It took all of two weeks into the new year before SPP set new peak records for wind and renewable energy output.
The RTO on Thursday upped its historical highs for wind and renewable energy to 19.9 GW and 21.2 GW, respectively. Those marks broke records set late last year of 19.7 GW and 20.9 GW, respectively.
SPP’s latest peak records for wind, renewable energy. | SPP via Twitter
“An incredible amount of wind generation in our region, all without sacrificing reliability of the grid,” SPP CEO Barbara Sugg tweeted.
Maybe not that incredible, given that wind served 31.3% of SPP’s load last year. The grid operator said that made it the first U.S. RTO or ISO with wind as its No. 1 fuel source.
ERCOT, SPP’s primary competitor in the wind race, saw wind energy meet 22.8% of its load last year, second only to natural gas (45.5%). The Texas grid operator, which meets about 50% more demand than SPP during summer months, also set a record Thursday with 22.9 GW of wind generation.
SPP set six records for wind production in 2020 and four records for renewables. In April, the RTO established a record when wind served 73.2% of load for one interval. (ERCOT’s record for a single interval is 59.3%.)
The grid operator has 26 GW of installed wind capacity on its system, and another 39.9 GW of proposed projects are under some form of study in its generation interconnection queue.
MISO will draw on its new planning futures to build the first set of models that could result in its long-term transmission plan’s first projects.
The RTO’s senior manager of system planning coordination, Jarred Miland, said staff are building reliability and economic models similar to those used in MISO’s annual Transmission Expansion Plan (MTEP). He said the long-term assessment’s first models will be ready for member review during 2021’s first quarter.
The models will be based on three MTEP futures designed for use in the 2021 planning cycle and beyond.
Miland said during Thursday’s Planning Advisory Committee that staff will use the more conservative Future I to build seven base reliability models each for 2030 and 2040. The future assumes 85% of utilities’ carbon-cutting plans are met and carbon is reduced 40% from 2005 levels by 2040. MISO currently operates at a 22% carbon reduction from 2005 levels.
“If you think about it, there are over 100 models we could build and we could spend months and months building models and never get to the analysis,” he said. “That’s not to say we won’t build more models. In fact, I expect we will build more models. But we needed something to begin analysis with. … These 14 models certainly won’t be the end-all.”
Miland said Future I modeling simply kicks off work that will take place in 2021. He emphasized that the long-term planning will take place over several transmission cycles and said that MISO will also likely build seven models apiece for the more aggressive Futures II and III.
“This a long-term plan to see how we’re going to stay ahead of the game for the next 40 years,” Miland said. “We do anticipate that at end of this year, we may have some projects with ripe business cases that we can bring forward for board approval.”
While MISO focuses on model builds, the Organization of MISO States is concentrating on how the long-range projects’ cost might be shared in the footprint.
The OMS convened a special cost-allocation committee late last year to draw up principles on how MISO should approach long-term projects’ cost sharing.
Up until approval, OMS members were wrestling over whether states with more aggressive clean-energy policies should bear a greater share of the costs for transmission that enables renewable energy.
Some commission staff pointed out that several states with renewable portfolio standards have already exceeded their targets. Others said it remains to be seen whether MISO will consider public policy requirements as a benefit metric. The staffers also debated whether some transmission costs should be allocated on a postage stamp basis and whether some long-term transmission projects should be packaged into portfolios.
MISO has said projects will likely face approval independently in annual timelines, rather than being approved en masse in a portfolio.
Speaking at an OMS cost-allocation principles meeting Jan. 11, Minnesota Public Utilities Commissioner Matt Schuerger said bundling transmission projects that have “synergies” can sometimes make sense. He said it’s not as if planners would lump together transmission projects “from opposite ends of the footprint.”
But New Orleans City Council attorney David Shaffer said each transmission project should be able to stand on its own under scrutiny.
LS Power subsidiary Ravenswood Generating, which runs the largest power plant in New York City, announced on Thursday that it will change its name to Rise Light & Power and expand to develop large-scale clean energy projects.
The company will continue to operate the 2,480-MW Ravenswood Generating Station, the steam energy power plant in service since 1963 on the East River waterfront in Queens. The plant represents over 20% of installed capacity in NYISO’s Zone J.
The company’s first new large-scale project is the Catskills Renewable Connector, a 1,200-MW submarine and underground transmission line to connect its site in New York City with Greene County on the western side of the Hudson River and just south of the capital region.
“We’ll be able to unlock shut-in wind and solar across upstate that previously hasn’t been able to reach customers in New York City,” Rise Light & Power CEO Clint Plummer told RTO Insider. “Obviously it’s got to be done in locations where there’s community support for development, and we think there’s a lot of that.”
