003, so you can see how narrow the evaluation selection is.”

At last October’s OC meeting, PJM shared frequency response data from 13 BAL-003 events between December 2017 and April 2018 that showed similar results. (See “The Right Metric on Frequency Response” in PJM Operating Committee B riefs: Jan. 8, 2019.)

PJM assesses generator performance during events in which the system frequency goes outside a +/-40-mHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz. (See “Utilities Question Primary Frequency Response Calculation” in PJM Operating Committee Brief s : Feb. 5, 2019.) The five events fitting into the narrower criteria occurred on Jan. 27, April 7, June 30, Sept. 13 and Sept. 20.

Count of units that provided PFR by % of response compared to expected response. Only units expected to respond are in evaluation. | *PJM*

While generators provided 130 MW of the anticipated 165 MW during the January event, available energy dipped to 50% or less of what PJM expected during the April 7, June 30 and Sept. 13 events.

Brock Ondayko, of AEP Energy, refuted PJM’s expectation for more output, calling it “incorrect.” He said PJM’s existing dispatch software often oversimplifies a resource’s anticipated PFR capability because it doesn’t account for physical operational hold points.

“Until PJM modifies [its] dispatch software to take into account how resources actually operate and then subsequently begins to preposition capable units to respond, ‘expected’ numbers really need to be taken with a grain of salt,” he said in an email Tuesday. “While I sympathize with PJM’s dispatch issues and understand the limitations of [its] current estimates, my continuing to bring up the topic/issues for what has seemed like years has never stopped PJM from continually sharing what must be considered suspect data, without disclaimers.”

Croop defended the numbers during the meeting Tuesday, noting more accurate data will come from analysis of individual generators — to which Ondayko agreed.

“This is not absolute … but it’s a good line in the sand to see if we are getting the PFR we are expecting or not,” Croop said. “I think more intricate details will work through at the generator evaluation level.”

Ondayko requested PJM consider accounting for future PFR sources and those scheduled for retirement, referencing FERC Order 842 requirements.

“It would give us a better sense of how successful the FERC order is going to be or not going to be,” he said.

2018 Primary Frequency Event Response by Megawatts. | *PJM*

Stakeholders Ponder Meeting Changes

As the schedule for upcoming Operating Committee meetings fills up with obligations from new and continuing task forces, stakeholders pondered getting an earlier start.

OC Chair Dave Souder suggested starting April’s meeting at 8:30 a.m. to account for agenda items related to non-retail behind-the-meter generation business rules. Stakeholders approved a problem statement and issue charge revising the existing manual language during Tuesday’s meeting. (See “PJM Continues Review of Non-retail BTM Generation Business Rules” in PJM Operating Committee Briefs: Feb. 5, 2 0 19.)

“I think the 8:30 start time is a little early,” said Sharon Midgley, of Exelon. “And the beginning of the meeting is sometimes important, particularly if there are any controversial endorsement items.”

Jim Benchek, of FirstEnergy, agreed an earlier start time would prove difficult for stakeholders commuting and instead suggested staying an hour later.

Souder proposed implementing a working lunch for future OC meetings, to which no stakeholders voiced any objections. He said PJM’s Dave Anders also suggested moving meetings to Thursday mornings beginning in 2020 so staff could have more time to provide accurate and updated reference materials. Planning Committee meetings would occur Tuesday mornings, instead.

— Christen Smith

March 7, 2019

NextEra Gains Incentive for Hartburg-Sabine Project

By Robert Mullin

FERC on Tuesday authorized NextEra Energy Transmission (NEET) Midwest to recover all “prudently incurred” costs related to the company’s investment in the Hartburg-Sabine Junction 500-kV project in East Texas, MISO’s second-ever competitively bid transmission project (ER1 9 -775).

The commission’s granting of the abandoned plant incentive ensures NextEra will be covered for 100% of its investment if the project is canceled for reasons outside the company’s control.

The Hartburg-Sabine project will consist of a new 23-mile 500-kV transmission line, four short 230-kV lines and a new Stonewood substation that will connect the longer line with the existing Hartburg substation. The project is designed to relieve congestion issues and import limitations along the Texas-Louisiana border.

