As NERC’s leadership sees “light at the end of the tunnel” of the COVID-19 pandemic, CEO Jim Robb is considering a partially online format for future meetings of the organization’s Board of Trustees inspired by the successful shift to remote work in 2020.
Under a framework proposed by Robb during Wednesday’s meeting of the Member Representatives Committee (MRC), the full board would meet in person every quarter, as it did until last spring when many participants were no longer able to attend because of pandemic-related travel restrictions.
NERC CEO Jim Robb | NERC
The February and August meetings would be open to stakeholders and accompanied by an in-person meeting of the MRC, while the May and November meetings would be open to in-person attendance by board members only. Stakeholders could still listen in via web conference, and the MRC would hold its quarterly meeting virtually, a format that Chair Roy Thilly said the organization was considering at the board’s online meeting last May. (See “COVID-19 Prompts Further Meeting Changes,” NERC Board of Trustees/MRC Briefs: May 14, 2020.)
Robb presented this new “rhythm” of stakeholder engagement as a way to reduce the cost of in-person meetings, which he said the organization estimated to be about $1 million when travel costs for all participants are factored in. But the proposal is also meant to extend the benefits that NERC has seen through the unexpected experiment in remote operations.
“[Over] the last nine months, through this format … we’ve been able, in general, to attract more participants to our meetings, and different participants than we’ve seen before have been able to speak,” Robb said, because of the fact that “now you don’t have to get on a plane” to participate in a meeting.
The limitation of in-person meetings allows other changes as well, Robb noted. With only two mass gatherings a year, each one becomes a more special event. For example, under the proposal outlined by Robb, the February meeting would function as an annual meeting “with a celebratory dinner and acknowledgement of outgoing/incoming trustees and stakeholder leaders.” The August meeting would still be held in Canada and would help with outreach to Canadian stakeholders.
NERC is also discussing with the heads of major stakeholder committees the possibility of similarly replacing some in-person gatherings with remote meetings. This could also help the organization reduce the meeting space requirements for its offices in Atlanta and D.C., though Robb said NERC has no plans for such reductions in the near future.
Responses Council Prudence, Boldness
Participants in the conference call were generally supportive of rethinking the meeting schedule. MRC Chair Jennifer Sterling, of Exelon, noted that the board has previously considered moving from four to three meetings a year, so Robb’s proposal is not unprecedented. (See “Board Seeking Cut to Three Meetings per Year,” NERC MRC Briefs: Nov. 5, 2019.)
Kenneth DeFontes, NERC | NERC
Some cautioned against taking the virtual meeting approach too far, however. Board Vice Chair Kenneth DeFontes suggested that NERC’s success with remote operation was because of the existing relationships built over years between current members. He wondered if newcomers would have the same opportunities to build trust with their colleagues with a reduced amount of in-person meetings.
Bill Gallagher of the Vermont Public Power Supply Authority noted that while the proposed schedule would allow four in-person board meetings per year, the MRC would be limited to two.
If “we’re only meeting twice a year, and the rest of it is virtual, carrying out our own responsibilities may be compromised,” Gallagher said. “I don’t think that’s something we ought to do. The MRC has responsibilities that are distinct from the board, but no less important.”
Sylvain Clermont, Hydro-Québec | NERC
Sylvain Clermont, director of operational technologies convergence at Hydro-Québec TransÉnergie, said that leadership should consider a bolder approach to incorporating technology rather than trying “to replicate the way we were doing business” before. He reminded participants that they have all grown familiar with online collaboration and video conferencing tools and suggested that NERC could explore how those products’ features could be used to enable greater productivity.
“I know that there’s probably technological challenges in that, but I would like us to think broader than just trying to replicate the formula with, in part, some virtual settings,” Clermont said. “I would like to see how we could make engagement … a frequent and dynamic and continuous process, so that ideas could be shared dynamically more often, and discussions happen more frequently.”
Robb emphasized that the schedule discussed Wednesday is a strawman intended to inspire discussion. NERC leadership will work on a proposal incorporating stakeholders’ suggestions ahead of the upcoming board and MRC conference calls in February.
FERC last week approved penalties totaling $344,000 against three utilities as part of settlements between them and WECC for violations of NERC reliability standards, along with a $192,000 penalty assessed by the Texas Reliability Entity against Oncor Electric Delivery.
The commission also approved settlements between ReliabilityFirst and the Twin Ridges Wind Farm in Pennsylvania , and between an unnamed utility and registered entity for a violation of NERC’s Critical Infrastructure Protection (CIP) standards (NP21-3). The CIP violation is being kept confidential in accordance with FERC and NERC’s new policy on the treatment of such information announced last September. (See FERC, NERC to End CIP Violation Disclosures.)
NERC submitted the settlements to the commission Nov. 30, filing separate Notices of Penalty for the settlement between WECC and Southern California Edison (NP21-4) and the unnamed entity, and a spreadsheet NOP that included Twin Ridges, Oncor and the other WECC utilities (NP21-2). FERC indicated last Wednesday that it would not review the NOPs, leaving the settlements intact.
Tree Inspection Leads to SCE Penalty
SCE’s $296,000 settlement with WECC involves two violations of FAC-003-3 (Transmission vegetation management), both involving the same transmission right of way in the Sierra National Forest. The first incident, involving requirement R2 of the standard (requiring transmission and generator owners to prevent interference with their lines by vegetation) was self-reported. WECC discovered another violation of requirement R6 (requiring 100% of transmission lines to be inspected for vegetation encroachment at least once a year) in a compliance audit.
In the first case, a third-party contractor for SCE performing a routine pre-inspection for vegetation management in August 2017 observed that a tree might be encroaching on the minimum vegetation clearance distance (MVCD) of a 220-kV transmission line originating in the utility’s Rector Substation. However, because of heavy brush growth on the line’s right of way the inspector could not get close enough for an accurate measurement.
SCE technicians later went out to inspect the line in a helicopter but were again unable to get a good view. It was only after ground crews managed to clear a path to the line that SCE could confirm that the tree was indeed within the MCVD. The utility sent a crew to remove the tree the day after the issue was first identified.
The dense brush in Sierra National Forest prevented SCE technicians from examining lines for vegetation encroachment
WECC attributed the root cause of the violation to SCE’s “misinterpretation of the expectation for a vegetation inspection” and failure to perform a systematic examination of vegetation conditions for the area, resulting in fast-growing plants obscuring the view of the tree in the MCVD. The regional entity determined that the violation posed a moderate risk to reliability of the bulk power system.
In addition to removing the tree, SCE took a number of other steps to mitigate the issue. These included performing emergency field inspections on transmission circuits in the same area to detect potential MVCD encroachments — of which none were found — developing a process for reporting inaccessible areas, improving training for pre-inspection and line-clearing work, and updating its right-of-way maintenance and vegetation plan.
WECC found the violation of requirement R6 during an October 2018 audit, in which the RE examined SCE’s records of vegetation inspections of the line in the prior MVCD incident. While SCE had completed aerial vegetation inspections of the relevant areas in 2015 and 2016, WECC could not find evidence that inspectors had taken sag and sway of the transmission line into account and, thus, could not verify that the inspection was complete. The same was true of SCE’s ground inspections, the RE found.
SCE’s mitigation measures for this violation included contracting for a light detection and ranging survey of most of the 220-kV lines in the area to ensure it detected all vegetation issues and updating its transmission vegetation management plan to account for sag and sway.
SMUD, SPS Face WECC Criticism
WECC’s other settlements were with the Sacramento Municipal Utility District (SMUD), for $26,000, and sPower Services (SPS), an independent power producer headquartered in Utah, for $22,000.
The SMUD settlement arose from violations of FAC-008-3 (Facility ratings), discovered by WECC during a September 2019 compliance audit. The RE determined that SMUD had incorrectly applied the standard’s requirements both as a generator owner and a transmission owner.
