The Maryland Public Service Commission on Thursday approved Skipjack Offshore Energy’s decision to use fewer, larger turbines in its offshore wind project, rejecting objections by Ocean City officials.
The PSC awarded offshore wind renewable energy credits (ORECs) for the 120-MW Skipjack project and the 248-MW US Wind project in May 2017.
Skipjack had initially proposed using Siemens’ 8-MW turbine but said the selection was subject to change because of continuing improvements in turbine design. In June 2019, Skipjack notified the PSC that it would switch to General Electric’s new 12-MW Haliade-X turbine, prompting the commission to solicit comments and hold a public hearing on the change. Skipjack said the Haliade-X would produce more power in medium-wind speeds and increase the project’s capacity factor.
The Maryland Energy Administration, the Office of People’s Counsel and the commission’s technical staff all supported the switch to the larger turbine, saying it is more efficient and could reduce costs for ratepayers.
In its order Thursday, the commission concluded that the change is consistent with the Maryland Offshore Wind Energy Act and the public interest because it will allow Skipjack to use only 10 or 12 turbines instead of 15.
The order selecting Skipjack “includes dozens of conditions whose purpose was to mitigate risk to ratepayers and maximize value to the state of Maryland. Included therein is the requirement that Skipjack utilize ‘best commercially reasonable efforts to minimize the daytime and nighttime viewshed impacts’ of its project, ‘including through reliance on best commercially available technology at the time of deployment,’” the commission wrote.
GE’s 12-MW Haliade-X offshore wind turbine prototype | GE
It also said the Haliade-X is “well-suited to the wind conditions in the Mid-Atlantic where low- to medium-wind speeds predominate.”
Ocean City contended the larger turbines would have a negative visual impact because they are three times taller than the highest building in the city.
With the new design, the diameter of the turbines’ rotors will increase from 590 feet to 721 feet, and the tip height will increase from 641 feet to 853 feet. But the commission noted the 12-MW turbine layout will take up just 7% of the visible horizon from Ocean City versus 18% in the 8-MW configuration. In addition, the nearest turbine will be 21.5 or 22.7 miles from shore versus 19.5 miles as originally planned.
The commission rejected Ocean City’s request to order Skipjack to move the wind farm to 33 miles offshore.
“First, the Maryland Offshore Wind Energy Act of 2013 requires that offshore wind turbines be placed between 10 and 30 miles off the coast of the state. If the project is located beyond those geographical constraints, it is not eligible for ORECs approved by the commission,” the PSC said. “Second, the Skipjack project must also be located within the specific area of federal waters leased to Skipjack by [the U.S. Bureau of Ocean Energy Management]. BOEM determined the location of the Delaware Wind Energy Area through a multiyear research and review process, which included intergovernmental stakeholder input, including state and local governments along the Delmarva coast. BOEM also considered the location of shipping lanes and other existing uses of the federally regulated outer continental shelf. That multiyear endeavor should not be easily disregarded by the commission.”
The PSC, however, scolded Skipjack for what it said were “deficient” outreach efforts to stakeholders. “Skipjack’s engagement with Ocean City appears meager. For example, Mayor [Richard W.] Meehan testified that Skipjack has not provided routine outreach to Ocean City representatives or stakeholders for the past several years.”
It ordered the developers to “re-engage” with stakeholders and provide the commission reports on its efforts every six months.
NYISO is nearing a vote on market participation rules for hybrid storage and generation resources, with plans to submit the proposal to FERC in 2021.
Stakeholders on Wednesday spent more than three hours discussing proposed Tariff language on co-located, front-of-the-meter energy storage and wind or solar generation.
The ISO’s proposal would allow each unit in a co-located storage resource (CSR) to have its own single point identifier — one for the energy storage resource (ESR), and one for the wind or solar generator, referred to as an intermittent power resource. Each unit also would have separate energy resource interconnection service (ERIS) and capacity resource interconnection service (CRIS) values.
NYISO’s proposal would allow each unit in a co-located storage resource (CSR) to have its own single point identifier (PTID) — one for the energy storage resource (ESR), and one for the wind or solar generator, referred to as an intermittent power resource (IPR). Each unit also would have separate energy resource interconnection service (ERIS) and capacity resource interconnection service (CRIS) values. | NYISO
The CSR units would be settled at the locational-based marginal price at the point of interconnection. Only the ESR unit would be eligible to provide reserves or regulation.
The ISO, which has held seven prior meetings since beginning the hybrid storage project in January, had considered two other participation options in May but decided not to propose them. (See NYISO Explores Hybrid Interconnection Processes.)
NYISO will use a scheduling constraint to determine feasible energy and reserve schedules for units within the CSR, the ISO’s Kanchan Upadhyay told stakeholders during a joint meeting of the Market Issues, Installed Capacity and Price Responsive Load working groups.