MISO awarded the project to NextEra last November following a competitive bidding process in which the company’s proposal scored 97 out of a possible 100 points, beating out 11 other competitors. (See Next E ra Wins Bid to Build MISO’s 2nd Competitive Project.) NextEra’s proposal capped total project costs at $114.8 million, less than MISO’s $122 million estimate, and demonstrated a 2.2-1 benefit-to-cost ratio.

Under its FERC-approved formula rate, NextEra is already entitled to a 50-basis-point adder for RTO participation and a mechanism for later recovery of pre-commercial and formation costs along with a carrying charge. In its request for the abandoned plant incentive, NextEra noted the Hartburg-Sabine project is still subject to multiple layers of review, including those by the U.S. Fish and Wildlife Service, Federal Aviation Administration and EPA, as well as those by several Texas state and county agencies.

NextEra pointed to other nonregulatory risks confronting the project.

“In this regard, NEET Midwest states the project was included in the 2017 [MISO Transmission Expansion Plan] primarily because of the economic benefits to be derived from the project,” the commission wrote. “However, NEET Midwest points out that under the MISO Tariff, significant changes in those anticipated benefits could result in MISO reconsidering and potentially canceling the project.”

The company said it has no rate base or other revenue stream that could potentially offset any costs sunk into the project.

In approving the incentive, the commission noted it has previously found reliability and congestion-relieving projects selected through a regional transmission planning process are entitled to the rebuttable presumption established under Orde r 679, which requires an applicant to show “there is a nexus between the incentive sought and the investment being made.”

“We find the total package of incentives, including the previously granted incentives, as modified as part of the selected proposal, is reasonable because it addresses the risks and challenges associated with the development of the project,” the commission said.

March 6, 2019

ERCOT Summer Forecast: Record Demand, Alerts

By Tom Kleckner

E R COT is forecasting record peak demand with increased potential emergency alerts this summer, given its historically low planning reserve margin of 7.4%.

The grid operator said Tuesday it expects a summer peak of 74.9 GW, which would break the mark of 73.3 GW set just last summer. ERCOT has 78.2 GW of capacity on hand to meet that demand, according to its preliminary summer seaso n al assessment of resource adequacy (SARA).

March Seasonal Assessment of Resource Adequacy | *ERCOT*

David Bellman, head of power for Houston-based Skylar Capital Management, told RTO Insider the “surprising thing to note” is this year’s projected peak is almost 3% higher than last year’s predicted high of 72.8 GW, as well as being 1.6 GW higher than 2018’s actual peak.

Bellman said the forward markets lost about $2/MWh Tuesday and were trading at $138/MWh.

“The increase in peak demand and drop in resource adequacy means we expect emergency alerts to be issued this summer,” Resource Adequacy Manager Pete Warnken said during a media call.

Declaring an energy alert during scarcity situations would free up the ISO to tap into a variety of additional resources to meet demand. Those resources include demand response products, resources normally set aside to provide operating reserves, additional generation or imports from neighboring RTOs, and calls for voluntary conservation measures.

Dan Woodfin, ERCOT’s director of system operations, said the grid operator has 900 MW of emergency response service available and another 1,300-1,800 MW of capacity from load-management programs.

The grid operator’s reserve margin dropped from 8.1% to 7.4% with the December retirement of the Gibbons Creek coal plant. Warnken said 500 MW of summer capacity, much of it from wind and solar projects, has been delayed until late spring and early summer.

The final summer SARA report will be released in May and will reflect the expected summer weather conditions.

ERCOT also released its final SA R A for the spring months (March-May), saying it has sufficient capacity (81.3 GW) to meet a forecasted spring peak of 61.6 GW. The system has added 577 MW of planned gas, wind and solar resources for the spring, with another 50 MW of wind and solar capacity expected to be available for the season’s start.

March 6, 2019

Senate ENR Committee Discusses Climate Change

By Michael Brooks

The hearing the Senate Energy and Natural Resources Committee held Tuesday was perhaps less noteworthy for what was said than the fact it even happened.

Chaired by Sen. Lisa Murkowski (R-Alaska), committee members and panelists discussed the electricity industry’s role in mitigating climate change. According to ranking member Joe Manchin (D-W.Va.), it was the first hearing the committee had held on climate change since 2012.

