The Maryland Public Service Commission last week approved a settlement allowing Transource Energy to move forward with its controversial Independence Energy Connection (IEC) transmission project.
In its order issued June 30, the PSC said Transource can build the 4.5-mile western portion of the 230-kV overhead transmission line from Washington County, Md., to a substation in Franklin County, Pa.
Baltimore Gas and Electric will build the 6.6-mile eastern portion of the project, comprising two segments from substations in Harford County, Md., to a substation across the border in York County, Pa. (Case No. 9471).
Signing the settlement in addition to Transource were the Maryland Power Plant Research Program, the commission’s technical staff, BGE, Harford County and landowner parties, including the group STOP Transource Maryland.
The Harford County segment of the project, which also crosses portions of Baltimore County, was redesigned from the original proposal to avoid greenfield construction through the utilization of BGE’s existing utility infrastructure and rights of way. Transource filed the second configuration for the IEC East project with Maryland and Pennsylvania regulators in October after settling with landowners and state officials opposed to the original route of a nearly 16-mile-long new transmission line. (See Transource Files Reconfigured Tx Project.)
Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | Transource Energy
The PSC directed Transource and BGE to minimize all construction activities and additional construction-related costs until the project wins the approval of the Pennsylvania Public Utility Commission and final approval by PJM. It concluded that portions of the proposed transmission line in Maryland will “address existing and future regional congestion issues,” while reducing impacts on the environment, agricultural activities and natural resources.
“The commission finds that this project will provide benefits to Maryland ratepayers, including enhanced reliability of electricity service and greater access to least-cost energy from elsewhere within PJM, while also accommodating future development of renewable technologies such as offshore wind,” PSC Chair Jason Stanek said in a statement.
In 2016, PJM identified the IEC project as a solution to relieve congestion on the AP South interface. Transource filed its initial applications with the Maryland and Pennsylvania commissions in 2017.
The Harford County segment of the project, which also crosses portions of Baltimore County, was redesigned from the original proposal to avoid greenfield construction through the utilization of BGE’s existing utility infrastructure and rights of way. Transource filed the second configuration for the IEC East project with Maryland and Pennsylvania regulators in October after settling with landowners and state officials opposed to the original route of a nearly 16-mile-long new transmission line. (See Transource Files Reconfigured Tx Project.)
PJM’s analysis of the new IEC East configuration determined it will cost $496.2 million and realize $844.8 million in congestion benefits. The analysis ran into protests by PJM stakeholders last year, who said the project did not meet the RTO’s cost-benefit test. (See PJM Analysis of Transource Alternative Challenged.)
Nils Hagen-Frederiksen, press secretary for the Pennsylvania PUC, said the proposed settlement regarding the Pennsylvania portions of the IEC project is pending regulatory approval before the commission. Hagen-Frederiksen said additional evidentiary hearings are scheduled for July 9 and 10 before the PUC administrative law judges, with briefs from all parties due in mid-August and reply briefs due for a yet-to-be determined date.
“At some point, after all the briefs have been filed and the record has been closed, the administrative law judges will review all of the case materials and issue a recommendation for the full commission to consider as part of their final decision, but there is no specific schedule for that,” Hagen-Frederiksen said.
Concluding “less is more,” stakeholders looking to shape a planned grid transition study for New England on Wednesday discussed creating a smaller, more manageable committee to oversee the hiring of consultants and conduct of the analysis.
A joint meeting of the New England Power Pool Markets and Reliability committees opened with a memo from the officers of both committees, which noted the sentiment of several stakeholders favoring adapting modeling and assumptions from existing studies or those currently underway rather than starting from scratch, as was discussed at the joint meeting in May. (See NEPOOL Markets/Reliability Committee Briefs: May 27, 2020.)
“We also need to consider how detailed workflow will be managed between meetings. For example, some have suggested hiring an independent consultant to manage these efforts, designating a small representative working group of individuals willing to commit time towards managing study details, or similar,” the memo said.
It included a draft template for collecting proposals of scenario assumptions. The final template will be distributed soon; responses are due to the MC secretary by July 17 for the Aug. 4 joint meeting, at which a presentation will be made on a grid study underway now by Energy Futures Initiative and E3.
Eversource Offers Preliminary Results
Vandan Divatia of Eversource Energy presented his company’s Grid of the Future study methodology and preliminary results, with modeling and analysis performed by London Economics International.