The state the previous day issued a solicitation for transmission projects to bring renewable energy from upstate and Canada to New York City as part of Tier 4 of its Clean Energy Standard, with planners hoping the transmission “arteries” will feed a 250-mile, $2 billion green “superhighway” project. (See “Other Projects,” NY Awards 2.5-GW Offshore Deal to Equinor.)
The company has filed a NYISO interconnection request (No. 1120) but has not yet committed to a path for financing and regulatory approval of its new transmission line.
Roads to Reality
“We think there are a number of different ways we could get the revenue support that we need,” Plummer said.
New York has quickened its permitting processes for both renewable siting and so-called priority transmission projects. Does Plummer think the company can get this new project under construction faster than the 10 years typically needed?
“Possibly, and I say possibly because some transmission lines have taken a long time, others take less time,” he said. “For any type of big infrastructure project, it needs to be planned in close coordination with the communities, and we need to be engaging and listening to the thoughts and concerns of those communities and developing routes that work best for them. New York has a very efficient process for evaluating and granting permits to large-scale transmission projects under Article VII, [the state law governing project siting], but that same process also allows for a great deal of stakeholder input, and that’s a good thing.”
The company also has potential to redevelop Ravenswood’s 28-acre site without adversely affecting the existing generation, Plummer said. Since acquiring the plant in 2017, LS Power has invested more than $160 million in modernization and resiliency upgrades for the facilities and removed more than 300 MW of fossil-fired peakers from service.
The state’s Public Service Commission in 2019 approved construction of a 316-MW battery storage facility in three phases on the site. The first phase was scheduled to come online this year, but the company on Tuesday filed a request to extend the Phase I completion date from April 2021 to June 2024 (19-E-0122). (See “Largest Storage Project in New York,” NYPSC Projects Lower Winter Energy Prices.)
The PSC on Sept. 17 modified dynamic load management implementation plans for the state’s six investor-owned utilities, all related to storage, saying the initial plans “resulted in a bias towards short-term, low-capital investment solutions” because of their yearly performance structure (18-E-0130). (See NY Utilities, Developers Tweak Storage Procurement Terms.)
The commission’s December 2018 storage order required Consolidated Edison to procure at least 300 MW of storage capacity and each of the other utilities to procure at least 10 MW each, with assets to be operational by Dec. 31, 2022, on contracts up to seven years.
“While LS Power has an impressive track record developing merchant energy storage in California, the New York market does not currently support that kind of development, so the economic viability of this storage project depends upon us obtaining a contract with a customer like Con Edison or NYSERDA,” Plummer said. “We participated in Con Edison’s 2019 solicitation, and at the end of this past year we found out that we lost.”
Con Edison will run another solicitation in 2021 and Plummer said his company looks forward to participating and hopes to win.
Plummer served on the planning team at Deepwater Wind that developed the Block Island offshore wind farm and takes hope from that experience.
“We proposed the project in 2008, and it took us until 2016 until it was built, and of that eight-year period, six of it was getting all the permits, approvals and public support in place,” he said.
NYISO on Tuesday proposed updating its buyer-side mitigation (BSM) processes in order to compensate for the growing disconnect between the original design, intended to cover a few new resources in any given class year, and the up to 50 such resources to be evaluated currently.
The ISO’s BSM rules are designed to prevent uneconomic entry of subsidized resources into its markets. It expects the number of resources needing to be studied under the rules to increase by five to 10 times the historical norm, while the two-year period formerly allowed for these evaluations has halved, Shaun Johnson, director of market mitigation and analysis, told the Installed Capacity Working Group (ICAPWG).
“We’re adding several other BSM evaluations, which could result in at least four to six BSM studies per year, certainly for 2021,” Johnson said. “We’re in the process of wrapping up the studies for Class Year 19, hopefully very soon. … So, just in the next six months, we could be looking at an additional four to six studies.”
The 2-MW Lewis County Solar Project in Lowville, N.Y. NYISO is seeing a surge of renewables seeking to interconnect, potentially overwhelming its BSM study processes. | Lewis County, N.Y.
Until recently, staff usually performed the BSM process on about five resources over the course of a class year. CY17 had about seven resources evaluated for BSM, Johnson said. CY19 had more than 50 resources at the start of the study.
“The current processes were not designed to be able to be administered effectively under this expected work load,” Johnson said.
Input Assumptions
“This initiative will not discuss new BSM designs or exemptions to BSM; there is a separate process underway with the ISO, the Comprehensive Mitigation Review,” Johnson said. “We’re all really uncomfortable right now about the risks that the BSM process in particular can add to the delays of the class year timeline.”