Resources serving a host load would not be permitted to participate in ISO markets as a CSR. The ISO initially proposed requiring them to participate as a behind-the-meter net generation resource or a distributed energy resource, but officials are reconsidering that based on stakeholder feedback at Wednesday’s meeting.
The ISO’s Amanda Myott led a discussion on proposed Tariff revisions governing CRIS for hybrid generation and storage.
The ERIS for the intermittent generator would be limited to the CSR injection capability plus the full withdrawal capability of the storage resource.
Under proposed transition rules, projects with separate positions in the interconnection queue as of the effective date of the Tariff changes could combine and proceed under a single interconnection request as a CSR as long as both projects are behind the same point of injection.
Sarah Carkner gave a presentation on proposed ESR bidding rules for installed capacity (ICAP) suppliers with an energy-duration limitation.
The ISO originally proposed requiring that ESR ICAP suppliers use the ISO-managed energy level bidding parameter for their day-ahead bids.
FERC, however, said the proposal did not comply with Order 841’s requirement “to allow resources using the participation model for electric storage resources to self-manage their state of charge.” It ordered NYISO to allow ESRs that supply capacity to bid either ISO-managed or self-managed.
| 8minute Solar Energy
Earlier this year, FERC approved NYISO’s proposal to require the ESR ICAP supplier to bid, schedule and notify the ISO of its full range, from withdrawal to injection. (See NYISO’s 2nd Storage Compliance Almost Hits Mark.)
NYISO proposes requiring ESR ICAP suppliers with an energy-duration limitation to either bid or schedule a bilateral transaction for their full injection range for all hours during the “peak load window,” or notify the ISO of a derate. For hours outside of the peak load window, they would be required to bid their full withdrawal range or notify the ISO of a derate. (The peak load window is between the hours beginning 13-18 in summer and 16-21 in winter. When the system reaches 1,000 MW of duration-limited resources, the window will increase from six to eight hours.)
The ISO plans to bring the new bidding rules for ESR ICAP suppliers with an energy-duration limitation to upcoming meetings of the Business Issues and Management committees and have them effective for the day-ahead market run for May 1, 2021.
As the COVID-19 pandemic continues, NERC told stakeholders Wednesday it will keep its offices in Atlanta and D.C. closed and extend its work-from-home policy through the end of the year, while evaluating in-person stakeholder meetings on a case-by-case basis.
Under NERC’s reopening plan, its current remote work posture will remain in place at least through the end of the year. | NERC
Speaking to the Corporate Governance and Human Resources Committee, Teri Stasko — NERC’s assistant general counsel and director of enforcement — credited the organization’s “dedicated and perseverant” employees for keeping their work going despite being forced to stay home with no transition time.
Technology has also proven unexpectedly helpful in expanding NERC’s engagement with industry and other stakeholders, with Stasko noting that the June meeting of the Reliability and Security Technical Committee, held entirely online, attracted more than twice as many attendees as the previous in-person meeting in March. (See NERC RSTC Briefs: June 10, 2020.) In addition, she praised the efforts of NERC’s management to “creatively adapt” to the challenges of motivating staff virtually.
However, though these adaptations have allowed individual productivity to remain high, Stasko acknowledged the psychological toll taken on NERC staff by the indefinite extension of both the office closure, which was originally planned to end May 25, and the remote work posture, previously scheduled to last through July. (See Align Tool Set for 2021 Rollout.) Several teams have complained that they feel “less aligned” and miss the opportunities for spontaneous conversations provided by in-person gatherings.
COVID-19 Likely Still Holds Surprises
NERC’s extended remote work posture and office closure is based both on what is already known about the coronavirus, as well as on several consciously conservative presumptions:
The full range of the virus’s transmissibility and severity, along with other characteristics, is still unknown.
A widely available vaccine or effective treatment is unlikely in 2020, meaning that social distancing and face coverings will still be needed.
Local conditions affecting NERC’s employees are likely to vary across the Atlanta and D.C. areas.
Utilities and other stakeholders will likely continue to work remotely, limit travel and restrict nonessential visitors from facilities for the rest of the year.
“As we prepared this presentation, we realized that we could probably remove the NERC logo from the slide deck and add almost any entity’s logo, as we are likely taking similar actions,” Stasko said. NERC hopes to allow staff to return to the office on a voluntary basis in the first half of 2021, but teleconferencing will remain the norm and visitors will be highly restricted.
While NERC’s offices are closed, the organization is putting extensive modifications in place to help enforce social distancing protocols. Changes include traffic directions in hallways and other common areas, and strict enforcement of occupancy limits in meeting and break rooms. These measures are being complemented by modifications by the property management companies for both locations, such as improved cleaning protocols for the heating, ventilation and air conditioning systems; elevator occupancy limits; and alterations to restrooms.