On the generation side, the facility ratings methodology that SMUD used for eight of its generation facilities did not state that “the demarcation for generation facilities must extend from the high-side terminals of the main step-up transformers to the point of interconnection with the TO,” in this case SMUD itself. This oversight could have resulted in the utility’s facility ratings being incorrectly calculated, though auditors reported that the generator facilities in question were rated appropriately.
As a TO, SMUD did not “explicitly describe which of its transmission facilities were jointly owned.” As a result, according to WECC, the utility could not clearly describe how it rated these 12 facilities with their joint owners, though the RE noted that SMUD “provided evidence that all components that make up its jointly owned transmission facilities were rated appropriately” and that the utility did coordinate with neighboring entities in some form.
Both violations posed a moderate risk to the BPS, WECC determined, noting that because it found no issues with the affected equipment, SMUD’s infringement appeared to be limited to failing to document its procedures. In response the utility revised its ratings methodology for both generators and jointly owned transmission facilities, in addition to updating its definition of jointly owned facilities. It also added a requirement to annually request updates from neighboring entities on any facilities that they might share with SMUD and ensure their ratings are verified.
The SPS settlement applied to four separate violations of VAR-002-4.1 and its predecessor VAR-002-4, both of which govern generator operation for maintaining network voltage schedules; the violation of VAR-002-4 occurred before the current standard was adopted in September 2017.
SPS self-reported all of the violations, starting with an incident on March 10, 2017, and continuing with reports in March 2018, September 2018 and November 2019. All reports were for the same issue: failing to notify the transmission operator of a status change on the automatic voltage regulation (AVR) in one of its wind or solar facilities within 30 minutes of the change, as required by the standard.
The violations had various causes, WECC concluded. In one case the RE attributed the infringement to “an unreliable communications path from the generating unit to the control room,” while another was from the generating unit’s supervisory control and data acquisition controller “not being properly commissioned by [its] vendor.” All violations concluded within one hour except for one, which lasted for about 18 hours.
WECC determined that all of the violations posed a minimal risk to the BPS. Mitigation measures by SPS included updating its systems to ensure that AVR status changes are properly communicated, implementing software to ensure involuntary changes are detected, and replacing faulty equipment.
Oncor also Cited for Ratings Issues
The Texas RE-Oncor settlement also stems from violations of FAC-008-3, discovered in an audit in November 2017. The RE reported that 22 Oncor transmission facilities had ratings that were inconsistent with its reported ratings methodology. Oncor was also cited with a separate violation for vailing to “provide accurate and timely facility ratings data to its associated reliability coordinator, ERCOT.”
Texas RE attributed both violations to failure of internal controls at Oncor. In the first case, the utility’s ratings methodology was said to “[lack] sufficient processes to track and timely reflect equipment ratings changes.” For the second infringement, the RE noted that while Oncor had a procedure to preform weekly comparisons between its facility ratings and the corresponding ratings in ERCOT’s network operations model, the utility did not adequately ensure that its rating changes were submitted in a timely fashion to address identified discrepancies.
Both violations were found to pose a moderate risk by Texas RE, though it noted that Oncor has a history of compliance issues with reliability standard IRO-010-1a (Reliability coordinator data specification and collection), which has since been replaced by IRO-010-2. In that case the utility was determined to have failed to provide ERCOT with accurate rating data for 10 of its facilities over a period of more than four years. Texas RE considered this an aggravating factor in determining the penalty amount.
To mitigate the infringement, Oncor corrected the incorrect facility ratings and implemented a new project tracking and communication application to consolidate the previously separate systems that it used for initiating and executing transmission projects. It also revised its rating discrepancy review and commissioning process to ensure that discrepancies are tracked, reviewed and resolved quickly, and that “assets are energized in the field only after a proper ERCOT model topology and rating review.”
RF Scolds Twin Ridges for Missing Documents
RF’s settlement with Twin Ridges originated from a spot-check conducted July 8-19, 2019, during which it found the facility to be in violation of PRC-019-2 (Coordination of generating unit or plant capabilities, voltage regulating controls, and protection).
Twin Ridges Wind Farm | Sargent Electric
During the spot-check, RF could not verify that Twin Ridges had properly coordinated its generating facilities because of the absence of “dated documents that would demonstrate that the facility coordinated the voltage-regulating system controls … with the applicable equipment capabilities and settings of the applicable protection system devices and functions.” The RE determined that neither the current owner of Twin Ridges nor its previous owner — neither of which was named in the filing — were aware that the entity was not compliant with the standard.
Once RF discovered the noncompliance, Twin Ridges contracted with an outside engineering firm to perform a coordination study and determine whether it needed to change any of its procedures, with the firm reporting that none were required. It also engaged in a separate review of its compliance program to verify this assessment, which also confirmed that no further mitigating activities would be necessary.
Although the violation had a long duration — beginning in July 2016 when the standard took effect and ending in February 2020 when mitigating activities concluded — RF determined that the risk posed was moderate. This is particularly evident in the fact that no changes were required when the coordination was finally performed. As a result, no monetary penalty was assessed.
Massachusetts lawmakers passed a sweeping climate bill Monday that would provide the state another path to reach net-zero carbon emissions by 2050.
The bill, which passed both the state House and Senate, still requires sign-off by Republican Gov. Charlie Baker, who recently released his own legally binding plan to achieve net-zero emissions in the same time frame.
It also comes just weeks after the state joined Connecticut, Rhode Island and D.C. in launching the Transportation and Climate Initiative Program (TCI-P), which aims to cut greenhouse gases from vehicles by 26% over the next decade and invest in cleaner transportation choices and public health improvements. (See NE States, DC Sign MOU to Cut Transportation Pollution.)
The new law will require Massachusetts to reduce emissions to 50% below 1990 levels by 2030, 75% by 2040 and 85% by 2050.
Emissions targets must be reviewed every five years to ensure the state is making sufficient progress. The bill additionally establishes mandatory emissions limits for electricity, transportation, commercial and residential heating and cooling, industrial processes, and natural gas distribution and service.
Dan Dolan, president of the New England Power Generators Association, said the climate bill and Baker’s plan “dovetail largely together.” Both efforts show that states are starting to do “more than pay lip service” to electrification on an economy-wide basis, he said.
The bill also calls for utilities to procure an additional 2,400 MW of offshore wind power, raising the state’s total to 5,600 MW.
| Vineyard Wind
Francis Pullaro, executive director for RENEW Northeast, said his organization’s members are not just renewable energy developers; “they’re environmental advocates and I think, generally speaking, they’re extremely pleased with this bill.”
“It’s an attention-getter for the offshore wind sector,” Pullaro said. “With the climate ambitions that Massachusetts has, it’s going to need offshore wind; it’s going to need small solar and it’s going to continue to need to take advantage of the land-based wind and larger solar potential in the region, as well as the transmission to get some of these renewables, including offshore wind, from remote areas to the load centers.”
Dolan expressed disappointment that the bill contains an OSW procurement — but “not because offshore wind is a bad resource.” Instead, he wants to see how the first set of offshore projects perform and allow the region “to then make some of the market changes necessary to be able to finance the next wave of new energy through the market, rather than continued reliance on the long-term contracts.”
“That’s probably the single biggest element that was of concern to us in the legislation itself,” Dolan said.
‘No Way Around It’
Tamara Small, CEO of NAIOP Massachusetts, which represents commercial real estate developers, said her organization is troubled by a bill provision that allows for the development and adoption of “opt-in” building codes for municipalities that could require buildings to have net-zero emissions. Small said the bill’s language is “unclear” about which cities and towns would opt-in and when they would do it. She added that the bill “does not define what net-zero means, and interestingly net-zero is a term that means very different things to very different people.”