Those delays could stem from determining the assumptions that go into energy and capacity price forecasts, which determine whether new market entrants are subject to certain exemptions. Part A exempts a new resource from BSM if the forecast of capacity prices in its first year of operation is higher than the default offer floor. Part B permits exemptions if the forecast of capacity prices in the first three years is higher than the resource’s net cost of new entry.
“When you have four or five resources that you’re looking at, you can iterate and say, ‘if this one’s out, this is the effect it’s going to have’” on prices. “But when you have 30, 40, 50 resources, you just can’t iterate like that,” Johnson said. “The time it would take to do that is inconceivable, particularly when we get down to the [installed reserve margin] and [locational capacity requirement] values.”
NYISO wants stakeholders to consider the timing and lockdown of input assumptions, such as whether it should allow for discussion of the inputs with stakeholders, or post rough assumptions well in advance, Johnson said.
One stakeholder urged the ISO to balance the need for market fairness with the desire for administrative efficiency, urging staff not to avoid extra calculations if they are needed.
The 340-MW Alle-Catt Wind Farm is being built near this Amish family farm south of Buffalo. | Joed Viera
Tariff Clarity
NYISO also wants to add language to clarify how the limit on exemptions for renewables is calculated, as the tariff often can be unclear, Johnson said. The ISO had wanted to limit renewable exemptions in a class year to 1,000 MW of installed capacity, but FERC rejected that. It later accepted a proposal to use an unforced capacity reserve margin impact component in the renewable exemption limit formula. (See NYISO BSM Mitigation Ruling Sparks Glick Rebuke.)
“This was the first time we applied the renewable exemption limit that we just filed and got approved … and we realized as we’re administering the provisions that were written that some of them we didn’t write well,” Johnson said. “Others are not consistent with what we presented to stakeholders; they are consistent with what we described in the filing, but we do want to circle back on those components and discuss with stakeholders whether we want to update and clarify this or not.”
The ISO also wants to revise language addressing the inclusion of units, supply stack inclusion rules and inflation rate terminology, he said.
NYISO is requesting feedback by Jan. 27 in order for stakeholder comments to be included in any specific enhancement proposals Johnson plans to make, ideally, at the Feb. 9 and Feb. 25 ICAPWG meetings.
Regardless of changes in the composition of FERC under the incoming Biden administration, the next steps are to develop a proposal in time for the Business Issues and Management Committees to consider at their April meetings, Johnson said.
NERC on Thursday opened a third formal comment period on the standard authorization request (SAR) for Project 2019-04 (Modifications to reliability standard PRC-005-6) following revisions by the drafting team aimed at addressing criticism received during the second round that closed in July.
Many respondents had indicated surprise at the proposed changes to PRC-005-6, which requires utilities to “document and implement programs for the maintenance of all protection systems, automatic reclosing and sudden pressure relaying affecting the reliability of the bulk electric system.”
Objectors included the North American Generator Forum (NAGF), which submitted the original SAR in May 2019 with the goal of clarifying the standard’s applicability to automatic voltage regulators (AVRs). (See AVR Standards Team Faces Industry Pushback.) In a comment endorsed by several other participants, the organization said the proposal had “evolved into a draft that the NAGF can no longer support” and requested that the drafting team “revert back to the original SAR as previously submitted.”
Automatic voltage regulator
Team Tries to Calm Overreach Fears
According to NERC’s unofficial comment form, stakeholders are asked to respond to the following questions:
Does NERC’s current definition of “protection system” create confusion with regards to protective functions embedded in control systems, as it omits protective functions in the excitation and other control systems?
Should BES protective functions that respond to electrical quantities inside excitation systems be included in PRC-005, along with BES protective functions inside other control systems?
Should PRC-005 provide for the use of alternative protection system station DC supply technologies, whether battery-based or not, and ensure that they are subject to maintenance requirements?
Should entities registered as under-frequency load shedding-only distribution providers be considered as functional entities applicable to PRC-005?
Are there any logistical or cost considerations that would add significant burden to equipment owners trying to confirm protective functions in an exciter, inverter or other control system, and are there more cost-effective solutions that the drafting team could consider?
These questions are largely identical to those in the last round, with the exception of the third, which substitutes “alternative” for “emerging.” However, the new draft SAR incorporates changes outlined by the drafting team in a previously published response to the industry objections.
Most of the criticism that the second draft received focused on respondents’ perception that it represented an unwarranted expansions of the project’s goals, particularly in its attempt to apply PRC-005 to control systems. As a result, the drafting team devoted a significant portion of its response to explaining why it believes such changes are needed and do not constitute overreach.