“I agree that this approach — with a 10- to 15-person smaller group … with representatives from each sector participating and then bringing back information for alignment — makes a lot of sense,” Divatia said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
Economy-wide CO2 emissions reduction will result in major changes to the electricity industry. Increased demand from electrification of heating and transportation will shift the peak from summer to winter, leading to deployment of energy storage resources and new technologies, as well as market support for reliability services, transmission expansion and operational infrastructure, the report said.
The Grid of the Future Study is designed to understand changes in all sectors of the economy and their impact on the grid. | ISO-NE, LEI
The study said that electric vehicles could account for 48% of emission reductions from 2020 to 2040, which led Ben Griffiths of the Massachusetts attorney general’s office to ask if the study authors had “a sense of how much decarbonization will then be occurring from the power sector, or from converting gas heating customers to electric heat pumps, or something like that?”
Divatia said Eversource and LEI had assessed what would be required from each sector to achieve near total decarbonization by 2040 but had not included that level of detail in the study.
| LEI
“Transportation accounts for 42% of the carbon footprint of New England, and the electric sector accounts for only 14%, so if we want to go from here to there in a strategic fashion, the approach we’ve taken is that each sector needs to do its job,” Divatia said.
On how the study planners got from emissions to modeling, Julia Frayer of LEI said, “We made a starting assumption that we wanted to look beyond just the power sector, so we could actually reflect the intentions of policymakers, which is to decarbonize the economy.”
Because it is a long-duration study going out to 2050, the analysts incorporated a capacity expansion model with two objective function goals, she said. “One was to achieve the carbon emissions reductions, and the second criterion was to meet electricity demand reliably.”
The capacity expansion model built out a plan for resources that could meet the 2050 carbon emissions goals. “Through backwards induction, we could back into interim goals that we’ve created for 2040 and 2030 … for transformation of the electricity sector from the demand side and the supply side,” Frayer said.
National Grid 2020 Economic Study Details
Engineer Julia Grasse of National Grid presented the firm’s 2020 Economic Study request, including a pathway emphasizing the role of exchange with Québec, which previous studies indicated may be utilized as a balancing resource in a future system with a large amount of intermittent renewables. (See “2020 Economic Study Scope, Assumptions,” ISO-NE Planning Advisory Committee Briefs: May 20, 2020.)
Two recent studies in particular drove the company’s request, the first being a 2019 offshore wind study by the New England States Committee on Electricity (NESCOE) that showed high levels of renewable resource spillage, and the second being MIT’s 2020 study on deep decarbonization of the Northeastern U.S., which demonstrated that bidirectional transmission with Québec complements high intermittent resource mixes in New England.
Specifically, National Grid wants to evaluate the role that large-scale “dispatchable reservoir” hydro in the north could have in meeting the state goals, the presentation said.
ISO-NE will analyze three scenarios: the base case, with varied offshore wind, solar and thermal retirements; bidirectional transmission capability, with use of existing and new interties to explore up to 3,600 MW of export capability to Québec; and varied amounts of in-region battery storage, the lowest at 2,000 MW as used in the NESCOE study.
Stakeholders will discuss the study at the Planning Advisory Committee meeting July 22, with further refined RTO assumptions. The draft results expected, and sensitivities identified will come in the third quarter, with sensitivity results and draft ancillary services results in the fourth before the draft and final reports in Q1 2021.
Bay State Net-zero Overview
Participants also heard an overview of a Massachusetts decarbonization study to guide the state’s effort to achieve net-zero greenhouse gas emissions reductions by 2050, an initiative that boasts its own website.
“Overall, our approach is backcasting, which is an exercise to understand what is needed today to get to where we want to be in 2050,” Massachusetts Undersecretary for Climate Change David Ismay said. (See “Modeling the Future,” Overheard at 166th NE Electricity Roundtable.)
| Mass EEA
The state’s net-zero policy requires at least an 85% reduction in emissions below 1990 levels by 2050, plus carbon sequestration to make neutral the remaining emissions, he said.
“We’re modeling the mega-region of the Northeast from New York to Maine, together with Québec and New Brunswick … for a 90% emissions reduction from 1990 levels, which we think is valuable, since there are different dynamics when you go past an 80% reduction,” Ismay said.
The study will entail more than a half-dozen complete scenarios, including detailed total cost analyses, and the state will work through NESCOE this summer to share full results with colleagues in all New England states ahead of a planned full public release in the fall, he said.
