Page 982 – RTO Insider

February 14, 2021

MISO Fostering Alternatives to MTEP Projects

MISO is seeking ways to modify its annual transmission plan and make it easier for stakeholders to suggest alternatives to transmission owners’ project proposals.

During a Planning Subcommittee meeting Feb. 9, the RTO tested a draft plan that would increase the amount of time stakeholders have to assess projects and draw up alternatives during the annual Transmission Expansion Plan (MTEP).

Expansion Planning Senior Manager Thompson Adu said stakeholders have complained that MISO only allows a few weeks in the MTEP planning cycle to “review models, evaluate mitigations and propose alternatives” to submitted projects.

The RTO currently accepts both MTEP project proposals and alternatives on Sept. 15. It is proposing to move the alternative projects’ deadline to May 31 of the following year, giving stakeholders an extra eight and a half months to develop alternative solutions. Staff would then analyze the alternative proposals June through September.

However, multiple stakeholders said that unless MISO standardizes the project information that TOs release, the expanded timeline won’t help. They said TOs don’t post the same datasets on projects, making it difficult to assess proposals and draw up alternatives.

“What we’re looking at here is not just a timeline issue, but also an information issue,” Alliant Energy’s Mitch Myhre said.

Adu said the proposal was only a “conversation starter” and that MISO is accepting more ideas to encourage more meaningful transmission alternatives.

The grid operator has reported it’s overseeing 1,255 active MTEP projects totaling $13.6 billion. Of those, 118 projects, worth $2.3 billion, are under construction. Eleven projects were withdrawn during 2020’s final quarter.

Since the first MTEP package in 2003, approximately $26.5 billion worth of approved transmission projects have gone into service, according to MISO.

Meanwhile, the RTO has developed its cost-estimation guide for 2021 MTEP economic projects. Substation engineer Alex Monn said the fourth iteration of the annual guide includes both upfront project costs and costs over time. He said that as new technologies are sized up as project alternatives, MISO should provide maintenance cost predictions. He said energy storage projects generally have larger costs over the first 20 years versus traditional wires projects.

MISO will collect stakeholder opinions on its cost-estimation guide through April.

February 14, 2021January 21, 2024

Bipartisan Agreement on Minnesota Climate Bills Unlikely

Minnesota has fallen far short of emission reductions established in 2007 by Republican Gov. Tim Pawlenty, but the chance for bipartisan agreement on a course correction appears slim, according to legislative leaders on both sides of the aisle.

Considered historic at the time, the bipartisan “Next Generation Energy Act” requires the state to cut overall greenhouse emissions by 30% by 2025 and 80% by 2050. But emissions have declined by just 8% from 2005 levels, the Minnesota Pollution Control Agency reported last month.

While the report applauded the state government’s move to more electric vehicles and the energy industry’s move away from coal-fired power plants in favor of carbon-free wind and solar, MPCA officials also said the state has made little progress in the areas of transportation and agriculture.

On Jan. 21, Gov. Tim Walz announced a four-part plan by the Democratic-Farmer-Labor party to accelerate the state’s efforts, including a requirement that the state’s electric utilities use only carbon-free resources by 2040.

It would also require that utilities prioritize energy efficiency and clean energy resources over fossil fuels when proposing to add new generation, allowing new fossil fuel resources only if necessary for reliability and affordability. Walz would also raise energy efficiency standards and set a state goal of cutting greenhouse gas emissions from existing buildings in half by 2035. “The time to fight climate change is now,” Walz said.

But State Senate Majority Leader Paul Gazelka (R) said his current session priorities are substantially scaled back because of the coronavirus pandemic and an anticipated $1.3 billion budget shortfall.

“We knew that we were going to be in trouble [financially] this year,” Gazelka said in a January capitol report regarding session priorities. “And we’re not going to [balance the budget] by raising taxes.

He added that with limited floor action because of COVID protocols, he’s encouraged legislators in both the Senate and the House to “think about doing less.” His priorities this session focus on three key items: the budget, redistricting and dealing with pandemic issues.

“We’ve got to get our businesses open,” Gazelka said. “The rest can wait until next year.”

Despite the prospects of a divided legislature, DFL leaders have already pitched proposals with the hope that the Republican-controlled Senate might consider renewed goals for cutting emissions.

“This is an issue of our times, and it’s urgent that we deal with it,” Senate Minority Leader Susan Kent (DFL) said. While she said the state has made some headway on reducing emissions, transportation remains the number one concern, and a faster move to electric vehicles is a key to addressing it.

But Republicans prefer to stick with the targets set in the 2007 bill. The GOP’s relationship with Walz has been heading south for several months. The two sides have argued often and publicly about the governor’s use of emergency powers because of the pandemic. There have been several legislative attempts to curtail Walz’s emergency powers, but they have all been stopped by the DFL-controlled House of Representatives.

Gazelka said his party believes it is long past time to allow the Senate and the House to address the state’s economic issues, and that decisions “should not be given to one person for over a year.”

Republicans have also criticized the state’s vaccination rollout as being confusing and slow, and there has been a growing rural-urban split over how to fund economic recovery efforts for businesses impacted and destroyed in Minneapolis during the days following the death of George Floyd on May 25.

Despite a slim Senate margin, Republicans believe they have somewhat of a mandate judging from the November elections which saw their party gain five seats in the House, primarily in rural Minnesota. While the DFL still holds a 70-64 edge in the House, Republicans hold a 34-31-2 advantage in the Senate.

Two former DFL members, Rep. David Tomassoni (I) and former House Majority Leader, Rep. Tom Bakk (I), have left the party and plan to caucus with Republicans.