“We don’t know what building types will be affected, whether it be all types of real estate or segments,” Small said. “We don’t know if the technology even exists to get to the goals that may be included in this undefined term. We know that certain properties have really struggled to get to net-zero, particularly large office buildings and lab buildings. Right now, we have a global health pandemic that has resulted in a significant impact on the entire commercial real estate industry and the greater economy.”
Small said NAIOP is “very concerned” the bill creates uncertainty for the building permit process and the cost of construction, “so we are very much opposed to the language in the bill right now.”
To be clear, she said, NAIOP recognizes the effects of climate change, and its 1,700 members are “supportive of net-zero within a timeline that makes sense,” but “one year is not that timeline.”
“We have regulations getting ahead of technology, in addition to the fact that it’s just so unclear what’s going to be required in the industry right now,” Small said. “I think for real estate developers, and the greater real estate industry, predictability and certainty are critical, and this [bill] does not provide that.”
Jacob Stern, deputy director for the Massachusetts chapter of the Sierra Club, likened the builders’ reaction to reaching net-zero emissions to the past attitude of automakers toward manufacturing electric vehicles.
“I kind of see it as something a little similar,” Stern said. “We know that we cannot continue to do gas infrastructure. … It’s going to affect the building sector. It’s a situation where we’re either going to have to start rethinking about how we construct buildings and how we put a gas infrastructure in buildings, or we’re not going to be able to effectively fight climate change. It’s just a part of the puzzle. There’s no way around it.”
MISO again explained its lack of insight into the system’s distributed energy resource numbers while stakeholders asked for simpler interconnection studies during the inaugural meeting of the Distributed Energy Resources Task Force (DERTF).
The task force will meet monthly, ultimately furnishing recommendations to the Market Subcommittee on how to best approach FERC’s Order 2222, which allows DER aggregators to compete in organized wholesale electric markets.
Minnesota Public Utilities Commission Planning Director Tricia DeBleeckere and Xcel Energy’s Diane Watkins were selected as the group’s chair and vice-chair, respectively.
Timothy Caister, MISO’s DER program lead, said during the meeting that staff is considering asking FERC for an extension of Order 2222’s July 19 compliance deadline. He said MISO hasn’t settled on how much more time to request. (See Members Counsel MISO on Order 2222 Prep.)
Laura Rauch, the RTO’s director of settlements, said the goal is to “allow near-term DER integration with minimal system impacts.” She said staff will examine existing ways DER aggregators can participate in the markets through its predefined dispatchable intermittent resource, demand-response resource and energy storage resource categories. MISO will then perform analyses to pinpoint long-term system needs to facilitate DER participation.
Rauch asked stakeholders for written opinions on the action plan through Jan. 18.
“We’re still struggling at MISO, as I expect others are, to quantify DER growth in the MISO region. That’s something we’re going to focus on,” DER Program Director Kristin Swenson said. “Projecting how much DER is going to be in the footprint is a perennial question, [and] we’re working on it. … MISO has no real visibility into the distribution system.”
Swenson noted that the grid operator relies on load-modifying resource registrations, its member utilities’ integrated resource plans and the Organization of MISO State’s annual DER survey estimates for an initial understanding of the resources’ penetration. However, she said the data remains too spotty and inconsistent to accurately model and appropriately plan “as the generation fleet goes onto rooftops.” She also said DER visibility is key to MISO’s reliable operations.
The RTO could employ an affected system study to gauge how distribution interconnections will impact the transmission system, Swenson said. The mention of “affected system studies” struck a nerve with some stakeholders.
“As soon as you use the word ‘affected system study,’ you can expect people are about to faint,” Madison Gas and Electric’s Megan Wisersky said, alluding to MISO’s and MISO West Risks Becoming ‘Dead Zone,’ Stakeholders Warn.)
Wisersky urged that any MISO-designed DER impact studies “not be unduly restrictive, bureaucratic and always behind schedule.”
MISO’s managing assistant general counsel, Michael Kessler, said Order 2222 dictates coordination among distribution utilities, relevant electric retail regulatory authorities and grid operators to assess grid impacts.
“The commission has said those studies should not become barriers or impediments,” he said.
FERC last week ordered revisions to NERC’s pro forma regional delegation agreement (RDA) and its RDAs with all regional entities while approving the agreements overall (RR20-5). The new RDAs took effect Jan. 1.
NERC filed the agreements with FERC in June after the Board of Trustees approved the pro forma RDA, which serves as a template for the organization’s bilateral RDAs with specific REs, at its meeting in May. (See “Other Approvals,” NERC Board of Trustees/MRC Briefs: May 14, 2020.) The REs’ boards approved their own RDAs prior to NERC’s submission as well, with Texas Reliability Entity giving its assent on May 27 and the Midwest Reliability Organization, ReliabilityFirst, SERC and WECC following in June.
Changes in the pro forma RDA include:
removing outdated language in light of the dissolutions of the SPP RE and Florida Reliability Coordinating Council;
prohibiting stakeholders from leading RE board compliance committees;
clarifying requirements regarding the nomination of independent board members;
allowing REs greater flexibility regarding the use of funds collected through penalties; and
clarifying that delegation agreements may be terminated earlier than the end of the five-year term with one year of written notice.
Updates to the bilateral RDAs include specifying that each RE is “governed by a hybrid board” comprising both stakeholder representatives and independent board members, and that all REs have adopted the “consolidated hearing process” described in NERC’s Rules of Procedure (ROP). The exception to this is Texas RE, which will continue to use its own hearing process as permitted in the ROP.
NERC and the REs made additional minor changes to the RDAs, such as updating the funding sections of the Texas RE and WECC agreements. In the case of Texas RE the RDA was revised to “reflect current accounting, time record and expense management for statutory and non-statutory activities.” Revisions to the WECC agreement update the scope of its “statutory situation awareness activities” to remove registered entity-related functions.
In addition, NERC and the REs updated the bilateral agreements to eliminate maps of entity boundaries in favor of textual descriptions, which NERC feels will allow more precision in assigning registered entities to specific REs. This change also involves updates to language in the pro forma RDA “to replace the term ‘identified’ with the term ‘described’ when referencing the geographic boundaries.”
FERC Notes Inconsistent Language
In its filing, FERC agreed that using text to describe RE boundaries is “more accurate and precise,” and approved of the language changes. However, the commission criticized the revised RDAs for inconsistently applying this change, noting that both the pro forma and every bilateral RDA still contain instances where “identified” is used instead of “described.”
Effective Jan. 1 this map defining RE boundaries found in previous versions of NERC’s RDAs was replaced with textual descriptions defining each RE’s territory. | NERC
FERC also observed that despite NERC’s assertion that WECC adopted the consolidated hearing process along with other REs, WECC’s actual RDA does not specifically state this, which could cause confusion among registered entities as to which hearing process is to be used. The agreement also does not say that WECC “may modify its selection of hearing process by giving NERC six months prior notice” as required by the ROP.
The commission ordered NERC to modify the pro forma RDA and the bilateral RDAs to ensure the language regarding boundaries is consistent across all documents. NERC was also directed to modify WECC’s RDA to specify that it will use the consolidated hearing process.
FERC did not order WECC’s RDA to be modified to require giving NERC six months’ notice when it changes its hearing process. However, the commission did note that “it is our expectation that, if a [RE] modifies its selection of a hearing process, NERC will amend the delegation agreements and file such amendments with the commission.”
A compliance filing with the ordered changes to the pro forma and bilateral RDAs is required within 120 days of the commission’s order, which is dated Dec. 30.