When asked if Massachusetts was planning to request an economic study by ISO-NE based on the analysis, Ismay said, “We will be bringing a lot of data to ISO-NE and NEPOOL for this discussion, rather than asking ISO-NE to do it themselves.”
“At some point soon, the grid operator will need to get into the details at least at this level, though I’m not exactly sure how or when that’s going to happen,” he added.
Stakeholder Perspectives
Brian Forshaw of Energy Market Advisors proposed an analytical framework for the future grid study on behalf of the Connecticut Municipal Electric Energy Cooperative (CMEEC).
ISO-NE currently lacks a Forward Capacity Market pricing model for planning studies, which can often make it more challenging to interpret study results, the presentation said.
CMEEC recommended development of a capacity optimization tool to reflect the current market construct and develop estimates of what capacity market prices would be under various scenarios, he said.
Caitlin Marquis of Advanced Energy Economy presented input that asked whether the markets, as designed today, meet future needs in a technology-neutral way. She said that AEE views analysis of the transition to the future and discussion of potential market reforms as being just as important as the planned operational and reliability assessment.
With respect to the reliability analysis, “we’re really most interested in understanding what grid services and operational tools are needed to address reliability gaps,” Marquis said. “We see the resources of the future as requiring more flexibility, see the heightened importance of resource availability and not just adequacy, and certainly a different range of reliability services.”
One side of that assessment should be looking at whether markets are equipped to make full use of demand flexibility and demand-side resource participation, she said.
Peter Fuller of Autumn Lane Energy presented further thoughts on the evolving grid study, made with the endorsement of NEPOOL members NRG Energy and Sunrun.
Today’s markets do not include a value for carbon commensurate with the value that state policies imply for it, the presentation said. It also asks where system inertia and stability will come from in a system with more distributed, digital and inverter-based resources.
The presentation asked what other aspects of system operability and reliability are being taken for granted that will need to be explicitly valued in the future and said the sponsors hope to address that and other questions at the August joint meeting.
MISO, PJM and SPP are within a hair’s breadth of meeting FERC’s transparency requirements around affected-system studies, but both their joint and individual filings on seams issues still need fine-tuning, the commission ruled in a series of orders last week.
The commission last September ruled that the three RTOs’ joint operating agreements do not provide enough clarity on how they handle the study of generator interconnections along their seams. (See FERC Denies Rehearing on Affected System Order.)
MISO seams neighbors | MISO
FERC’s June 30 orders repeated that theme, directing the RTOs in their joint compliance filings to provide clearer descriptions of how they analyze each other’s systems during respective interconnection studies (ER20-942, ER20-940). The commission found both the MISO-PJM and MISO-SPP joint operating agreements lack indexes that point interconnection customers to business practice manuals that explain the circumstances under which the RTOs will perform an affected-system analysis under an energy resource interconnection service (ERIS) or a network resource interconnection service (NRIS) modeling standard.
FERC gave the RTOs 60 days to add references to the rulesets.
The commission approved other aspects of the seams filings, including details on how the RTOs determine the queue priority of projects and select the ERIS or NRIS modeling standard, as well as how they exchange affected-system information and determine study criteria.
Another Compliance Filing for SPP
The commission found SPP’s proposed revisions partially complied with its 2019 order and directed the RTO to submit a further compliance filing within 60 days. FERC said the RTO’s “Guidelines for the SPP GIP Process and Business Practices” document was not sufficiently detailed, as it lacked the specific section number containing the ERIS and NRIS modeling information (ER20-945).
PJM in Partial Compliance
FERC said PJM had complied with the commission’s directive to detail in its Tariff the time allowed interconnection customers to review affected-system study results and said the 30-day period is consistent with the time given to the RTO’s interconnection customers for reviewing system impact and facility studies.
But it ordered the RTO to make another compliance filing within 60 days, saying it had failed to include where in its manuals or other documents interconnection customers can find details of the modeling PJM uses in studies of ERIS and NRIS requests on its own system (ER20-939).
PJM stakeholders continued their talks last week over integrating carbon pricing while focusing on the impacts of states looking to join regional environmental collectives like the Regional Greenhouse Gas Initiative.