NERC activated its Business Continuity Plan early in the pandemic, closing its offices and shifting upcoming meetings to conference calls or video conferences. Some events, such as the security-focused conference GridSecCon — originally scheduled for Oct. 20-23 — have been canceled outright, while others have been rescheduled, like the inaugural Electric Power Human Performance Improvement Symposium that was moved from September to March.
A grueling Western heat wave that caused rolling blackouts and sparked wildfires across California is expected to abate somewhat starting Thursday, potentially easing the strain on the state’s overburdened electrical system.
But with temperatures still soaring into the triple digits Wednesday, and smoke from dozens of fires darkening skies, CAISO said it was hoping for conservation efforts like those which helped avoid blackouts Monday and Tuesday.
CAISO CEO Steve Berberich on Wednesday credited the U.S. Navy, companies such as Tesla and household consumers for reducing demand by about 3,000 MW the past two days. That helped prevent what CAISO had predicted would be the most extensive blackouts in state history.
Berberich said the forecast was correct, but unexpected conservation turned things around. CAISO’s control room operators saw a “dramatic flattening” of demand in the afternoons, Berberich said.
“The load pull in the morning on Monday was probably best described as ‘frightening,’” Berberich told reporters Wednesday. “By 1 o’clock, we had 46,000 MW on the system already.”
A satellite photo shows fires, many started by lightning strikes, burning in California on Wednesday. | NASA
The 1 p.m. demand was the same as the late-afternoon peak Friday, when rolling blackouts hit hundreds of thousands of customers, he noted.
“Absent the load curve turn at 3 o’clock, we would not have made it,” Berberich said.
In a separate press conference, Gov. Gavin Newsom said Wednesday could be the “last challenging night for CAISO.” Temperatures are predicted to drop into the upper 90s and low 100s starting Thursday.
Beginning last week, high temperatures in many parts of the state shot well above 100 degrees for six days straight. Death Valley set a possible world-record temperature of 130 degrees on Sunday.
California Gov. Gavin Newsom | Office of the Governor
At the same time, temperatures in Phoenix, Las Vegas and elsewhere in the West topped 110 degrees, while normally cool cities such as Portland and Seattle experienced unusual heat. The extent of the heat wave dried up electricity from neighboring states that California could have otherwise imported to meet demand.
Berberich and Newsom said efforts had been made inside California to obtain additional electricity by increasing generation at hydroelectric dams, bringing natural gas peaker plants online and reaching out for help to non-CAISO utilities such as the Los Angeles Department of Water and Power.
The unusual heat wave also brought thunderstorms and lightning strikes that started hundreds of fires, including 23 major blazes, some of which consisted of “complexes” of lightning-sparked fires.
The SCU Lightning Complex had burned 85,000 acres in the mountains above the southern San Francisco Bay Area and was only 5% contained by Wednesday afternoon, according to the California Department of Forestry and Fire Protection.
The LNU Lightning Complex near the city of Vacaville had scorched 46,000 acres and was 0% contained on Wednesday. It drove evacuations, rained ash on San Francisco and Sacramento and turned the sky yellow with smoke.
New Jersey legislators are considering a bill that would require the Board of Public Utilities to study the implications of withdrawing from PJM and either going it alone or joining NYISO.
NJ Sen. Bob Smith (D) | NJ Senate
Members of the New Jersey Senate Environment and Energy Committee voted unanimously during a hearing on Monday to advance the bill, sponsored by committee Chair Bob Smith (D), with a series of amendments to the full Senate (S2804).
Smith emphasized that his bill was not aimed at making any definitive answer as to leaving PJM but was created as a way for the BPU to analyze different options for the state’s electric grid and the potential impacts on ratepayers, utilities and energy generators.
“I actually had a whole bunch of calls about this bill saying, ‘What’s the real agenda?’ The real agenda is to get information,” Smith said during the hearing. “Nobody’s made a decision we want to leave PJM. Nobody’s made a decision we want to stay in PJM.”
Bill Language
The bill would require the BPU to conduct a study analyzing and comparing the potential costs and benefit impacts of five different scenarios, including:
withdrawing from PJM and “establishing an electric transmission grid operating independently within New Jersey”;
withdrawing from PJM and joining NYISO;
remaining with PJM;
any other electric transmission grid option that the BPU may consider to be “in the best interest of ratepayers of the state”;
using the fixed resource requirement (FRR) alternative to satisfy the state’s resource adequacy needs and accelerate achievement of the state’s clean energy goals.
The BPU would be required to submit a written report to Gov. Phil Murphy and the legislature concerning the study results within a year of the bill’s passage, including the costs and impacts on renewable energy production, energy storage and distributed electric generation in the state. It also requires the study of any costs, physical or structural changes or regulatory approvals needed if there is a withdrawal from PJM.