A few days later, the New England States Committee on Electricity (NESCOE) released “New England States’ Vision for a Clean, Affordable and Reliable 21st Century Regional Electric Grid.” The report urged ISO-NE to convene a “collaborative process” with states and other stakeholders in 2021 to consider changes to its mission statement and governance structure “to achieve greater transparency around decision-making, a needed focus on consumer cost concerns and support for states’ energy and environmental laws.” (See States Demand ‘Central Role’ in ISO-NE Market Design.)
New England states are looking to change the region’s energy industry structure, which has numerous entities. | ISO-NE
The statement made repeated references to the RTO’s “lack of transparency,” which “undermines public confidence” in the organization. Neither ISO-NE Board of Directors meetings nor NEPOOL stakeholder meetings are open to the public.
It also criticized the makeup of ISO-NE’s Joint Nominating Committee, which selects board members. The committee comprises seven incumbent board members, six market participants — one from each of NEPOOL’s sectors — and only one shared vote for the six New England states.
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said in September that improving ISO-NE’s transparency and accountability is “core to the design and implementation of our wholesale markets” and a “necessary and essential step” to achieve affordable decarbonization that relies on competition and minimizes risk to ratepayers. She added that states currently do not have adequate input and visibility into the RTO’s governance structure. (See Mass., Conn. Seek Federal Partner on Decarbonization.)
ISO-NE CEO Gordon van Welie | NECBC
In November, ISO-NE CEO Gordon van Welie shared the RTO’s vision statement with NEPOOL: “to harness the power of competition and advanced technologies to reliably plan and operate the grid as the region transitions to clean energy.” (See “ISO-NE Shares ‘Vision for the Future,’” NEPOOL Participants Committee Briefs: Nov. 5, 2020.)
The events set up an interesting end to 2020 and foreshadowed what is ahead in 2021.
“Understanding there are resource constraints on people and organizations, we really cannot afford to just go along and hope that we will land with the right market design and the right transmission pieces that need to be built,” said Judy Chang, undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs. “I think that’s the ultimate vision … to really work collaboratively so that we can achieve this future in the least amount of disruption and at the lowest cost.” (See NE Energy Leaders Discuss Paths to Decarbonization.)
Carbon Pricing
Carbon pricing was another hot topic in 2020. There was fervent opposition from state officials like Dykes, who said she opposed ISO-NE’s proposal to add a carbon price on top of the Regional Greenhouse Gas Initiative (RGGI), which sets the cap for carbon emissions across New England and other Eastern states. (See Dykes Calls out ISO-NE, FERC on Carbon Pricing.)
“Our states in New England, participating in RGGI as we do, have sent multiple letters to ISO New England and to NEPOOL regarding carbon pricing,” Dykes said in September. “And essentially, repeatedly, we’ve had to go on record stating that we are not in support of a carbon adder as a supplement or perhaps as a replacement for the RGGI program.”
However, Sen. Sheldon Whitehouse (D-R.I.) said in November that “carbon pricing is a pretty essential component of any rational analysis in the energy sector,” and there is an “imbalance” in the form of a massive subsidy for fossil fuels. (See Overheard at New England Energy Summit.)
Whitehouse said a carbon price is “far from dead” in Congress. It is the “leading strategy” on the Republican side, and there are four separate Democratic carbon pricing bills, “so this is not some fringe idea.”
FERC Commissioner Neil Chatterjee said in November, after he was demoted by President Trump in part for supporting carbon pricing in RTOs and ISOs, that state policies have negatively affected the competitiveness and function of the markets, which required “tough, but in my view, necessary decisions” at the commission. (See Officials Discuss Future of ISO-NE During Summit.)
“It all boils down to this: Carbon pricing is a fuel-neutral, transparent and market-based approach that can be harmonized with the markets we oversee,” Chatterjee said. “This stands in stark contrast to policy tools like subsidies, which can amount to hidden costs that can degrade market efficiency and skew price signals, ultimately hurting the consumer.” (See FERC: Send Us Your Carbon Pricing Plans.)
In December, Connecticut, Massachusetts, Rhode Island and D.C. signed a memorandum of understanding to launch the Transportation and Climate Initiative Program (TCI-P), which aims to cut greenhouse gas emissions from vehicles by 26% from 2022 to 2032.
A cap-and-invest program, TCI-P would require large gasoline and diesel fuel suppliers to purchase allowances for emissions and later auction them, which officials said will generate $300 million for yearly investments in less polluting transportation. Each year, the total number of emission allowances would decline. (See NE States, DC Sign MOU to Cut Transportation Pollution.)
FERC Updates
FERC in October rejected ISO-NE’s proposed Energy Security Improvements (ESI) market design because it said the proposal would add substantial costs to consumers “without meaningfully improving fuel security” (ER20-1567).
ESI would have allowed the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter when natural gas shortages can leave generators without fuel. Option awards would have been co-optimized with all energy supply offers and demand bids in the day-ahead market. FERC also rejected an alternative proposed by NEPOOL that would have lowered costs to ratepayers, saying it contained the same deficiencies. (See FERC Rejects ESI Proposal from ISO-NE.)
The result of more than a year of stakeholder meetings, the ESI proposal was prompted by FERC’s July 2018 finding that ISO-NE’s tariff lacks a way to address fuel security concerns that the RTO said could result in reliability violations as soon as 2022. The tariff currently only allows cost-of-service agreements to respond to local transmission security issues.
Following the rejection, ISO-NE asked FERC whether it could seek its direction on how to improve fuel security following the ruling. ISO-NE said the region “is at a crossroads with … energy security and its reserve markets. The ISO does not believe that it is prudent to move forward without the opportunity to speak freely with the commission and its staff. Accordingly, we are stalled.” (See ISO-NE to FERC on Fuel Security: What Now?)
Also in November, FERC defended its Competitive Auctions with Sponsored Policy Resources (CASPR) order, which permitted ISO-NE to create a two-stage capacity auction to accommodate state renewable energy procurements (ER18-619). The commission said it continued “to find the economic principles underlying CASPR to be sound” and agreed with the RTO’s recommendation to prioritize the preservation of a competitive Forward Capacity Auction price to ensure investor confidence. (See FERC Defends CASPR Order.)
Democratic Commissioner Richard Glick dissented, saying he does not believe CASPR “is a just and reasonable means of accommodating state public policies” in the Forward Capacity Market. He said concerns about “consequences that resource entry and exit decisions have for climate change, among other things, are likely to play a more important role in resource entry and exit than the FCM clearing price,” especially in New England.
Speaking of FCM, FERC ordered ISO-NE to remove its new-entrant rules from its tariff in December, preventing resources from being allowed to lock in their prices for seven years (EL20-54). The rules had been in effect since ISO-NE began its capacity market in 2006.
The commission said the rules resulted in “unreasonable price distortion” and that locked-in prices are “no longer required to attract new entry, with the benefits provided by price certainty no longer outweighing their price-suppressive effects.” Price-lock agreements in effect before the order will not be impacted, with the new rules starting with FCA 16, scheduled for February 2022. (See FERC Orders End to ISO-NE Capacity Price Locks.)
Renewable Energy
Solar developers were the clear winners in the Maine Public Utilities Commission’s renewable energy procurement in September, accounting for 482 of the 546 MW in approved projects through a competitive bidding process. It was the PUC’s largest procurement of renewable energy since restructuring more than 20 years ago. (See Maine Makes Record Renewable Procurement.)
Winning bidders estimated the projects would reduce greenhouse gas emissions by approximately 500,000 tons per year. The projects were the first approved since Mills, a Democrat, signed a bill last year to increase the state’s renewable portfolio standard to 80% by 2030 and set a goal of 100% renewable energy by 2050.
Later in October, Rhode Island Gov. Gina Raimondo (D) announced a new competitive solicitation to procure up to 600 MW of offshore wind energy. (See R.I. Opens Solicitation for 600 MW of Offshore Wind.) Raimondo had signed an executive order in January committing her state to use renewables to meet 100% of its electricity demand by 2030.