Neal Fitch of NRG Energy gave a presentation noting that carbon pricing is being expressed in direct programs through states that have already joined RGGI and also indirectly through renewable portfolio standards and zero-emission credits (ZECs). Fitch said the indirect carbon pricing programs involve a “fairly significant amount of money” that needs to be addressed, including $4.4 billion in total RPS costs from 2014 to 2018 compared to $1.4 billion raised in RGGI auctions over the same time period.
Fitch said PJM must ensure it considers all programs at the state level that are driving carbon costs while addressing the possibility of direct carbon pricing in the RTO. He said NRG would like to see debates on ways PJM could utilize existing state programs to transform them into a vehicle to achieve carbon-reduction goals at a lower cost through greater efficiency.
“We don’t want to lose sight that there are a lot of levers already in play regarding carbon pricing,” Fitch said.
Border adjustments and leakage have been some of the most hotly debated issues regarding carbon pricing. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.) But Fitch said as more states decide to adopt carbon pricing, border adjustments become less of an issue because they are “remedied as states migrate toward a consensus position on carbon regulation.”
“As the progress and expansion of carbon regulation goes beyond one or two states, the need to address leakage and border adjustments remedies itself,” Fitch said.
Jason Barker of Exelon asked Fitch if NRG is asking that the task force not address border adjustments or leakage in future discussions.
Fitch said border adjustments and leakage remain “something to contemplate” and that he would want them fully addressed and vetted before moving too far ahead. He said stakeholders who find border adjustments to be a “constraint” when discussing carbon pricing may be more comfortable with carbon pricing as the borders go away with more states adopting environmental standards.
Barker said one of the interests Exelon has for the task force is seeing how stakeholders can both enhance the value of the carbon programs states are undertaking while also recognizing time is an element in the discussions. Barker said Exelon doesn’t want to lose sight of what can be accomplished in the short term while pursuing broader solutions over the longer term.
“There have been decades of talk about carbon pricing, and it hasn’t happened other than in a state-by-state basis,” Barker said.
Michael Borgatti of Gabel Associates spoke on behalf of the American Wind Energy Association, the Solar Energy Industries Association and 27 other organizations who were signatories of a letter sent to the PJM Board of Managers on June 26 calling for continued discussions on carbon pricing.
FERC last week established a paper hearing to explore the justness and reasonableness of ISO-NE’s new-entrant rules for its Forward Capacity Market (EL14-7-002, EL15-23-002, EL20-54).
The June 30 decision came on remand from the D.C. Circuit Court of Appeals, which ruled in February 2018 that the commission failed to adequately explain why it approved capacity market rules for ISO-NE in 2014 like those it had rejected in PJM for suppressing prices. (See DC Circuit Orders FERC to Review ISO-NE Auction Orders.)
Before accepting a new generating resource for its FCM, ISO-NE tests to ensure they do not cause overloads that cannot be fixed in time for the capacity commitment period. | ISO-NE
The court ruling granted petitions for review by Exelon and the New England Power Generators Association on rules allowing new suppliers to lock in their first-year clearing prices for six additional years while requiring them to offer at $0 in years 2 through 7 (15-1071).
“In light of the time that has passed since the NEPGA and Exelon complaints were filed and the changes to the ISO-NE Forward Capacity Market during that time, we believe it is appropriate to provide parties an opportunity to refresh the record on which we will address the issues raised in the court’s remand,” the commission said.
It noted that capacity prices have been trending downward in ISO-NE auctions and that it has approved several changes to the FCM, including Tariff revisions to implement the Competitive Auctions with Sponsored Policy Resources construct, it said. (See ISO-NE Capacity Prices Hit Record Low.)
The commission issued a set of questions to guide the paper hearing and said it was instituting a new Section 206 proceeding “because certain of these questions may not have been directly presented in the original NEPGA and Exelon complaints.”
Relevant Questions
At the inception of the FCM in 2006, the commission accepted Tariff provisions that allowed a new resource to lock in for five years the capacity price that it receives in the first Forward Capacity Auction in which it participates. Under that rule, a new resource receives that initial clearing price for the four subsequent annual auctions (the lock-in period), even if the actual clearing price for those subsequent auctions is higher or lower.
Exelon and NEPGA had complained that the commission’s approval of the rules was at odds with its 2009 ruling rejecting a similar construct in PJM. The D.C. Circuit agreed, saying that FERC had “failed to square its decision with its past precedent.”