Hope Creek Nuclear Generating Station | NRC
The bill requires consultation with stakeholders, including power suppliers and public utilities, FERC, NERC and public and private entities that have conducted studies on transmission grids.
Smith said the BPU has already started public discussions mulling the implications of leaving the PJM capacity market in favor of the FRR option. (See N.J. Investigating Alternatives to PJM Capacity Market.) He said he doesn’t want the legislature to be “the dumbest group in the room” and not have enough information to make an educated decision.
“For anyone out there in the energy world, we’re not sending you a signal that we’re leaving PJM,” Smith said. “We’re sending you a signal that we want to be more informed rather than less informed.”
Current BPU Actions
New Jersey regulators have already taken the first steps in determining whether the state should remain in PJM’s capacity market or to go in a different direction to meet the state’s electricity needs.
The BPU voted March 27 to investigate if staying in the capacity market will impede Murphy’s goals of 100% clean energy sources in the state by 2050 or increase consumer costs (Docket No. EO20030203). (See NJ Regulators Weighing Input on Capacity Market Exit.)
Some stakeholders said the state should adopt the FRR because the expanded MOPR would hamstring its support for emission-free generation. Opponents said leaving the capacity market could end up costing state ratepayers millions, leaving them at the mercy of monopolistic generators.
PJM Perspective
Asim Haque, PJM vice president of state and member services, gave prepared testimony at Monday’s hearing, saying the RTO estimates that its regional operations, transmission planning and operation of wholesale markets saves between $3.2 billion and $4 billion a year, including $360 million to $460 million a year in New Jersey.
Asim Haque, PJM | PUCO
Haque’s testimony focused on PJM’s regional planning role and how New Jersey residents have benefited for more than 90 years being an integral part of the RTO. He said if the state chooses to “go it alone,” serious challenges would be presented because of the interstate nature of the transmission grid.
“PJM feels confident that New Jersey would continue to find the greatest value for its consumers in being part of PJM,” Haque said. “We believe that the study would show that PJM is the best option for New Jersey and all states in our footprint. Reliability. Affordability. All while trying to assist states in advancing their policy objectives.”
He said he is confident that any study conducted by the BPU would result in the state staying with PJM because leaving has “potentially some deleterious impacts to families and businesses in the state of New Jersey.”
“I understand that in these challenging times, folks are struggling, and this is an extremely complicated endeavor that could prove to be very costly during times of financial recovery,” Haque said. “We do feel confident that New Jersey will continue to find the greatest value for its consumers by being a part of PJM.”
FERC on Tuesday rejected a new argument by the Louisiana Public Service Commission in a 17-year-old case tied to a now terminated agreement among Entergy’s operating companies (EL01-88-023).
Having previously faced rejection from FERC, the PSC framed its argument for refunds to Entergy Louisiana customers in a new light, this time claiming that Entergy’s System Agreement itself — not the Federal Power Act, as the PSC originally thought — was the basis for the “rough equalization” of costs requirement.
Prior to 2015, the Entergy operating companies functioned as one system across four states, although each had different operating costs. FERC in 2005 determined that production costs across the multistate Entergy system were not as equal as Entergy promised and imposed a bandwidth payment remedy among the companies, spurring litigation that’s lasted several years. (See FERC Affirms Ruling Favoring Entergy Bandwidth Calculation.)
The Louisiana PSC has mounted multiple attempts to compel refunds for the period before the 2005 solution, arguing that “large disparities in production costs” began showing up in 2000 without Entergy attempting to distribute production costs more evenly in accordance with its 1982 System Agreement.
This time, the PSC requested rehearing of FERC’s decision not to order refunds for 2001-2003 and asked it to consider a new refund period from 2003 through mid-2005 on the basis that Entergy violated its own tariff, not the FPA. (See La. PSC Complaints Denied in Entergy System Disputes.)
Entergy Tower in New Orleans
FERC refused both requests on Tuesday.
“We are not persuaded by the Louisiana commission’s arguments on rehearing concerning its new refund claim, and we continue to find that it was too late in this 17-year-old proceeding for the Louisiana commission to change its theory of the case and raise a new claim,” FERC said.
Beyond that, the commission said the now defunct System Agreement and the FPA are not the same.
“The System Agreement and the FPA therefore do not constitute potential alternative bases for the rough equalization requirement. Rather, the System Agreement has been structured in a way that was intended to achieve rough equalization and thereby satisfy FPA standards,” FERC said.
It also said the PSC failed to point out a provision of the System Agreement that Entergy violated.
“Instead, it treats rough equalization as a general, albeit unarticulated, duty applicable to the parties, rather than as a result that the specific duties set forth in the System Agreement are expected to achieve,” FERC said.