“The SAR drafting team does not intend to state that non-BES protective functions, such as those detecting malfunctions of the excitation system, are within the scope of PRC-005,” the team said in its comment on the definition of “protection system,” emphasizing that the expanded definition is meant to clarify that AVRs are included.
Similarly, the team’s approach to the second question focuses on the lack of clarity regarding BES protective functions in the current version of PRC-005. The drafting team was concerned that “only addressing traditional synchronous generator excitation systems was not fully addressing the potential reliability gaps in the interpretations of PRC-005 applicability to protective functions in all control systems.”
In response to industry objections, however, the draft SAR has been updated to emphasize that the standard will be applicable only to BES protective functions, meaning that protective functions inside excitation and control systems that do not “perform as a BES protection system” would not be included. The team also promised that industry comments will be forwarded to the future standard drafting team once the SAR is approved.
Other changes include clarifying that battery energy storage systems are not being considered for inclusion in PRC-005, and that the SAR’s mention of battery technologies is because DC supply technologies, whether they include batteries or not, are not currently included in the standard’s maintenance requirements. This came in response to a comment from Edison Electric Institute that said it was “unclear” whether the current standard already addressed such equipment.
Comments on the revised draft SAR are due by 8 p.m. Feb. 12.
Washington state senators this week introduced a bill to establish a cap-and-trade program that would gradually limit the state’s greenhouse gas emissions while funding decarbonization efforts.
Sponsored by Sen. Reuven Carlyle (D), the Climate Commitment Act (Senate Bill 5126) would implement the vision outlined by Gov. Jay Inslee last month to cap statewide GHG emissions and direct state spending into clean energy resources, transportation electrification, building retrofits and climate resilience programs.
Under SB 5126, any climate-related investments would be subject to review by a newly created Environmental Justice and Equity Advisory Panel. The bill would also allocate cap-and-trade revenues to partially fund Washington’s Working Families Tax Credit, the state’s version of the federal earned income tax credit.
“As our state begins to break out of the grip of the pandemic, I believe courageous climate action that invests in clean energy jobs, embeds equity at every level and reduces emissions to Paris Accord levels is central to rebuilding our quality of life,” Carlyle said last month when the governor released his plan.
The bill would also grant the Washington Department of Ecology the authority needed to adopt emissions standards to help the state meet GHG limits and implement a climate program. Bill sponsors included the provision after the state Supreme Court last year found the department lacked the statutory authority to set standards that held producers and distributors of fossil fuels accountable for their indirect emissions.
The cap-and-trade program is designed to put teeth into the GHG reduction targets the legislature upgraded last year without enacting any supporting legislation (RCW 70A.45.020). Those targets require the state to reduce GHGs to 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050.
Washington’s proposed cap-and-trade program is expected to sharply accelerate reduction of the state’s carbon emissions leading up to its 2050 goal. | Washington State Governor’s Office
“The greenhouse gas emissions limits established in RCW 70A.45.020 are not merely aspirational. Rather, they are intended to guide the implementation of all other state laws and policies that have an impact on greenhouse gas emissions in the state,” the bill says.
Cap-and-trade would cover any entity within the state responsible for emitting at least 25,000 metric tons of GHGs annually, including electricity generators, importers and utilities; industrial facilities; and natural gas and other fossil fuel suppliers. Other entities can opt to participate in the program on a voluntary basis.
Potential Linkage
Central to SB 5126 is the development of carbon allowance auctions overseen by the Department of Ecology but managed by an independent contractor.
Auctions would be held no more than four times each year. The bill directs the department to design the auctions to allow — “to the maximum extent possible” — integration with other GHG trading programs, such as the Western Climate Initiative, which includes California and the Canadian province of Quebec.
“The department may conduct auctions jointly with other jurisdictions with which it has a linkage agreement,” the bill states.
The bill calls for the cap-and-trade program compliance obligations to begin Jan. 1, 2023, with the first compliance period running through the end of 2026. The Ecology Department would need to adopt a budget of allowances for the first compliance period by Oct. 1, 2022. Emissions data reported to the department for 2017 through 2021 would be “deemed sufficient” for adopting annual emissions budgets and demonstrating compliance, according to the bill.
To minimize the impact of cap-and-trade costs on electricity customers, the program would allocate free allowances to consumer- and investor-owned utilities for the first compliance period starting in January 2023. Any allowances allocated at no cost would be consigned to the next auction with proceeds rebated back to ratepayers. Before the second compliance period commences in the January 2027, the department would need to adopt rules for allocating no-cost allowances to only consumer-owned utilities with an approved clean energy implementation plan.