In last week’s order, FERC said it was concerned that any potential effects that the current new-entrant rules could have on the FCM clearing price may outweigh the certainty and other benefits that the commission considered when approving those provisions.
To evaluate the need for the price lock in its entirety, the paper hearing will first pose the following questions:
How many resources have taken advantage of the price lock to date?
Is a price lock still needed to incent new entry in ISO-NE?
Does the price lock lead to unreasonable price suppression in the entry year?
Does the price lock with the zero-price offer rule result in unreasonable price suppression in years 2-7?
Is the price lock unduly discriminatory?
If the price lock is retained, should the term be shortened and, if so, what would be a just and reasonable term?
Second, to evaluate retaining the price lock and adding an offer floor, the commission will ask how an offer floor would be implemented, whether it would require significant market redesign, and what the timeline would be for implementation.
Third, to evaluate whether to impose an alternative replacement rate, the commission seeks to address whether there are alternative approaches to the current price lock that would be sufficient to incent new entry, and how these alternative approaches would address any concerns related to unreasonable price suppression, undue discriminatory or preferential treatment.
PJM has created a new group to work with states to advance energy initiatives like offshore wind and grid security.
The State Policy Solutions group will combine PJM’s knowledge of planning, markets and operations with its interpretation of state laws and regulations to help government bodies implement energy policies.
PJM officials said the new group will lend the RTO’s “subject matter expertise” to help states reach energy goals and to help facilitate discussions among states or regional groups if efficiencies in policies make sense across multiple government bodies.
“Our states are key stakeholders, and we’re committed to partnering with them whenever possible as they contemplate and execute their policy goals,” CEO Manu Asthana said in a statement.
The State Policy Solutions group is initially focusing on five areas at its launch, PJM said, including offshore wind, resource adequacy, grid modernization, clean energy targets and grid security. The RTO said the areas were chosen because of their overlap with its main functions.
Tim Burdis, PJM’s lead strategist for state government policy, will manage the group, reporting to Asim Haque, the RTO’s vice president of state policy and member services.
Haque, who served as chairman of the Public Utilities Commission of Ohio before coming to PJM in 2019, said the group is a response to evolving state energy policies.
Although the RTO has given technical assistance to states in the past, Haque said the new group will provide a more “holistic, end-to-end approach” through the RTO’s understanding of state laws, regulations, related cases and FERC orders.
“PJM will always champion its primary duties of keeping the lights on and running efficient markets,” Haque said. “At the same time, PJM can utilize its expertise in carrying out those functions to assist our states as they advance their policy objectives. This is an opportunity for us to innovate and partner together in an evolved RTO/multistate dynamic.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said what the group will be tasked with doing is not totally clear to him or his organization, but he said the group “seems very promising” and that states’ access to PJM’s expertise will be helpful in decision-making on complicated issues.
“Over the past few years, there have been complaints that PJM has not been responsive to the concerns of the states,” Poulos said. “I’m hoping this ushers in a period where PJM works to repair and develop those important relationships.”
State regulators and other stakeholders were dismayed when PJM announced last year that Denise Foster had unexpectedly resigned as head of the RTO’s State and Member Services Division and that her unit would be realigned. (See Stakeholders, States in Dark over PJM Personnel Moves.)
PJM has frequently found itself in the middle of state-federal jurisdictional disputes over energy policy. Illinois and New Jersey officials are considering pulling their utilities from the RTO’s capacity market because of FERC’s 2019 order expanding the minimum offer price rule.
The RTO is currently considering how it could incorporate carbon pricing for only some of its 14 member states (including D.C.). (See related story, PJM Carbon Pricing Group Talks RPS, ZECs, RGGI.)
Energy Harbor will pay almost $66 million to cancel a solar power purchase agreement signed by its predecessor, FirstEnergy Solutions (FES), clearing away another legal battle as it continues to emerge from bankruptcy.
On Saturday, Judge Alan M. Koschik, of the Bankruptcy Court for the Northern District of Ohio, approved a stipulation outlining the settlement between Energy Harbor and Maryland Solar Holdings.
The judge’s order came three days after FERC granted Energy Harbor’s request to hold in abeyance for 90 days a docket the commission had opened to consider whether FES could abrogate its contracts with Maryland Solar and the Ohio Valley Electric Corp. (OVEC) (EL20-35).
The commission said it agreed with Energy Harbor that the proceeding would be moot if the bankruptcy court accepted its settlements with Maryland Solar and one announced in May with OVEC.