The PSC has long argued that Entergy Arkansas “reaped” over-collections of system payments. In its order, FERC again reminded the PSC that Entergy as a whole didn’t over-collect on rates.
“The Entergy Operating Companies operate[d] on a single-system basis, and this case involves a zero-sum allocation of costs among the operating companies under the System Agreement,” FERC said.
Entergy Arkansas gave notice in 2005 to leave the System Agreement in 2013, asserting it was effectively subsidizing the other Entergy companies. Entergy Mississippi followed in 2007, seeking a 2015 exit. FERC approved the departures in 2009 and ruled that neither utility was bound to compensate the remaining unified Entergy companies upon their departures.
The PSC also argued that the presiding judge over the bandwidth remedy issue in 2005 implied that refunds were appropriate for the 2003-2005 period and that FERC could use its discretion bestowed under Section 309 of the FPA to go beyond the law itself and order refunds beyond a 15-month span.
FERC said the reference to Section 309 was an invention of the PSC and that it couldn’t “identify any pleading or order in the long history of this proceeding that invokes, or even mentions, FPA Section 309.”
The Bonneville Power Administration has pulled back into a more cautious operational posture in response to the COVID-19 pandemic after relaxing restrictions in June, agency officials said Tuesday.
The return to a “Response Level 3” posture (from Response Level 2-A) comes just two months after BPA lifted restrictions enough to resume work on some maintenance and construction projects. That move aligned with the reopening of Pacific Northwest economies following stay-at-home orders issued by state governments in March.
Now the federal power marketing administration says it is “standing down” on any nonessential transmission or generation projects.
“We’re deferring all maintenance and construction projects that are not tied to life safety or reliability,” Nadine Coseo, BPA senior financial analyst, told listeners during a quarterly business review (QBR) workshop Wednesday.
Coseo said the change in posture was driven by agency metrics that consider the region’s caseload of positive COVID-19 tests. Those metrics are showing “small clusters popping up around our territory, especially where the construction crews have been performing their work,” she said. “We determined it was in the best interest for Bonneville to see if the metrics will either flatten or decline again before resuming our former phase.”
BPA on Tuesday assured its customer base of publicly owned utilities that its crews will continue to respond to outages and other emergencies. It will also keep focusing on enabling office staff to telecommute in order to “reduce the concentration of employees in any one location and continue meeting business requirements.”
The agency decided to resume a more restrictive pandemic posture one day after a Aug. 11 QBR call in which it explained that its third-quarter projections show it earning $152 million in net revenues for fiscal year 2020, which ends next month. That estimate puts BPA well above a second-quarter “baseline” case prediction of $110 million and a second-quarter pandemic “bad case” figure of $44 million. It also represents a steep rise from the agency’s rate case target of $12 million for 2020. (See BPA Poised to Weather COVID Impact.)
BPA explained that while reduced expenses account for some of the expected increase in net revenues, the greatest boost stems from increased net operating income — largely the product of higher profits from secondary sales of surplus energy.
During Tuesday’s call, Steve Gaube, a financial analyst with BPA’s power generation division, confirmed that the revenue boost was more the result of high market prices than increased sales volume during what has been an average water year for the region’s hydroelectric producers.
“We did see considerably higher Northwest regional prices, particularly in winter,” Gaube said, adding that BPA expects this month to yield another rise in secondary sales because of high temperatures in the West.
During Tuesday’s call, BPA staff also clarified that the agency discontinued use of a separate pandemic “bad case” because it was equipped to factor pandemic effects into its general third-quarter forecast.
But staff also noted the third-quarter projections don’t consider the impact of BPA’s retreat into Response Level 3, which generates uncertainty around how the renewed delay in capital projects could move some costs into the agency’s expense accounts and reduce the net revenue figure.
Addressing capital projects related to transmission, BPA accountant Kevin Bernards said the third-quarter projections “have kind of shown optimism” about 2020 capital budgets.
“However, the recent decision to return to a more restrictive posture will negatively impact this forecast,” Bernards said. “At this point, it’s still really too early to know the impacts, but this decision will definitely increase the risk that BPA will need to write off a portion of the indirect costs to expense. We’re going to continue to monitor these impacts and just track what the impacts on the capital execution side will look like.”
But BPA’s generation side still foresees no capital project write-offs for this fiscal year despite delays caused by March’s stay-at-home orders, according to Scott Eggimann, a lead accountant.
“I would say the message around this is really we’re in a wait-and-see mode,” Coseo said. “It’s just too early to tell, and we will know more as the year progresses.”
NERC is required to file the variance report with FERC every quarter to alert the commission to any differences of more than $500,000 between actual and planned spending for the year to date in any revenue or expense categories. In addition to filing with FERC, the report will be reviewed by NERC’s Finance and Audit Committee at its meeting Wednesday.