Natural gas utilities would be allocated free allowances for the first compliance period in amounts proportional to their provision of service to low-income customers, measured by the number of customers who receive bill or rate assistance from the utility. Those allowances would be consigned to the auction for the benefit of low-income customers.
The bill also calls for free allocations during the first compliance period for “emissions-intensive, trade-exposed” industries. The category covers a wide swathe of sectors, such as primary and secondary metal manufacturing, paper manufacturing, aerospace, wood products, mineral manufacturing, chemical producers, computers and electronics, food production and cement.
Industrial users would be allocated 90% of their compliance obligation for the 2023, declining by 5 percentage points each year through 2026.
“By Jan. 1, 2024, the department must adopt by rule objective criteria for both emissions’ intensity and trade exposure for the purpose of identifying emissions-intensive, trade-exposed manufacturing businesses during the second compliance period of the program and subsequent compliance periods,” the bill says.
Funding Source
The bill would also require the department to complete an evaluation of the program’s performance in reducing GHGs statewide and criteria pollutants in overburdened communities by the end of 2035. It would allow the department to adjust emissions budgets if the evaluation shows the program is coming up short of meeting the 2040 goal.
Auction revenues would be deposited into a climate investment account created in the state treasury. Funds could be spent on clean transportation programs; programs to improve the climate resilience of the state’s waters, forests and vital ecosystems; clean energy transition programs that assist affected workers and low-income individuals; and emission-reduction programs.
“Projects or activities funded from the account must meet high labor standards, including family-sustaining wages, providing benefits including health care and pensions, career development opportunities, and maximize access to economic benefits from such projects for local workers and diverse businesses,” the bill says.
The bill would require the governor’s office to convene a climate commitment task force consisting of state agencies, other governments and stakeholders by July 1. The task force would be charged with hammering out the details of the legislation and preparing for rollout of the program.
CAISO and its sister state agencies released a final, more detailed analysis Wednesday of the mid-August blackouts and steps they are taking to prevent capacity shortfalls this summer and beyond.
“We recognize our shared responsibility for the power outages many Californians unnecessarily endured,” stated a cover letter to Gov. Gavin Newsom signed jointly by the heads of CAISO, the California Public Utilities Commission and the state’s Energy Commission. “The findings of the final analysis underscore this shared responsibility and give greater definition to actions that can be taken to avoid or minimize the impacts to those we serve.”
Blackouts on Aug.14-15 occurred around 6:30 p.m. as solar ramped down. | CAISO
Requested by Newsom, the report incorporates data that was not yet available during the preparation of a preliminary root-cause analysis issued in October. (See CAISO Says Constrained Tx Contributed to Blackouts.)
The final report mainly confirms the preliminary conclusion that the rolling blackouts CAISO ordered Aug. 14-15 resulted from a combination of severe heat across the West, inadequate resource planning and market practices that undermined procurement. But it elaborates on those findings with more specific evidence and recommendations gleaned from months of investigation.
“This Final Root Cause Analysis provides important insights and lessons learned about the factors that contributed to the rotating power outages of last summer,” CAISO CEO Elliot Mainzer said in a statement. “As we prepare for summer 2021 and beyond, I look forward to working closely with the CPUC, CEC, policymakers and regional stakeholders to bring our planning, procurement and operational practices together into a modernized and well-integrated resource adequacy framework for California.”
CAISO previously said that import bids in the day-ahead market were 40 to 50% higher during the energy emergencies of August than typical resource adequacy requirements at that time of year, but transmission constraints limited the transfers into CAISO’s footprint. A major transmission line from the Pacific Northwest had been derated because of the weather, the preliminary analysis reported.
The final analysis newly reported that the line in question had experienced a forced outage because of a storm in May 2020 that damaged the line and derated the California-Oregon Intertie (COI) into August.
“The derate reduced the CAISO’s transfer capability by nearly 650 MW and caused congestion on usual import transmission paths across the COI and Nevada-Oregon Border,” the final report said. “In other words, more energy was available in the north than could be physically delivered, and the total import level was less than the amount the CAISO typically receives.”
One of CAISO’s current efforts — part of its Resource Adequacy Enhancements stakeholder initiative — is a controversial proposal to contract for the highest level of firm transmission into CAISO from the Northwest, guaranteeing delivery of essential hydropower resources. (See CAISO Seeks ‘Firm’ Tx for Resource Adequacy.)
Another RA effort involves more accurately accounting for the capacity of intermittent resources such as wind and solar, which can be unpredictable.
Updated figures in the final report showed combined RA values for solar and wind fell by 1,300 MW Aug. 14-15. Solar generation was reduced because of high cloud cover and smoke from wildfires raging at the time. Wind generation dropped without warning by 1,200 MW on Aug. 15 caused by tropical storm influences from the south.