The state’s target for OSW energy is 1,030 MW, with 430 MW currently selected. The potential addition of 600 MW would meet the target.
During a speech in December, U.S. Sen. Ed Markey (D-Mass.) said New England states have the chance to be “the true leaders of the Green New Deal” that he co-sponsored with Rep. Alexandria Ocasio-Cortez (D-N.Y.) — or some variation of it.
Markey said achieving the Green New Deal’s objectives of a 100% clean energy economy and carbon-free power sector by 2035 will require billions of dollars for battery storage and promoting electric vehicle adoption through the construction of at least 500,000 new charging stations. (See “Markey: Climate Issues Top Agenda,” Overheard at NE Electricity Restructuring Roundtable.)
“This is not pie in the sky, put a man-on-the-moon stuff; these are largely technologies that already exist,” Markey said. “It’s been a political problem but not a technological problem. … We know we can get this done. It is just a matter of political will. I will be working very hard to make sure that these hundreds of billions of dollars are spent in a way in which we have public-private partnerships jumpstarting clean energy innovation and deployment.”
2020 was a year that strained the very idea of society and tested the United States’ democratic institutions. It began with the acquittal of the president on impeachment charges and ended with his re-election defeat, seen by many as a referendum over his response to the novel coronavirus that has killed more than 350,000 people.
The COVID-19 pandemic underscored the value of the Internet even as it proved that people are still as dependent on face-to-face contact and social interaction as their ancestors 300,000 years ago.
The year also brought increasing evidence of climate change: The 2020 Atlantic hurricane season was the most active in recorded history, and the Western U.S. saw record-high dry weather that once again triggered dangerous wildfires and a heat wave that drove CAISO to enact rolling blackouts in California.
An Appetite to Address Climate Change?
Though Joe Biden won the presidential election, Democrats did not manage to flip the Senate as they had hoped, at least not yet. That will be determined as soon as tomorrow, when Georgia holds two runoff elections for its seats, currently held by Republicans. If Democrats win, there will be a 50-50 tie in the Senate, and Vice President Kamala Harris will hold the tie breaker.
President-elect Joe Biden in late November | Shutterstock
Democrats also lost seats in the House of Representatives, narrowing their majority. Thus, Democrats will lack the sort of margins that could enact Biden’s promises for sweeping climate change policies. (See GOP Senate May Limit Biden Climate Ambitions.)
In the final days of the year, the Democratic-controlled House and the Republican-controlled Senate passed the first comprehensive energy policy legislation since 2007 as part of an annual spending package. After hinting at a veto, President Trump signed the bill a week after it was passed. Among its many provisions the legislation included tax break extensions for wind, solar, energy efficiency and carbon capture; a requirement for the Interior Department to seek at least 25 GW of renewable projects on federal lands; and a phaseout of the use of hydrofluorocarbons in air conditioning and refrigeration. (See Wind, Solar, EE, CO2 Storage Win Tax Breaks.)
How much the bill will impact U.S. emissions is unclear. But the legislation will not result in the scale of decarbonization of transportation, industry and building infrastructure that experts say is necessary to avoid the worst impacts of climate change. (See Net Zero Price Tag: $2.5 Trillion.)
Another question that arose late last year is how the U.S. will rejoin the Paris Agreement on climate change after it formally withdrew just after Election Day. Biden has pledged that he would immediately begin that process after he is inaugurated, but the U.S. will need to update its emission-reductions targets from those sought by President Barack Obama in 2015. And though he has proposed spending on clean energy projects to combat climate change, Biden has not yet detailed regulations, like Obama’s Clean Power Plan, to achieve any targets under the agreement.
FERC Transition
With commissioners serving staggered five-year terms, the makeup of FERC is always in flux, and last year was no different for the agency.
Early on, Commissioner Bernard McNamee announced he would not seek another term after his current one expired June 30. While he said he would continue to serve until a replacement was confirmed, he resigned shortly after President Trump nominated his intended successor, Virginia State Corporation Commission Chair Mark Christie, in late July.
It took the Senate until Nov. 30 to confirm Christie, a Republican, and Allison Clements, a Democrat and former energy policy consultant. Clements was sworn in soon after being confirmed, and Christie was sworn in on Jan. 4, giving the Republicans a 3-2 edge. (See Senate Confirms Christie, Clements to FERC.)
Meanwhile, tension continued to grow between FERC and states, which complained that the commission’s capacity market rules were frustrating their efforts to integrate renewable resources.
But Chair Neil Chatterjee, a Kentucky native, continued his transformation from coal-state partisan by shepherding through Order 2222, which ordered RTOs and ISOs to open their markets to distributed energy resource aggregations. (See FERC Opens RTO Markets to DER Aggregation.) He also held a technical conference on integrating offshore wind and supported a policy statement inviting states to propose carbon pricing in the wholesale markets.
Chatterjee acknowledged that these actions likely led Trump to demote him and name Commissioner James Danly — who was confirmed in late March after serving as FERC’s general counsel — as chair. (See Trump Names Danly FERC Chair.)
Because of the COVID-19 pandemic, if Danly is replaced immediately after Inauguration Day he will be the only chair to have never presided over an in-person open meeting. The commission moved its January meeting to the day before Biden will become president, ensuring at least one more virtual session for Danly and the Republican majority. Biden will name either Clements or her Democratic colleague Richard Glick (the more likely candidate) as chair.
How long the Republicans will maintain their majority will depend on Danly. Chatterjee’s term ends June 30, though he can stay on after that until a replacement is confirmed or Congress adjourns for the year, and he has pledged repeatedly to serve out his term.
It is also possible that Danly could resign — as Republican Chair Joseph T. Kelliher did when Obama assumed the presidency in 2009 — allowing Biden to fill his seat with a Democrat. That would give the Democrats a 3-2 edge and could allow Biden to renominate Chatterjee.
If 2019 was a turbulent year for PJM as it dealt with fallout from the GreenHat Energy default and the emergence of the minimum offer price rule (MOPR) issue, 2020 proved an even bigger challenge with a worldwide pandemic.
COVID-19 was the defining problem of the year as PJM worked with stakeholders to overcome logistical difficulties in coordinating complicated deliberations on a host of issues, including the MOPR. The year also saw the unfolding of political scandals involving some of the RTO’s largest utilities and the increasing number of renewable energy resources coming online and the new obstacles they provide for grid planning.
Here’s a review of some of the biggest PJM stories of 2020 and a peek at what stakeholders will be looking at in 2021.
MOPR Takes Shape
Last January, a wide range of stakeholders began asking FERC to reconsider its Dec. 19 order requiring PJM to overhaul its capacity market, saying the commission’s directive was unnecessary and overstepped federal jurisdiction. FERC said PJM had to expand its MOPR to counter the impact of growing state subsidies, primarily for renewables and nuclear generation. (See FERC Extends MOPR to State Subsidies.)
But state regulators, utilities and load-serving entities argued that the order went too far in attempting to control generation choices and failed to prove state-subsidized resources suppress capacity market prices. (See Consumer Advocates Appeal MOPR Order to DC Circuit.)
| PJM
By the end of January, PJM officials had announced they would not run a capacity auction until FERC approved the RTO’s compliance filing implementing the MOPR expansion, all but confirming that the delayed 2019 auction would not occur in 2020. (See PJM: BRA Unlikely in 2020.)
PJM’s Independent Market Monitor released analysis in March concluding that expanding the MOPR would not impact clearing prices or auction revenues for the 2022/23 Base Residual Auction because it won’t significantly change the treatment of gas-fired resources and also allow categorical exemptions for existing self-supply, demand response, energy efficiency and storage resources. The analysis also cited the “competitiveness of unit specific offers for existing subsidized nuclear resources.” (See MOPR May Not be Death Knell for Renewables in PJM.)