Big Savings in 2020 Travel
For the first two quarters of 2020, NERC’s actual income came to $40.9 million, compared to the $41 million in its 2020 business plan and budget. Four revenue and expense categories were under budget by more than $500,000:
Meetings and travel: currently $927,020 under budget (55.8%), expected to end the year $2.4 million under budget because of pandemic-related cancellations of in-person meetings and travel reductions.
Consultants and contracts: currently $560,730 under budget (9%) because of “timing of expenditures.” Increased spending on contract labor in the Electricity Information Sharing and Analysis Center (E-ISAC) for the rest of the year is expected to bring this category to $27,073 under budget (0.2%) by year-end.
Office costs, professional and miscellaneous expenses: currently $678,338 under budget (11.6%), expected to be $370,868 (3.2%) over budget by year-end because of higher software license and maintenance costs, as well as support and maintenance costs for leased equipment.
Fixed asset additions: currently $1.6 million under budget (67.3%) but expected to end the year $2.2 million over budget because of “unbudgeted costs for the Secure Evidence Locker project” (part of NERC’s Align software project).
In addition, the Personnel category is expected to be $1.7 million under budget by the end of 2020 (3.7%) because the organization deferred hiring for 11 open positions to 2021. The planned use of contract labor for E-ISAC positions that were budgeted for full-time employee equivalents contributed to the underrun in this category as well.
Net financing activity is also projected to be $1.7 million under budget at year-end, though this is because of NERC’s decision to fund the Align project — which was not originally included in the organization’s 2020 budget — with a $2 million credit facility along with $1.8 million from NERC’s operating contingency reserves (OCRs). (See FERC Approves NERC’s Align Spending Request.)
“The 2020 budget anticipated that NERC would pay off more in principal than it would receive in loan proceeds, but … NERC is [now] projected to receive more in loans than it will pay off in principal,” the organization said.
Return to Normalcy Planned for 2022
In addition to the pandemic’s short-term cost impacts, NERC and the regional entities have signaled in their upcoming budgets that they expect long tails from the pandemic. NERC’s 2021 business plan and budget makes cost control a priority, with the goal of keeping its assessment flat from the prior year in response to economic uncertainty among the electric industry and load-serving entities. (See NERC Aims for Cost Control in 2021 Budget.)
The organization has already warned registered entities that its pandemic-related cost controls will need to be offset by budget increases in later years, with rises of 5% planned for both 2022 and 2023. (See NERC: Post-COVID Budget Rises Likely.) NERC described the post-2021 budget projections as a “measured return” to pre-pandemic planning assessments that also reflected the cost of deferring hires and other investments.
NERC’s projected 2020 budget surplus has already attracted interest from industry stakeholders, with the Canadian Electricity Association suggesting that the organization use the resulting higher-than-expected OCRs to provide additional relief to registered entities. In response, the ERO pointed out that OCRs are already being used to fund development costs for Align, and it preferred to keep the rest in reserve in case additional unexpected spending is required.
The New England Power Pool’s Markets Committee held a three-day meeting last week, with much of the time devoted to revising parameters and inputs for Forward Capacity Auction 16 (capacity commitment period 2025/26). Here are some of the highlights.
ISO-NE Seeks to Sunset Forward Reserve Market
ISO-NE is seeking to sunset the Forward Reserve Market (FRM) to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative.
The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves.
ISO-NE’s Jonathan Lowell told the committee that transmission investments and market changes, including the anticipated implementation of ESI, have or will relieve many locational constraints and reward resource flexibility. Because of those changes, and prior recommendations by the External Market Monitor, the RTO is proposing sunsetting the FRM on June 1, 2025, assuming FERC approves related ESI components.
Lowell said FRM and ESI cannot “peacefully coexist” because both procure 10- and 30-minute reserves and that FRM’s weaknesses cannot be corrected through incremental fixes. FRM does not use a two-settlement market design, relies on administratively calculated penalties and requires real-time energy offers above cost, resulting in an inefficient co-optimized real-time dispatch, the RTO says.
FRM was created as a supplemental payment to peakers. Although ESI has a different primary purpose — creating incentives to ensure energy security in real time — the two constructs would both award commitments prior to real time.
The RTO would align the FRM sunset with the net cost of new entry updates for FCA 16, contingent on FERC’s acceptance of 10- and 30-minute day-ahead reserves in either the RTO or NEPOOL version of the ESI proposal. (See ISO-NE Sending 2 Energy Security Plans to FERC.)
To receive a FERC order by March 1, 2021, ahead of the retirement bid delist window, the RTO plans to make the sunset filing contemporaneously with Forward Capacity Market parameters by the end of the year. CONE and other assumptions used in FCA 16 depend on estimates of ancillary revenues from sources such as FRM.