When wind plummeted during the so-called net peak, as solar waned and demand remained high in the early evening, CAISO was unable to maintain its safety reserves to prevent larger grid failure.
The report recommends that the state update it estimations of wind and solar capacity.
“The CPUC has improved the methods for estimating the reliability megawatt value of solar and wind over the years, but the reliability value of intermittent resources is still over-estimated during the net peak hour,” it said. “Improvements to the RA program should account for time-dependent capabilities of intermittent resources.”
| Ready.gov
More RA, Batteries
The report noted other efforts underway to avoid future shortfalls. They include an emergency reliability rulemaking by the CPUC to procure additional resources to meet demand this summer.
“Through this proceeding, the CPUC has already directed the state’s three large investor-owned utilities to seek contracts for additional supply-side capacity and has requested proposals for additional demand-side resources that can be available during the net demand peak period (i.e., the hours past the gross peak when solar production is very low or zero) for summer 2021 and summer 2022,” the report said.
CAISO is performing an analysis to increase the CPUC’s RA procurement targets.
“Based on the analysis to date, CAISO recommends that the targets apply to both the gross peak and the critical hour of the net demand peak period during the months of June through October 2021,” it said.
The ISO is expediting a stakeholder process to consider market rule changes by June to “ensure the CAISO’s market mechanisms accurately reflect the actual balance of supply and demand during stressed operating conditions.” (See Summer Readiness Sought by CAISO, CPUC.)
CAISO is also working to integrate hundreds of megawatts of battery storage into its grid by summer to store excess solar and wind power for use during the evening net peak. The CPUC said it is trying to remove regulatory obstacles to battery and generation resources coming online by this summer.
“The acceleration of climate change demands we enhance our planning efforts and market practices at a faster pace and with broader anticipation for what is possible,” CPUC President Marybel Batjer said in a statement. “It is our top priority to ensure we have the demand- and supply-side resources needed to maintain reliability, and this [final root-cause] analysis demonstrates how we will do it and continue to decarbonize the grid.”
New York on Wednesday announced that it is awarding 2,490 MW in offshore wind contracts to Equinor Wind US, the largest such procurement ever in the U.S.
Equinor and its partner, BP, will develop two separate projects: an additional 1,260 MW for the companies’ Empire Wind in the New York Bight, and the 1,230-MW Beacon Wind, to be located more than 60 miles east of Montauk. State officials had already selected the initial 816-MW phase for Empire Wind, and Beacon Wind could add up to 1,170 MW in the future.
“These projects will deliver homegrown, renewable electricity to New York and play a major role in the state’s ambitions of becoming a global offshore wind hub,” Equinor CEO Anders Opedal said in a statement.
The new contracts bring the state’s total OSW procurement to about 4.4 GW, nearly half the 9 GW targeted by 2035. Along with Empire Wind 1, New York in 2018 selected the 816-MW Sunrise Wind project and the 130-MW South Fork Wind Farm.
Empire Wind is located 15 to 30 miles southeast of Long Island and spans 80,000 acres, with water depths between 65 and 131 feet. The lease was acquired in 2017 and is being developed in two phases (Empire Wind 1 and 2) with a total installed capacity of more than 2 GW (816 and 1,260 MW). | BOEM
The terms for the latest deals have not been announced, but officials estimate the projects will bring $8.9 billion in investment and create more than 5,200 jobs, an economic stimulus sweetened by commitments from companies to manufacture wind turbine components in New York. For example, the country’s first OSW tower-manufacturing plant will be built at the Port of Albany; a turbine-staging facility and operations and maintenance hub will be set up at the South Brooklyn Marine Terminal; and other support activities will take place at the ports of Coeymans, Jefferson and Montauk Harbor in Long Island.
Other Projects
New York also made several other announcements related to renewable and clean energy as part of the third segment of Gov. Andrew Cuomo’s State of the State address, which began Monday. (See Cuomo Outlines Green Path for New York in 2021.)
The state issued a solicitation for transmission projects to bring renewable energy from upstate and Canada to New York City as part of Tier 4 of its Clean Energy Standard. The state is hoping these transmission “arteries” will feed a 250-mile, $2 billion green “superhighway” project
“Supercharging the new transmission superhighway will be vital to completing New York’s nation-leading green economic recovery and accelerating renewable energy development programs,” it said.
New York Gov. Andrew Cuomo delivers the energy portion of his State of the State address on Jan. 13. | New York DPS
Transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected without coordinated planning, OSW Growth to Test New York’s Transmission Grid.)