Energy Harbor agreed to pay Maryland Solar $65.9 million less $1 million in cash collateral held by the solar company for the PPA signed by FES in 2011 for the purchase of renewable energy and related credits. Maryland Solar, which owns a 20-MW solar farm in Washington County, Md., had sought $79.8 million in the dispute.
FES changed its name to Energy Harbor upon emerging from bankruptcy in February, with former bondholders owning 50% of the equity.
Energy Harbor also assumed FES’ obligations with OVEC and agreed to pay the company $32.5 million in a settlement approved by the bankruptcy court on June 15. (See Energy Harbor to Pay OVEC $32.5M in Settlement.)
In March, FERC ordered a paper hearing to consider FES’ attempt to void the OVEC contract and PPA with Maryland Solar as part of its bankruptcy proceeding. The commission acted after the 6th U.S. Circuit Court of Appeals issued a mandate overruling the bankruptcy court’s May 2018 injunction preventing FERC from issuing any order requiring FES to continue complying with the contracts. The appellate court also reversed the bankruptcy court’s ruling allowing FES to reject the contracts.
In holding the proceeding in abeyance, FERC ordered Energy Harbor to file a report by Sept. 29 updating the commission on the status of the court proceedings.
FERC’s order opening the docket said the “jurisdictional contracts” included several wind PPAs signed by FES in addition to the OVEC and Maryland Solar contracts. But Energy Harbor’s June 15 motion to hold the FERC docket in abeyance said Maryland Solar and OVEC were “the sole counterparties to the jurisdictional contracts at issue in this proceeding.”
A company spokesman clarified that FES had entered into stipulations with all of the other counterparties during the Chapter 11 restructuring proceedings.
The Texas Public Utility Commission last week approved a new rule that allows utilities operating solely outside the ERCOT region to apply for a generation-cost recovery rider (GCRR) for capital investments in individual generation facilities (55031).
The rule applies primarily to El Paso Electric, Entergy Texas, Southwestern Electric Power Co. and Xcel Energy’s Southwestern Public Service. It stems from a bill passed (HB 1397) in last year’s state legislature.
PUC Chair DeAnn Walker, pointing to the abundance of renewable facilities already installed and coming online, modified the rule in a memo before the July 2 open meeting to clarify that a utility may include “more than one discrete generation facility” in the rider. Utilities will be allowed to amend their GCRRs to request inclusion of additional generators.
PUC Chair DeAnn Walker, the sole commissioner present, leads July 2’s open meeting.
“I feel like where we are with our future generation, most are going to be smaller projects, where you may need to have more than one included in the rider,” Walker told her fellow commissioners.
The commission agreed that if the rule is not working, they can always revisit the issue. Walker said the PUC’s earnings-monitoring process would allow them to determine whether any utilities were taking advantage of the rule.
Walker was the only commissioner present in the PUC’s meeting room. Commissioners Arthur D’Andrea and Shelly Botkin both called in from remote locations.
PUC Extends Customer Relief Program
The commissioners agreed to extend the state’s Electricity Relief Program from July 17 to Aug. 31, citing Gov. Greg Abbott’s decision to curtail certain economic activities in the face of rising coronavirus diagnoses and hospitalizations. An order will be drafted for the commission’s approval during its July 16 open meeting.
The PUC created the program in March to help retail providers’ unemployed customers by shielding them from disconnections for nonpayment and offering bill payment assistance.
“While we certainly wish we could snap our fingers and make this virus go away, it’s clearly with us for the long haul and we need to reflect that in our decisions,” Walker said.
The state reported a record 8,258 COVID-19 confirmed cases on July 4, bringing its total to 195,239. A record 8,181 Texans were hospitalized on Sunday. The state has reported 2,637 deaths.
The program is funded by a rider charge applied to customer bills within the ERCOT region.
Entergy, LCRA Get CCNs
In other actions, the PUC:
Granted Entergy Texas a certificate of convenience and necessity (CCN) to build, own and operate a 230-kV line and substation north of Houston that is needed to accommodate future load growth. Entergy has reached a settlement with all intervenors on a 9-mile route that is projected to cost $34.1 million. The substation is expected to cost an additional $23.3 million (49715).
Approved Lower Colorado River Authority’s request for a CCN for a new substation and a 138-kV line connecting the facility with the grid in the Texas Hill Country north of San Antonio. The 22.5-mile project, costing an estimated $64.3 million, is needed to address congestion and voltage issues, LCRA said (49523).