Lowell said the RTO is not concerned about removing incentives for new peakers to supplement increasing amounts of intermittent resources because the region has ample generation and fast-start capacity. Market changes over the last 10 years have added rewards for resource flexibility: fast-start pricing, energy market offer flexibility, Pay-for-Performance, sub-hourly settlements and the existing real-time replacement reserve, he said.
The RTO will present proposed Tariff changes to the committee Sept. 8-10, with an MC vote planned for October and a Participants Committee vote in November.
Wholesale Market Consequences of Gross Load Reconstitution Proposal
Bruce Anderson of the New England Power Generators Association (NEPGA) asked the RTO to make a market rule change to avoid suppressing capacity market prices as a result of its proposed gross load forecast reconstitution methodology.
The NEPOOL Reliability Committee on July 21 supported Tariff changes to reduce the quantity by which it reconstitutes the long-term peak load forecast. Instead of including all energy efficiency resource megawatts on the system, it would be limited to those that have cleared an FCA. The intent is to produce gross load forecasts that reflect the amount of EE that will clear in that FCA and avoid counting EE resources with capacity supply obligations (CSOs) as both supply and demand.
The change approved by the RC would set the quantity of load reconstitution based on a trend line reflecting historical measures of EE CSOs compared to the level of installed EE.
Anderson said limiting reconstitution to the trend line based on the forecast could result in EE megawatts clearing in the FCA exceeding the level of forecast EE megawatts reconstituted for that auction.
“If that were to occur, the FCA will understate demand and artificially suppress clearing prices,” NEPGA said in a presentation. “In addition, a lack of a companion market rule change will leave open the possibility of ‘double counting’ EE megawatts, i.e., to count those megawatts as both supply (though the acquisition of a CSO) and demand (by failing to reconstitute for that quantity).”
Anderson gave an example in which the trend line found 2,000 MW of EE will clear in the FCA, but the market clears 2,500 MW.
“The additional 500 MW of EE CSO cleared beyond the reconstitution would have the same effect as understating the capacity requirement by 500 MW and artificially suppress the FCA clearing price. The market would also double count the 500 MW,” he said.
Anderson suggested the region adopt one of two options:
Do not qualify EE as capacity supply above the level of EE reflected in the reconstituted peak load forecast; or
add a constraint in the FCA clearing process to prevent EE megawatts from clearing beyond the level of EE reflected in the peak load forecast.
NEPGA asked that the RTO agree to change Market Rule 1 before the September PC vote on the Tariff changes. It asked that the market rule changes be effective for the first implementation of the Tariff change in FCA 16.
Dynamic Delist Bid Threshold
ISO-NE’s Matt Brewster briefed stakeholders on a proposed revision to the methodology the RTO uses to recalculate the dynamic delist bid threshold (DDBT) for FCA 16. The threshold was last updated for FCA 13.
The DDBT sets the price range above which static delist bids are subject to pre-submittal and cost reviews.
Suppliers controlling enough capacity to benefit from market power whose bids exceed the threshold may have those bids reduced by the Internal Market Monitor.
Brewster said the RTO attempts to identify delist bids that may represent market power without unnecessarily interfering in competitive price formation.
ISO-NE’s proposed recalibration method would estimate the competitive clearing price for the next FCA using public data: the last FCA’s cleared supply and clearing price and forecasted demand changes (net installed capacity requirement (ICR), net CONE) for the next FCA.
| ISO-NE
Brewster said the recalibration estimate showed an average 25% error for FCA 9 through 15 compared with a 39% error with the current “manual” estimation.
He said the proposal’s use of current and forward-looking market information should improve accuracy and allow it to “catch up” with unforeseen market changes by the next period. It also will be aided by the recent transition to demand curves based on the marginal reliability impact (MRI) of capacity, he said.
The committee also heard from Vice President of Market Monitoring Jeff McDonald, who said he sees the function of the DDBT as avoiding mitigation for resources whose bids are too low to create market power concerns. “Constructing the DDBT to achieve this goal requires a method that can reasonably be expected to produce a threshold price that is below the auction clearing price,” he said in a memo to the committee.
McDonald said expanding the function of the DDBT to “support” prices or “complement” the Competitive Auctions with Sponsored Policy Resources (CASPR) could interfere with competitive price formation. “I am not in favor of expanding the function of the DDBT specifically to (i) serve a price support purpose or (ii) increase the amount of capacity that may opt into the Supplemental Auction. Artificial price supports (whether explicit or by way of allowing uncompetitive bidding) introduce inefficiencies, resulting in excess capacity and cost.”
Parameters for FCA 16
ISO-NE’s Deborah Cooke gave a presentation on the recalculation of gross CONE, net CONE and offer review trigger prices (ORTPs) for FCA 16 with a focus on the proposed “level of excess” adjustment for energy and ancillary service (E&AS) revenue calculations.