As PJM continued refining its MOPR, several states began weighing the option of meeting resource needs outside the capacity market.
The New Jersey Board of Public Utilities (BPU) voted March 27 to investigate whether staying in the capacity market will impede Gov. Phil Murphy’s goals of 100% clean energy sources for the state by 2050 or increase consumer costs (Docket No. EO20030203). If the goals are not achievable, board members instructed their staff to examine alternatives to the market. (See N.J. Investigating Alternatives to PJM Capacity Market.)
Illinois and Maryland officials also started their own discussions on leaving the capacity market. MOPR’s extension to subsidized nuclear plants created problems for Illinois regulators, where nukes receive zero-emission credits (ZECs), while Maryland’s plans for offshore wind are also impacted. (See PJM’s MOPR Quandary: Should States Stay or Should they Go?)
The commission in April clarified that voluntary renewable energy credits and Regional Greenhouse Gas Initiative (RGGI) participation would not subject capacity resources to PJM’s expanded MOPR. FERC directed PJM to make a compliance filing within 45 days to set the default offer price floor for new energy efficiency resources at the net cost of new entry (CONE) and existing energy efficiency resources at the net avoidable cost rate. (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)
By October, FERC approved most of PJM’s MOPR compliance filing while reversing its position on state-directed default service auctions (EL16-49-003, et al.). The commission said it agreed with PJM and commenters to exclude “independently evaluated, non-discriminatory, fuel-neutral, competitive state-directed default service auctions from application of the expanded MOPR.”
The commission also rejected PJM’s proposed revisions to the market seller offer cap as beyond the scope of the compliance proceeding. (See FERC Acts on PJM MOPR Filing.)
| PJM
PJM then moved even closer to restarting its capacity auctions with FERC’s November approval of its new energy and ancillary services (E&AS) offset calculation (EL19-58-002). (See FERC Approves PJM Reserve Market Overhaul.)
The commission acknowledged the changes would increase the RTO’s reserve procurement and thus, the revenue resources received, affecting the capacity market’s E&AS offset. The offset is a key variable in calculating the net CONE for resources in the capacity market and is calculated using energy market results from the three calendar years prior to the BRA.
PJM’s revisions changed the offset to be forward-looking and included in its filing indicative E&AS and net CONE values for various resource types. These values are “based on the latest published and publicly available forward prices at that time,” FERC said, and would be revised using updated forward prices prior to the upcoming BRA for the 2022/23 delivery year. (See FERC Approves PJM Key Capacity Market Variable.)
PJM was finally able to announce that it will hold the 2022/23 BRA May 19-25 and will post results on June 2. (See PJM Sets BRA for May 2021.)
Political Scandals
Ill. House Speaker Michael Madigan
Last year also saw major figures in the Illinois and Ohio legislatures caught up in alleged bribery schemes involving two of PJM’s largest stakeholders over controversial laws passed to help save costly nuclear plants. The evolving scandals took down company leadership and leaves several people facing the possibility of stiff jail sentences.
Exelon’s Commonwealth Edison agreed last July to pay a $200 million fine to settle allegations that it bribed Illinois House Speaker Michael Madigan (D) in return for legislation that increased the company’s earnings and bailed out its money-losing nuclear plants. Madigan is the longest-serving leader of any state or federal legislature in U.S. history, having held the speaker title for all but two years since 1983. (See ComEd to Pay $200 Million in Bribery Scheme.)
The U.S. Attorney’s Office in Chicago filed a one-count information alleging that to influence legislation favorable to the company, ComEd arranged no-work jobs for Madigan associates, including former Chicago Alderman Michael R. Zalewski, the father-in-law of Illinois Commerce Commission (ICC) Chair Carrie Zalewski.
In 2011 ComEd sought to persuade Illinois lawmakers to allow it to make billions in smart grid investments and switch to a formula ratemaking process to enable it to recover costs more quickly, investigators said.
ComEd also admitted to appointing a Madigan ally to its board of directors, retaining a law firm favored by the speaker and providing internships to students who resided in the speaker’s Chicago ward.
In return for the alleged bribes, the company won Madigan’s support for the 2011 Energy Infrastructure Modernization Act, which approved the formula rate mechanism, and the 2016 Future Energy Jobs Act, which authorized subsidies for Exelon’s Clinton and Quad Cities nuclear generators. (See How ComEd Got its Way with Ill. Legislature.)
Within weeks of the bribery announcement, ComEd officials apologized to the ICC at an open meeting, while Zalewski defended herself against the conflict-of-interest allegations. (See ComEd on Hot Seat at ICC Hearing.)
Ohio Gov. Mike DeWine | Ohio Governor’s Office
Illinois electric customers went on to file a federal class action civil racketeering lawsuit in August against ComEd and Madigan, seeking more than $450 million in damages and an order barring the longtime politician from participating in any electricity legislation related to ComEd or its parent company, Exelon.
The plaintiffs’ attorney Stuart Chanen said ComEd’s agreement to pay the $200 million fine settling criminal allegations did not prohibit customers from pursuing additional damages under the Racketeer Influenced and Corrupt Organizations Act. (See ComEd, Madigan Sued for $450M in Racketeering Suit.)
Lobbyist Juan Cespedes | The Oxley Group
In November, several former ComEd executives, including former CEO Anne Pramaggiore, were indicted in connection to the ongoing bribery investigation. Investigators alleged the executives conspired with outside consultants to influence and reward a high-level elected official in Illinois to assist with the passage of legislation favorable to ComEd. (See Ex-ComEd CEO, Officials Charged in Ill. Bribery Scheme.)
Just days after the ComEd news broke, federal officials in Ohio alleged FirstEnergy spent $61 million in bribes and “dark money” campaign contributions to elect the speaker of the Ohio House of Representatives and allies, who won $1.5 billion in subsidies for the company’s struggling nuclear plants. (See Feds: FE Paid $61M in Bribes to Win Nuke Subsidy.)
Ohio House Speaker Larry Householder (R), FirstEnergy Solutions lobbyist Juan Cespedes, lobbyist Neil Clark, former state Republican Party Chair Matt Borges and political strategist Jeff Longstreth were arrested on racketeering charges in an alleged three-year scheme resulting in the passage of House Bill 6 in 2019, which authorized ZECs for FirstEnergy Solutions’ (FES) Perry and Davis-Besse nuclear plants.
Perry nuclear plant | Nuclear Regulatory Commission
FirstEnergy no longer owns the nuclear plants, as FES emerged from bankruptcy in February as Energy Harbor. But the utility’s then-CEO Charles Jones and others face legal jeopardy based on the 81-page affidavit that said Jones was in regular contact with Householder.
Former FirstEnergy CEO Charles Jones | First Energy
Ohio Gov. Mike DeWine (R) said in July the state should repeal House Bill 6 considering the federal bribery charges were against Householder and called for the politician’s resignation. DeWine had previously said that the law, which he signed last July, should remain intact to save the nuclear plants’ jobs and carbon-free power. (See Ohio Gov. Calls for Repeal of Nuke Bailout.)
Without any debate, House members voted unanimously to remove Householder as speaker after his arrest. Householder retained his seat in the house despite calls for his resignation. (See Householder Removed from Ohio Speaker Post.)
By October, FirstEnergy announced it had fired Jones and two other officials after an internal investigation determined they had violated the company’s code of conduct in the alleged bribery scheme.
Jones’ firing was announced after Cespedes and Longstreth pleaded guilty earlier that day to participating in a racketeering conspiracy. (See FirstEnergy Fires Jones over Bribe Probe.)