In addition, the state announced it will this year contract for 23 solar farms and one hydroelectric facility worth more than 2,200 MW.
It is also investing $20 million in a new OSW Training Institute based at the State University of New York at Stony Brook and Farmingdale State College to train at least 2,500 people for jobs in renewable energy. New York State Energy Research and Development Authority and SUNY issued the first solicitation for advanced technology training partners to train the first group of workers beginning this summer.
Anne Reynolds, executive director of the Alliance for Clean Energy New York, lauded the news but said, “There is some unfinished business in helping renewables get built, and that is providing some guidance to towns on how to properly value and tax wind and solar projects. ACE NY is calling on the governor and legislature to devise a pathway to standardized taxation for renewable energy.”
“The governor’s focus on transmission upgrades will ensure that the clean power generated by offshore wind projects is brought to the grid in an efficient and cost-effective manner,” Joseph Martens, director of the New York Offshore Wind Alliance, said in a statement.
Regulators hailing from SPP’s and MISO’s footprint would like to see the grid operators improve seams relations by resolving rate pancaking and adding a smaller interregional project category.
The MISO-SPP Seams Liaison Committee (SLC), comprised of regulators from the Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC), agreed this week that the RTOs would best be served by addressing multiple transmission charges at their seam and creating a class of smaller cross-border projects similar to the Targeted Market Efficiency Projects (TMEPs) used by MISO and PJM.
The two items top the regulators’ draft list of seams recommendations. The regulators also designated current interconnection queue processes and interregional transmission planning efforts as medium priority.
The SLC relegated market-to-market improvements, developing an interface pricing process, and coordinated transaction scheduling to low priority status.
Texas Public Utility Commission Chair DeAnn Walker will share the draft list of recommendations with the RSC when it next meets on Jan. 25. She cautioned her fellow regulators that the draft document “could come out of the RSC looking much different,” as the committee has not been as involved as the OMS the last few months.
“I would like to get more concrete direction from the RSC as a whole,” she said during the committee’s call on Tuesday. “Maybe [RSC’s members] will provide a little bit more insight and clarity on this.”
“I would prefer Chairman Walker go to our RSC first,” RSC’s newly elected president Kristie Fiegen said. “We haven’t been able to discuss anything because we haven’t had a publicly noticed meeting [lately].”
Walker acknowledged that MISO and SPP are already working to address many of the topics, giving partial credit to the SLC. “We’ve done a lot in getting MISO and SPP to work together where there was probably a little bit of a roadblock before,” she said.
The SPP-MISO seam | Organization of MISO States
Missouri Public Service Commissioner Ryan Silvey said that while the OMS and RSC have agreed on the majority of the recommendations, differences on issue prioritization are because the RTOs already have plans in place to make improvements.
Walker said tackling transmission rate pancaking between MISO and SPP is the most “controversial” recommendation because it would require significant member agreement and stakeholder votes to come to a solution.
“I think there are a lot of members who would like to see this move forward, but there are just as many who wouldn’t,” she said. A pancaking solution could potentially result in “years of drawn-out litigation,” she said, noting multiple Texas utilities have litigious histories.
“I don’t see them being docile,” Walker warned.
The SLC may put together a working group to address rate pancaking between MISO and SPP.
“What I hope this will turn into is a negotiation that turns into an agreement first with the [transmission owners] and spreads to other members,” Arkansas Public Service Commission Chairman Ted Thomas said late last year.
OMS and RSC also recommended the grid operators use the TMEPs study category, which MISO and PJM use to identify smaller transmission projects that ease historical congestion along the seams.
Last year, regulators appeared split over whether MISO and SPP should embark on their own TMEP process. Some MISO South regulators have maintained that the seam isn’t mature enough to benefit from congestion-relieving TMEPs.
Others said a similar process — not an exact replica — could work.
“I don’t know that we need to get tangled up in exactly the same specific study process, but that we have one that accomplishes the same study objectives,” North Dakota Commissioner Julie Fedorchak said last year.
MISO and SPP have never approved a major interregional transmission project. Some in the MISO stakeholder community have suggested TMEPs as a route to alleviate some cross-border congestion.
Having finalized its recommendations, the committee may now transition to a monitoring role on MISO-SPP seams issues and hold less frequent meetings. Commissioners noted that the OMS is advisory in nature while the RSC has specific oversight bylaws. Some said the difference could limit how the committee issues guidance going forward.
Last fall, governors from five of the six New England states — Connecticut, Maine, Massachusetts, Rhode Island and Vermont — jointly released a pointed statement that said ISO-NE was frustrating regional and state-specific efforts to reduce economy-wide greenhouse gas emissions. It also called for reforms to the RTO’s market designs, transmission planning and governance.