Compared to the House of Representatives, now in Democratic hands and holding almost weekly hearings on climate change, the GOP-controlled Senate has been nearly silent on the phenomenon. (See House D e mocrats Put Climate Change Front and Center.) That will change as Senate Democrats up their rhetoric and make it a central platform of their 2020 re-election campaigns, as The New York Times report e d Monday.

Sen. Lisa Murkowski (R-Alaska) opened the hearing displaying this graphic, which shows the rapid decrease in Bering Sea ice, as a demonstration of the impacts of climate change. | *Rick Thoman, Alaska Center for Climate Assessment and Policy*

Tuesday’s hearing, however, lacked partisan rancor. Instead, the few senators who attended and the panelists focused on increased investment in research and development of new technologies to make generating resources cleaner and more efficient.

This was in part because of the committee’s jurisdiction: It does not oversee EPA nor does it have direct oversight of U.S. greenhouse gas emissions. Those are under the charge of the Environment and Public Works Committee.

“I think it’s important to point out, we know here on the committee we have jurisdiction in certain areas,” Murkowski said. “We do not have complete jurisdiction over climate change — we recognize that — but we do have a role to play in developing reasonable policies that can draw bipartisan support that I think will be a pragmatic contribution to the overall discussion.”

But the homes of the committee’s leaders also played a large role in what was discussed. Murkowski, who opened the hearing with a list of adverse effects being felt by Alaska — including rapidly de c reasing Bering Sea ice and a more challe n ging Iditarod Trail Sled Dog Race — has broken away from her party in even discussing the issue. Manchin, who frequently sides with Republicans on the committee, criticized regulations as a solution, saying they disproportionately hurt rural residents and coal miners, like those in West Virginia.

“Therefore, the path to a climate solution must offer West Virginians opportunity — not additional economic burdens,” Manchin said. “Chairman Murkowski and I share a deep concern for our rural communities and seek to use this committee as a means of identifying and legislating pathways to ensure our constituents have a role in the clean energy future.”

Manchin said the use of fossil fuels to generate electricity is “not going away anytime soon” and noted China and India are increasing the use of coal. Kenneth Medlock, senior director at Rice University’s Center for Energy Studies, put an exclamation mark on Manchin’s point by noting China has 254 GW of coal-fired capacity under construction — more than the entire U.S. coal fleet.

“So … when we think about CO₂ being a problem of the global commons, it really means we need to lead by example,” Medlock said.

Manchin jumped in, asserting that the U.S. has led by example, mandating technologies such as scrubbers and low-NOx boilers. “They’re not implementing any of those,” he said.

Medlock replied his point was that the U.S. needs to lead in innovation, such as developing scalable carbon capture and sequestration (CCS), a technology seen as key to reducing emissions and even potentially reversing climate change. He noted federal R&D spending has been declining for the last 30 years “and that doesn’t make any sense.”

Susan Tierney, senior adviser at Analysis Group, said, “China is actually an unsung story on a lot of innovations,” building advanced reactors and wind turbines.

“The U.S. needs to continue to advance technology leadership … so we don’t lose to them on these competitive technologies,” she said.

Notably absent from the hearing was EPW Committee Chair John Barrasso (R-Wyo.), who last month reintroduced the Utilizing Significant Emissions with Innovative Technologies (US E IT) Act. The bill, which enjoys bipartisan support, would fund CCS R&D and create a board of experts to oversee projects under development.

March 6, 2019

NEPOOL Debates Winter Energy Security Moves

By Michael Kuser

New England Power Pool stakeholders are this week discussing potential changes to IS O –NE wholesale energy markets that would include interim generator compensation to improve winter fuel security and the introduction of a multi-day-ahead market (M-DAM).

ISO-NE Principal Analyst Andrew Gillespie will on Wednesday pres e nt the NEPOOL Markets Committee conceptual details as well as a timeline for a fuel security FER C filing by Nov. 15, in line with the RTO’s January reque s t for a four-month extension to file a plan, currently pending before the commission (EL18-182).

In the motion for an extension, ISO-NE said, “New England’s winter energy issues are fundamentally an energy supply problem, not a generation capacity shortfall problem,” but the presentation to the MC acknowledges the RTO has “heard a number of questions and concerns about the length of the market horizon, primarily how this may not align with participants’ hedging strategies … “

ISO-NE filed the rule revisions after the commission last July denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022.