Ohio House Speaker Larry Householder | Ohio House of Representatives
In November, Public Utilities Commission of Ohio Chair Sam Randazzo resigned, less than a week after the FBI raided his Columbus home. Randazzo, who served as the chair of the PUCO since his appointment by DeWine in 2019, made the announcement in a letter sent to the governor.
The move came one day after FirstEnergy told the U.S. Securities and Exchange Commission that it made a $4 million payment to an “entity associated with an individual who subsequently was appointed to a full-time role as an Ohio government official directly involved in regulating [companies regarding] distribution rates.” (See PUCO Chair Randazzo Resigns.)
COVID-19 Impacts
As the U.S. was gearing up to shut down significant sectors of the economy in early March over the spread of COVID-19 from China, PJM was trying to determine how to keep its workers safe while still maintaining grid reliability.
The System Operations Subcommittee (SOS) began holding weekly conference calls in March to discuss how the coronavirus was impacting generation and transmission operators locally and the steps PJM and stakeholders were taking to handle the situation.
“I recognize that many of you are competitors in our markets … on a normal day-in-and-day-out basis,” PJM’s Paul McGlynn said about the meetings. “But our industry has a long tradition of working together to operate the grid reliably and … keep the lights on through some pretty challenging conditions.”
Within the first week of lockdown measures across the region, PJM officials reported seeing changes in energy use. The data from March 17-19 showed the normal 8 a.m. morning peak shifted to 9-10 a.m., and the evening peak was about 5% lower than expected, the RTO said.
On March 16, load came in at about 95,500 MW compared to an expectation of about 100,000 MW.
PJM implemented a work-from-home policy through April 10, except for system operators and other shift personnel, and employees began working longer shifts to minimize shift changes. The RTO also canceled its May 4-5 annual meeting in Chicago.
Crews began prepping the PJM campuses for sequestration in early April, with healthy workers required to remain on site if the pandemic became worse. Crews installed temporary bedding, entertainment, food and other accommodations for employees.
Analysts began working on worst-case scenarios in the early stages of the pandemic, with PJM engineers saying the RTO could support the loss of up to 40% of installed generation capacity on a summer day and up to 60% on a spring day in a worst-case scenario in which units were knocked offline from a COVID-19 outbreak among plant workers.
PJM officials presented the generator availability analysis to stakeholders, saying it was intended to determine the maximum generation loss PJM could handle without curtailing power to the hardest hit areas. The analysis began by considering the impact of an outbreak at one plant spreading and disabling a generating company’s entire fleet. (See PJM Analyzes Potential COVID-19 Generation Losses.)
According to a report issued in August by the Monitor, COVID-19 depressed PJM energy prices in the first half to the lowest levels of any comparable six-month period since the creation of the RTO’s markets in 1999.
The IMM 2020 State of the Market Report showed average energy prices fell over 29% from already historically low levels in 2019, to $19.40/MWh. Monitor Joe Bowring attributed the decrease to lower fuel costs, which accounted for more than half the decline. Also contributing was a significant decrease in demand because of mild winter temperatures throughout the region and the stay-at-home orders arising from the pandemic. (See PJM Monitor Reports Record-low Energy Prices.)
PJM Vice President of State and Member Services Asim Haque said late last year that the RTO will continue its cautious measures this year, with most employees continuing to work from home while its campus remains closed until at least June 2021. (See PJM Official Reflects on COVID-19 Impacts.)
State Clean Energy
PJM states continue to advance ambitious clean energy goals, causing conflicts among the RTO, stakeholders and government officials over the best ways to achieve the goals.
New Jersey Gov. Phil Murphy in January released an updated Energy Master Plan outlining how the state will meet its goal of 100% “clean energy” and an 80% reduction in statewide greenhouse gas from 2006 levels by 2050.
Murphy also issued an executive order directing the Department of Environmental Protection to issue regulations to reduce emissions and adapt to climate change. The regulations require a monitoring and reporting program to identify all significant sources of GHG emissions and integrate climate change considerations — such as sea level rise — into the department’s land-use permitting and other regulatory programs. (See NJ Unveils Plan for 100% Clean Energy by 2050.)
Indicating a desire for a new transmission strategy, New Jersey regulators voted in November to ask PJM to conduct a competitive solicitation for upgrades to connect 6,400 MW of OSW to the regional grid.
The New Jersey BPU unanimously requested that PJM integrate the state’s OSW goals into the RTO’s Regional Transmission Expansion Plan process under the “state agreement approach,” making it the first state do so since the approach was approved by the FERC under Order 1000. PJM expects to open a competitive solicitation window in the first quarter of 2021. (See NJ Asks PJM to Seek Bids for OSW Tx.)
| Avangrid
In April, Virginia Gov. Ralph Northam (D) signed legislation committing the state to closing most of its coal-fired generation by 2024 and making it the first southern state to adopt a 100% clean energy standard.
The PJM Carbon Pricing Senior Task Force, which began meeting in 2019, heard analysis in February on the impact of Virginia and Pennsylvania joining RGGI and the effect on emissions, prices and interregional trading of a “carbon price region” composed of up to five PJM states. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.) Virginia officially became a RGGI state Jan. 1, 2020.
Pennsylvania Gov. Tom Wolf issued an executive order in 2019 directing state officials to develop a rulemaking by July of 2020 for joining RGGI, although a Republican-controlled legislature has challenged his authority to do so. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
In July, the Pennsylvania House passed House Bill 2025 by a bipartisan majority of 130-71, requiring the legislature’s approval before Pennsylvania can enter any multistate program like RGGI that imposes taxes.
The Department of Environmental Protection would need to submit “a description of the economic and fiscal impacts that would result” from joining such a program to aid the legislature in its decision. The bill would also require legislative authorization before the state can impose a carbon tax on employers engaged in electric generation, manufacturing or other industries. (See Pa. House Passes Bill Limiting RGGI Entry.)
On the renewable energy side, the governors of Maryland, North Carolina and Virginia said in October they will collaborate to promote their states as a hub for the OSW industry. (See Md., NC, Va. to Team up on Offshore Wind.)
The Southeast and Mid-Atlantic Regional Transformative Partnership for Offshore Wind Energy Resources (SMART-POWER) will seek to increase regulatory certainty, encourage manufacturing of components, reduce project costs through supply chain development and share best practices.
OSW can “drive economic development and job creation as well as reduce the emission of greenhouse gases and other harmful air pollutants,” the group said in a press release, citing Department of Energy estimates that the Atlantic Coast OSW project pipeline could support 86,000 jobs, $57 billion in investments and generate up to $25 billion in economic output by 2030.
Virginia (5.2 GW) and Maryland (1.2 GW) have pledged to build 6.4 GW of the 29.1 GW in OSW capacity targeted by East Coast states.
FERC last month made additional alterations to its orders approving ISO-NE’s cost-of-service contract with Exelon’s Mystic Generating Station after the commission ruled on rehearing requests from the RTO, power generators and Connecticut regulatory entities (ER18-1639).
The commission clarified its multiple orders governing the contract after rehearing requests from ISO-NE, New England States Committee on Electricity (NESCOE), New England Power Generators Association (NEPGA), and Connecticut’s Public Utilities Regulatory Authority, Department of Energy and Environmental Protection and Office of Consumer Counsel. (See FERC Tweaks Orders on Mystic Contract.)
Commissioner Richard Glick, who had opposed the original 2018 orders and clarifications made to them in July, dissented. Commissioner Allison Clements, who was sworn in earlier in the month, did not participate in the proceeding.
Tank Congestion Charge
ISO-NE and NESCOE sought rehearing of FERC’s finding that the “tank congestion charge” in the fuel supply costs for Mystic Unit 8 and 9, which are fueled by a nearby LNG import terminal in Everett, Mass., was no longer needed. The groups argued that the charge was negotiated as a consumer protection in the agreement, saying a methodology for calculating tank congestion costs may be necessary for Exelon to demonstrate that ISO-NE ratepayers only pay for congestion attributable to serving Mystic.