FERC last week ordered hearing and settlement judge procedures on American Transmission Systems Inc.’s (ATSI) request to recover deferred and ongoing legacy costs related to the company’s move from MISO to PJM in 2011 (ER20-1740).
ATSI’s proposed revisions to its transmission formula rate, filed by PJM in May, sought $154 million in additional rates, including legacy MISO Transmission Expansion Plan costs, costs of ATSI’s integration into PJM and deferred vegetation management costs.
In 2011, the commission rejected ATSI’s first request for recovery of PJM integration costs and MISO exit fees, saying the company had failed to “provide sufficient information or support that would enable the commission to find that it is just and reasonable for ATSI’s transmission customers to bear the costs arising from the decision to switch RTOs.”
FERC upheld the denial on rehearing in 2016. It said its ruling was without prejudice, allowing ATSI to file a new request that included a detailed cost-benefit analysis showing that the benefits to wholesale transmission customers exceed the costs of the switch to PJM. (See FERC Rejects ATSI Bid for Cost Recovery on Switch from MISO to PJM.)
American Transmission Systems Inc. is a unit of FirstEnergy. | FirstEnergy
In justifying its new rate request, ATSI, a unit of FirstEnergy, said its move to PJM has generated about $4 billion in benefits, dwarfing the $154 million it seeks to recover.
But American Municipal Power (AMP), Buckeye Power, Industrial Energy Users of Ohio (IEU) and the federal energy advocate for the Public Utilities Commission of Ohio protested the request.
AMP and Buckeye said the request should be rejected because of the four-year delay in refiling for the RTO transition costs since the commission’s 2016 rehearing order. AMP said utilities should not have unlimited discretion on how long it will carry deferred costs on its books. AMP, Buckeye and IEU also contended that ATSI’s cost-benefit analysis did not accurately calculate the impact on Ohio retail customers.
IEU and AMP also challenged ATSI’s request for $18.7 million in deferred vegetation management costs incurred from 2013 to 2016, saying the company failed to demonstrate that they were “enhanced” or prudently incurred.
Citing the disputes, the commission’s order accepted ATSI’s proposed Tariff revisions and suspended them for five months to become effective Dec. 1, subject to refund.
Stakeholders at a virtual public hearing on Thursday praised the Bureau of Ocean Energy Management for working through the pandemic and urged the agency to approve the 800-MW Vineyard Wind offshore wind project along with the 1-nautical-mile turbine spacing advocated by developers and recommended by the U.S. Coast Guard.
“I’d like to go on record in supporting the 1-mile distancing between towers,” said Brad Lima, recently retired as chief academic officer of the Massachusetts Maritime Academy. “There was one statement in the [May 14] Coast Guard report that stood out: ‘Anything that can be done to reduce traffic scenarios is a prudent decision.’ … It’s quite evident based on the number of companies which have won leases for the Atlantic Coast sites that offshore wind is where power generation wants to be.”
BOEM’s supplemental environmental impact statement (SEIS) for the Vineyard Wind project, released June 9, included a proposal by the Responsible Offshore Development Association (RODA), a fishing industry group, calling for six “transit lanes” at least 4 nautical miles wide for a projected 22 GW of projects from the coasts of New England to Virginia. (See BOEM Issues Revised EIS for Vineyard Wind.)
The proposed transit corridor would provide a path for vessels traveling from New Bedford, Mass., and other southern New England ports to fishing grounds in Georges Bank, east of Cape Cod. Only one of the lanes intersects the Vineyard Wind 1 wind development area in federal waters south of Massachusetts.
The report also reflects changes to the Vineyard project since the draft EIS: replacing 696-feet-tall, 10-MW turbines with 837-feet-tall, 14-MW turbines. The SEIS found that the cumulative effect of the 22 GW of projects could have major impacts on navigation and vessel traffic, commercial fisheries, and military and national security uses.
Cumulative Impacts
“Global climate change presents a serious threat to the commonwealth’s environment, residents, communities and economy,” said Lisa Engler, director of the Massachusetts Office of Coastal Zone Management (CZM). “Gov. [Charlie] Baker has expressed the need for action. The magnitude of the impacts from climate change requires all of us to put politics aside and act together quickly and decisively.