Interim Compensation

Several NEPOOL stakeholders have proposed alternatives to the RTO’s market mechanisms regarding interim compensation treatment to improve fuel security.

David Cavanaugh, vice president of regulatory and market affairs for energy services firm Energy New England (ENE), was slated Tuesday to pre s ent an amendment to the RTO’s proposed Tariff language. The outcome of the planned discussion and vote, the first of a two-day MC, will not be revealed until NEPOOL posts the meeting minutes.

ENE argues the RTO’s proposal “far exceeds” its stated goal of retaining resources for fuel security reliability and preventing uneconomic retirement bids and its “resource eligibility is too broad and extends beyond target resources.”

The company instead recommends modifying ISO-NE’s proposal to limit compensation to oil, natural gas, demand response and electric storage resources.

“Compensation should be limited to resources capable of improving winter energy security by providing incremental reliability benefits,” ENE said. The RTO estimates costs for the interim program will exceed those of the last winter reliability program by $100 million, a figure ENE says drops to around $51 million under its amendment.

Winter reliability program costs were capped in advance and ranged from $30 million to $70 million annually. The RTO replaced that program last June with the Pay-for-Performance program, which is designed to fund performance bonuses mostly through penalties on nonperforming resources and not directly by customers. (See NEPOOL Debates F u el Security, Cost Allocation.)

ISO-NE CEO Gordon van Welie last month said energy security risks “could become a year-round concern” as the grid transitions to distributed and renewable generation and “eventually nearly all resources in the fleet will have some energy limitations.” (See ISO-NE Chief Sees ‘Year-round’ Energy Risks C o ming.)

The Pilgrim Nuclear Power Station on Cape Cod is scheduled to close down permanently later this spring, increasing New England’s fuel security risks. | *Entergy*

Abigail Krich, president of Boreas Renewables, was to present on behalf of the Union of Concerned Scientists a proposal guaranteeing that energy actually provided would receive the same compensation as inventoried energy.

Forward Capacity Auction 13 last month awarded payments to new renewable energy resources and also made ISO-NE the first grid operator to implement a market-based mechanism to accommodate state-sponsored resources. State-sponsored Vineyard Wind won a 54-MW capacity obligation from a retiring resource in the substitution auction. (See ISO-NE Com p letes FCA 13 Despite Controversy.)

Count the Days

The Massachusetts attorney general’s office commissioned London Economics International (LEI) to prepare an alterna t ive to the RTO’s M-DAM proposal, which LEI found “conceptually and operationally complex” and would “require substantial administrative costs.”

Complete revamping of the day-ahead market (DAM) into M-DAM is an unproven mechanism and may not meet all of the RTO’s goals, LEI concluded, proposing instead a Forward Stored Energy Reserve ancillary service with updated technical methods to provide parameter values for the forward capacity market.

The advisory firm contends that while the RTO’s proposal might increase revenues for some power plants and prevent inefficient retirement, the resulting higher energy prices may lower net cost of new entry, which would suppress capacity market prices and potentially accelerate retirement.

FSER Timeframe: Forward stored energy reserve timeframe should balance ISO-NE’s ability to forecast its need for reserves versus the time it takes to arrange fuel or other necessary inputs to stored energy. | *London Economics*

LEI said its proposal meets the ISO-NE’s needs and Massachusetts’ goals of incorporating market signals, supporting operational visibility and helping prevent inefficient retirement, while its blend of old and new components creates a “solid foundation for winter energy reliability.”

Calpine is scheduled to pre s ent again its case for a Forward Enhanced Reserves Market (FERM), with Senior Analyst for Government and Regulatory Affairs Rebecca Hunter arguing all problems that fall within a planning horizon time frame are left unsolved without a forward price signal. (See “Market Reaction,” New England Talks Energy Security, Pu b lic Policy.)

FERM would have no offer cap, but awards to resources with capacity supply obligations would be incremental to the clearing price. In addition, FERM resources would have daily day-ahead must-offer obligations in winter months only, and the construct would allow participation from resources without a supply obligation, such as energy-only resources that only plan to be available for peak days in the winter.