The RTO signed the two-year, $400 million contract to preserve the region’s reliability after Exelon announced plans to shutter Mystic when its existing capacity supply obligations expire in 2022.
The commission agreed with those arguments, but it clarified that while Exelon must demonstrate that Mystic recovers only those costs attributable to serving it, the company will not be required to file the charge methodology. FERC also agreed with NESCOE’s request that these costs may be reviewed in the true-up process.
Mystic Generating Station, on the Mystic River in Everett, Mass.
Application of Clawback Mechanism
The commission was also persuaded by NEPGA’s arguments that the phrase “that were expensed” rendered the agreement’s clawback mechanism, modeled after provisions in MISO’s tariff, unjust and unreasonable. The mechanism requires Exelon to refund ratepayers if Mystic continues participating in ISO-NE’s markets after the termination of the agreement.
NEPGA noted that the phrase was a deviation from the MISO tariff’s language; FERC said it had accepted the change by reasoning that it was made to be consistent with ISO-NE tariff terminology.
“We agree with [NEPGA] that the commission’s intention is for the clawback mechanism to apply to costs ‘that are incurred’ rather than those that ‘that were expensed.’ We note that the term ‘expensed’ is not defined in the Mystic agreement and could be interpreted in many ways, including the method that [NEPGA] describe, thus creating a potential loophole that uses accounting treatment to avoid returning capital expenditures to New England ratepayers,” FERC wrote. It directed Exelon to remove the phrase.
Other Issues
But FERC said it disagreed with Connecticut that it erred by failing to apply the clawback mechanism to the Everett terminal. The state argued that Exelon should also refund repair and improvement costs to the terminal if it continues to operate after a separate cost-of-service agreement, one between the plant and the terminal, expires.
But the commission said that agreement is not under its jurisdiction. It did note “that ISO-NE, Everett and Mystic are free to negotiate a revenue crediting mechanism and include it in the Everett agreement, but such a mechanism is not required for Mystic’s jurisdictional rate to be just and reasonable.”
Glick Dissent
Noting his previous dissents, Glick said “the weight of the evidence across the commission’s New England fuel security proceedings shows that the retention of Mystic was aimed squarely at bailing out [an LNG] import facility.”
“If anything, the order underscores the extent to which many of the issues that are nominally related to Mystic really are, first and foremost, questions about the operation of the non-jurisdictional Everett facility that Mystic was retained to support,” Glick wrote. “Accordingly, I dissent from [this] order not because I necessarily disagree with any of the specific determinations made herein, but because I continue to believe that the commission exceeded its jurisdiction in the series of orders that brought us to this place.”
With almost 31 GW of wind capacity, Texas can lay claim to having more wind resources than any other state and all but four countries.
ERCOT, which manages about 90% of the Texas grid, has almost 25 GW of that capacity. It expects to have 38 GW of wind capacity by 2023.
Blessed with wide open spaces, a friendly business environment and one of the world’s most efficient deregulated energy markets, the Lone Star State is also on track to stake out similar leadership in solar energy.
Planned solar capacity in Texas | ERCOT
In November, Invenergy announced it was building what will be the largest U.S. solar farm in northeastern Texas. The 1.31 GW Samson Solar Energy Center, within ERCOT’s footprint near its seam with SPP, will be built in five phases over the next three years through a $1.6 billion investment.
ERCOT began 2020 with 2.28 GW of solar capacity, but projects that number to quintuple to 12.31 GW by the summer of 2022.
“We have giant solar resources here. The demand has never been better,” Charlie Hemmeline, executive director of the Texas Solar Power Association (TSPA), said during a webinar in November. “We’re definitely looking forward to adding megawatts.”
Solar energy has several advantages. The TSPA says expanded and more efficient manufacturing, advanced technology, economies of scale, and sophisticated financing partners have resulted in cost-competitive prices. According to the financial advisory firm Lazard, solar’s electricity costs have fallen by 89% in the last decade.
Solar facilities can also be built closer to load centers, forgoing the need for expensive transmission infrastructure often necessary to connect wind facilities to the grid.
Hemmeline said the key has been the ERCOT market and its prices, among the 10 cheapest states as recently as October ($.083/KWh).
“The market structure has worked very well for solar,” he said. “Texas has a lot of good fundamentals and characteristics. You’ve got a highly competitive generation market and on the other side, a highly competitive retail market. Our solar resources are fantastic, but a lot of other states have good solar resources and higher electricity prices.”
ERCOT’s long-term system assessment projects “significant” growth in solar and wind resources over the next 10 to 15 years across five different future scenarios. Here significant means more than doubling solar generation capacity by 22.2 GW to 35.3 GW and more than doubling wind capacity by 35 GW to 44.8 GW.
The assessment also foresees more than 21 GW of existing coal and natural gas generation capacity to be retired by 2035. Wind has already surpassed coal as the No. 2 fuel in ERCOT, behind only gas resources.
“There are a lot of changes in the resource mix,” ERCOT CEO Bill Magness told the Board of Directors in December. “We’ve started to see, as expected, real impacts of utility-scale solar.”
ERCOT’s projected future capacity additions, across five futures | ERCOT
The projected influx of wind and solar energy — and now battery storage — has raised ERCOT’s planning reserve margins to healthy percentages in the mid-20s through 2025, double the ISO’s minimum target of 13.75%. Gone are the days of single-digit reserve margins and sweaty palms in the face of record demand during the dog days of summer.
Magness said ERCOT had three major overarching goals in 2020: establishing rules for batteries and other new resources, improving the exchange of data information with the market and strengthening its core systems.
Much of that work is now part of the grid operator’s Passport Program, which is designed to allow emerging technologies to expand their participation in the market. Staff and stakeholders will spend the next four years aligning the task forces’ work with an upgrade of the grid operator’s energy management system that also incorporates distribution generation resources into its systems. (See ERCOT Board of Directors Briefs: Dec. 8, 2020.)
“We’re in a good position to start taking on work in 2021,” Magness said.
Utility-scale solar facilities are helping pad ERCOT’s reserve margins. | CPS Energy
New Tx Needed
ERCOT also has staff’s eyes on the transmission system. The ISO endorsed almost $600 million in transmission projects in 2020, including the $219 million Corpus Christi North Shore Project to address future industrial load growth on the lower Gulf Coast. (See “Corpus Christi Tx Project Gets OK,” ERCOT Board of Directors Briefs: June 9, 2020.)
Some stakeholders have warned more transmission will be necessary to stay ahead of the renewable tsunami. Texas’ Competitive Renewable Energy Zones effort jump-started the growth of West Texas wind energy, but that was almost a decade ago. Oil and gas activity in the Permian Basin has only exacerbated the situation.
“We’re finding in our region that the transmission is getting loaded up now,” said David Hudson, president of Xcel Energy’s Southwestern Public Service subsidiary.
“[Renewable] generation is developing faster than transmission in ERCOT. We need more transmission to relieve the congestion,” said Susan Williams Sloan, the American Wind Energy Association’s vice president of state affairs. “The current system we have is not really fixing the problem. One of the things we need to do is talk about the fact that 20 years ago, when the competitive market was set up, [state] leaders understand transmission was [then] fundamental to the market.”
Help is coming. ERCOT’s 2020 Regional Transmission Plan lists eight noteworthy reliability projects and three economic projects that will be necessary by 2027. The Regional Planning Group said transmission owners will provide the ISO additional details on projects under review “to ensure the identified system facilities are still needed.”
If Texas is going to continue to grow “in the way that we know it can,” Hudson said, “transmission will be an important part in that — and figuring out the right way to build and allow the growth of the Texas energy market.”