An eight-page critique circulated by the New England States Committee on Electricity (NESCOE) soon thereafter detailed and expanded on the governors’ call for reformative action. The vision statement also referred to a series of online public technical conferences to convene, which would seek “presentations and proposals … and solicit comments and dialogue with all interested stakeholders.”
The first of those forums is Wednesday and will focus on wholesale market design. Two of the presentations from “interested stakeholders” are representatives from ISO-NE and NEPOOL, indicating a collaborative process from the start.
Interested Parties
NEPOOL Participants Committee Chair David Cavanaugh signaled an early interest in participating in the technical forums in December.
Cavanaugh, senior vice president of regulatory and market affairs at Energy New England, said New England has been struggling “with the tension of integrating state policy resources.”
“If 2021 was to have a success statement, it would be to find the appropriate pathways that balance investment, as well as state policy resources and achieving state goals, because you have to have a balance,” Cavanaugh said. “You still want to have the signals to draw merchant investment in the region because you need it, but you also need the ability to represent and respect state policy, so if ’21 could deliver anything, it’d be identifying a pathway that’s successful in achieving that goal.”
Flash forward, and Cavanaugh will be charged with educating the public on the NEPOOL stakeholder process and its sectors, in addition to a high-level overview of existing initiatives, discussion of the Future Grid Initiative and answering audience questions.
“Given NEPOOL’s critical role in the region as the FERC-approved stakeholder forum for consideration of any and all changes to the design and operation of New England’s wholesale electricity markets, it is important for NEPOOL to engage in discussions that may help to inform ongoing or future NEPOOL stakeholder processes,” Cavanaugh told RTO Insider.
Cavanaugh noted the Future Grid Initiative will “explore and evaluate potential market frameworks that could be pursued to help support New England’s clean energy transition.”
“These processes provide the forum for NEPOOL participants, state officials and representatives, and ISO-NE to find common understanding among a diverse set of interests on potential pathways forward, and to support the region’s efforts to find consensus, where possible,” Cavanaugh said. “I am hopeful that the states’ technical conferences will help to complement and further collaborative efforts around the NEPOOL stakeholder table.”
ISO-NE headquarters in Holyoke, Mass. | ISO-NE
Cavanaugh, a 35-year energy industry veteran who has also worked at ISO-NE, NRG Energy and Eversource Energy, said the technical forums “present an opportunity for regional stakeholders to better understand the individual and/or collective views of the New England states on the issues identified” by the governors and NESCOE.
For ISO-NE, Eric Johnson, the RTO’s director of external affairs, will provide an organizational overview, discuss resource adequacy and talk through the development and administration of competitive electricity markets.
In an email to RTO Insider, Janine Saunders, corporate communications manager for the RTO, said that building “a cleaner electricity system is an important step in confronting climate change and is a vision we share with our state leaders.”
“Collaboration with our New England stakeholders has already resulted in one of the cleanest, most efficient fleets of power generating resources in the U.S.,” Saunders added. “We look forward to continuing our work with the states and others to keep building on that solid foundation.”
State Thoughts
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said one of the goals in launching the technical forums is to ensure that anyone who has an interest and wants information on “the future of our shared regional electric grid can access it and be part of the conversation.” Public forums bring “new people into the discussion,” she said.
Dykes has not been shy about criticizing ISO-NE, especially on carbon pricing, but she recognizes that before any potential reforms, it is important to understand the perspectives of the RTO and NEPOOL and the shared history of the organizations.
“Institutions that have facilitated regional cooperation or operation of the grid and investment in the grid have evolved over time,” Dykes said. “It’s important for us to really start with that history and that understanding of how the grid, and the governance processes in organizations associated with it, have evolved to be able to set our intention of how we want our markets, transmission and the governance to be structured in the future.”
All parties involved “have a lot of work to do,” according to Dykes. The forums present an opportunity for states to provide primers on the laws, policies and perspectives that drive energy policy; modeling related to carbon-reduction goals; and mandates that are “at the forefront of why we feel that a real transformation of our electric supply in our grid is necessary.” It is also a chance to highlight a commitment to regional cooperation and “utilizing competitive markets to achieve the most affordable, clean electric supply that we can,” she said.
“I think it’s important for us to start off with an understanding of how our regional grid has evolved … in order to take the conversation further and look at how we can harness competitive markets and regional cooperation to achieve a transformation or rapid decarbonization of our electric grid,” Dykes said.
On Jan. 25, there will be another forum on the design of wholesale markets. Additional forums on transmission planning and governance reform of ISO-NE are slated for February. Following the forums, state representatives will report to their respective governors any findings and recommendations for action.