Cooke addressed a stakeholder suggestion that net CONE estimates should reflect the region’s current capacity surplus rather than using the assumption that the system is “at criterion” — with supply and demand perfectly balanced to achieve the region’s one-day-in-10-years loss-of-load expectation (LOLE).
ISO-NE estimates its excess capacity for FCA 16 is 791 MW, based on an expected net ICR of 33,165 MW and CSOs from FCA 14 of 33,956 MW. (See ISO-NE Capacity Prices Hit Record Low.)
Cooke said the RTO opposed an approach that used the same gross CONE value but calculated the E&AS offsets reflecting the system at surplus.
ISO-NE opposes the change because increased capacity tends to reduce expected E&AS revenues, which would increase the net CONE estimate above the RTO’s proposed value, Cooke said. She said this would induce new competitive entry, even when the system already has more capacity necessary to meet its LOLE standard.
Brett Kruse of Calpine questioned the RTO’s example, saying he was unaware of any generation developer that would rely solely on ISO-NE price estimates.
“I don’t think any developer of any stature would pretend that we’re at equilibrium as they’re figuring out whether their projects go forward,” he said. “I think the ISO’s price point is only one aspect of that, if that. That’s why I think the whole philosophy that you’re building the example on is inaccurate.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
Robert Stoddard, who made the case for assuming a surplus on behalf of NEPGA at the MC’s July meeting, said Cooke’s conclusion depends on the slope of the E&AS price curve being steeper than the slope of the MRI.
“My guess is you could construct a different set of examples by using a steeper MRI value and find that this problem does not occur,” he said. He elaborated on his point in a presentation later in the meeting.
Kruse said after the meeting that generators are hurt by the RTO’s use of inconsistent planning parameters. “One of my concerns is not just the ‘at criterion’ argument here but the fact that they use different metrics; they factor in the oversupply as well as the upcoming state-mandated [resources] when setting the DDBT threshold. … We lose on both sides of the equation.”
Votes by the MC on the DDBT threshold and updated FCM parameters are expected in October with the PC voting in November.
MISO is not giving itself time to celebrate after FERC recently accepted its transmission cost allocation plan, promising more such work on long-term and interregional projects.
“We made it. We got across the finish line. After about three years of stakeholder discussion and a year and a half of FERC rejections, we did it,” MISO Senior Manager of System Planning Jarred Miland joked during the Regional Expansion Criteria and Benefits Working Group’s (RECBWG) teleconference Thursday.
MISO’s plan lowered the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV and eliminated the 20% postage-stamp allocation in favor of allocating full costs to benefiting transmission pricing zones. It also added two new benefit metrics based on whether a project can reduce dependency on the RTO’s transmission contract path with SPP or eliminate needs for other reliability projects. FERC approved the plan in late July. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)
But the RECBWG’s work on transmission project cost allocation is far from over.
“I feel like it was time to take a nap, but then [Vice President of System Planning Jennifer Curran] kicked off expanded long-range transmission planning yesterday,” Miland said, referring to Curran’s announcement Wednesday to the Planning Advisory Committee that MISO will explore long-range transmission solutions — and may have some project recommendations as soon as next year.
The working group will likely forge new cost-allocation methodologies for any long-range transmission projects that may result. Several stakeholders asked when and how the group would approach the effort.
“We have to figure out what we’re talking about first,” Miland said in asking for patience. Long-range transmission discussions are continuing in MISO’s planning committees, and Miland said the RECBWG must wait to see what projects develop before it devises cost-sharing methods.
“It’s not baked yet; it’s not ready for primetime,” he said.
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Miland also said the grid operator is now considering another filing to lower the voltage threshold on interregional MEPs with PJM from 345 kV to 230 kV.
That seemed to confuse stakeholders, who said the interregional project allocation voltage threshold was already lowered to 100 kV after a 2013 complaint at FERC by Northern Indiana Public Service Co. against the MISO-PJM interregional planning process.
Miland clarified that currently, the RTOs’ interregional economic projects between 100 and 345 kV are allocated to benefiting transmission zones based entirely on the original adjusted production cost metric. MISO is proposing to additionally use the two new benefits metrics to evaluate 230-kV+ MISO-PJM interregional projects.
“I think it would be a pretty simple filing to do,” Miland said. MISO’s rationale is that it would align both the RTO’s regional and interregional project evaluations, he said.
But Clean Grid Alliance’s Natalie McIntire argued that because FERC ordered a 100-kV threshold on MISO-PJM interregional projects, the RTO should also apply that to any benefit metrics.
Some stakeholders asked if MISO would also consider a filing applying the two new benefit metrics to economic projects with SPP.
“Frankly, we have not had any conversations around that,” Miland said.