“We still have the ability to check the severity of future impacts by aggressively reducing greenhouse gas emissions and adapting to the changes,” Engler said. “The cumulative analysis included in the SEIS ensures that potential impacts beyond this individual project are evaluated.”
Engler said the state’s review, which included the Department of Environmental Protection, Energy Facilities Siting Board, Environmental Policy Act Office, Department of Public Utilities and the CZM, is complete.
The total project capacity still remains at 800 MW, and a change to the turbine capacity would not result in a change to the footprint or to the 8-MW minimum turbine capacity, said BOEM environmental coordinator Jennifer Bucatari, who presented the agency’s summary of the SEIS. The project will comprise up to 100 wind turbines.
Vineyard Wind also submitted changes expanding the onshore substation, with a total area of ground disturbance of 7.7 acres, which is 1.8 acres greater than the area analyzed in the draft EIS, she said.
As for the various transit lane proposals and the turbine locations they would displace, “under the current cumulative scenario, displacement of all these turbine locations is not feasible, and therefore the addition of all six transit lanes would lead to the elimination of some of the turbines that could have occurred within these lanes,” Bucatari said.
Competitor Concerns
David Hardy, COO of Ørsted North America Offshore, praised BOEM’s work on the supplemental EIS. “It is no small feat to forecast the myriad impacts the development of a new ocean-based resource will have on the human and natural environment, both positive and negative,” he said.
Ørsted has been awarded more than 2,900 MW of offtake rights, with the states of Connecticut, Maryland, New Jersey, New York, Rhode Island and Virginia having all awarded their first offshore projects to the company.
Hardy said Ørsted “strongly” supported the developers’ consensus proposal of 1-nautical-mile turbine spacing, with an east-west layout for simpler navigation.
He said RODA’s proposed 4-mile spacing “would result in the loss of over 50 wind turbine locations from our current three projects: South Fork, Revolution Wind and Sunrise Wind. … This equates to a nearly 25% loss in the total wind turbine locations for our state” power purchase agreements.
The SEIS should reflect a more favorable rating of offshore wind as a domestic economic development engine consistent with ongoing and planned investments, Hardy said, noting Ørsted is planning to spend $15 billion over the next decade in the U.S.
“For many of the cumulative impact parameters considered in the SEIS, BOEM chose not to incorporate widely accepted or legally mandated mitigation strategies; thus the bottom-line impact of the 22-GW buildout must be considered a worst-case scenario and not as representative of as-constructed impacts,” Hardy said.
Where BOEM comes out on the Vineyard project will likely determine the fate of offshore wind in the whole country, said Joe Martens, director of the New York Offshore Wind Alliance and former commissioner of the New York Department of Environmental Conservation.
“A plain reading of the SEIS could lead to the conclusion that if the Vineyard Wind project is not advanced, other projects in various stages in the pipeline inevitably will,” Martens said. “I don’t think this is the case. … The [Vineyard] developers have gone above and beyond the extensive federal, state and local requirements for offshore wind.”
The Vineyard project is in effect a “litmus test” for the industry, he said, urging its approval on both environmental and economic grounds. “All eyes are on this project.”
Communities Supportive
The project has been thoroughly vetted by all the “top notch” environmental groups and should be approved to provide more renewable energy for the state, said Eileen Mathieu, board member of Sustainable Marblehead, a volunteer community organization in the town of Marblehead, Mass.
“In Marblehead, our municipal light department … is eager to be able to purchase reasonably priced electricity from renewable sources,” Mathieu said. “However, local resources are very constrained, so that right now we only have 12% renewable energy in our portfolio and 26% nuclear.”
Marblehead buys its power through the Massachusetts Municipal Wholesale Electric Co., which “needs wind options to provide its 22 municipal light plant members, and currently it has none,” Mathieu said.
“We strongly support this project as the first large-scale OSW project in the region,” said Kai Salem, policy advocate for the Green Energy Consumers Alliance.
Fred Hopps of Beverly, Mass., founder of the town’s clean energy advisory committee — and a former resident of Copenhagen, Denmark — gave “a thousand thanks to the Danes for practically single-handedly keeping offshore wind energy alive.”
BOEM will hold two more web-based public hearings on the SEIS for Vineyard Wind, on July 7 and 9, with the public comment period open through July 27 on a dedicated website. The agency expects to publish its final EIS in November and to issue a final decision in December.
Vineyard Wind is a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables.