A bill sponsored by Rep. Jamie Long (DFL) that would set benchmarks for meeting Walz’s 2040 goal was the first clean energy measure to get a hearing in the new legislative session. And on Jan. 29, Long’s Capital Investment Committee held a joint hearing on Long’s bill with the Climate and Energy Committee chaired by fellow Minneapolis Rep. Fue Lee (DFL).

“As one of the fastest warming states in the nation, Minnesota needs strong, resilient infrastructure to withstand the impacts of climate change,” Long said in a press release. “Investing in sustainable infrastructure will create new jobs and help our communities adapt and thrive as the climate continues changing.”

Sen. Nick Frentz (DFL), who is sponsoring Long’s proposal in the Senate, isn’t quite as optimistic at winning support for the measure in the GOP-controlled upper house.

Sen. Dave Senjem (R), chair of the Energy and Utilities Finance and Policy Committee, plans to reintroduce the “Clean Energy First” proposal he authored in 2020. The bill would direct the Minnesota Public Utilities Commission to prioritize use of sources such as nuclear, solar, wind, hydropower, carbon sequestration and municipal solid waste in utility requests for additional generation. The PUC would be required to determine if the energy is adequately reliable and affordable for ratepayers.

The state’s two largest utilities, Xcel Energy and Allete’s Duluth-based Minnesota Power, have pledged to produce energy without carbon emissions by 2050, focusing on wind and solar options. Minnesota Power also plans to eliminate coal-powered generation by 2035.

In December, Minnesota Power announced it had become the first state utility to provide 50% renewable energy in its system, which serves 145,000 residential and commercial customers across northern Minnesota. Land O’ Lakes, through its sustainability affiliate Truterra, launched a carbon exchange program Feb. 4 to pay Minnesota farmers for increasing carbon storage in the soil. Companies that want to reduce their GHG emissions could buy credits to help offset the impact of climate change, according to Land O’ Lakes, a farmer-owned cooperative.

Microsoft became the program’s first customer, announcing it will pay $20/ton for carbon sequestered in the soil by sustainable farming practices.

February 14, 2021

MISO TOs’ Self-funding Option Tested Again

Two FERC commissioners still have heartburn over a 2018 commission order reinstating MISO transmission owners’ rights to self-fund network upgrades.

Chairman Richard Glick and Commissioner Allison Clements expressed their concerns in a Feb. 8 order following MISO’s submittal of an unexecuted facilities service agreement (FSA) between itself, interconnection customer Walleye Wind and transmission owner Northern States Power Co. While FERC approved the unexecuted FSA for a 111-MW Minnesota wind farm, it opened old wounds over the appropriateness of TOs’ unilateral right to self-fund network upgrades (ER21-615).

Walleye Wind, a NextEra Energy Resources subsidiary, said it refused to execute the FSA and requested MISO file an unexecuted document because of “continued legal uncertainty regarding” TOs’ right to provide initial funding for the network upgrade that would accommodate the project.

MISO Transmission Owners — | *NextEra Energy*

Walleye said FERC could reverse its decision in the future, placing initial funding responsibility back on interconnection customers.

The company asked FERC to direct MISO to amend the FSA by including a provision for the possible reversal of TOs’ self-funding option. It asked that the FSA state that “changes will be undone if the legal premise for [transmission owner initial funding] is later eliminated.”

FERC declined to amend the FSA to incorporate such language, saying the document correctly reflects the state of MISO’s rules at the time.

Glick concurred with the FSA decision but wrote separately that giving TOs the option to “unilaterally choose whether to self-fund network upgrades constructed on behalf of affiliated and nonaffiliated interconnection customers” could be unfair. He said the commission “failed to meaningfully wrestle with these concerns in its orders allowing transmission owners the unilateral right to choose up-front funding.”

Clements said that while she concurred with the decision, she is worried that FERC didn’t “adequately address the justifiable concern that those rules create an opportunity for generation-owning transmission owners to unduly discriminate” between assets they have an ownership interest in and those they don’t have an interest in.

She said that when interconnection customers have control of initial funding, they can finance at more favorable rates instead of reimbursing TOs for construction and a predetermined rate of return. She also said TOs’ unilateral right to self-fund ignores that the “vast majority of transmission owners do in fact still own generation.”

The commission should conduct a “more searching inquiry” of the issue, she said.

“While this topic has been the subject of litigation before this commission and the courts for several years, I believe we have more work to do,” Clements wrote. “A foundational principle of the commission’s work to open up access to the nation’s transmission grid over the past 25 years has been that when monopoly utilities are permitted to discriminate among affiliated and nonaffiliated customers, competition suffers and customers pay.”

She said that while the reasonableness of MISO interconnection rules was not the item in question, “they may well merit additional scrutiny in the near future.”

MISO in 2018 acted on FERC’s direction and reinstated TOs’ right to self-fund network upgrades necessary for new generation. FERC originally issued a 2015 order barring TOs from electing to provide initial funding for network upgrades, but that decision was remanded by the D.C. Circuit Court of Appeals. (See MISO Gauging Aftershocks of TO Self-fund Order.)

The move was unpopular with some MISO generation developers, who said it could pave the way for discrimination by TOs of some interconnection customers and increase the cost of new generation. But TOs’ ability to self-fund network upgrades survived a challenge last year from the American Wind Energy Association. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

February 14, 2021

Long-term Tx Plan Edges Out MISO GI Coordination

MISO last week said it bit off more than it could chew by simultaneously mounting a long-term transmission package while trying to merge interconnection upgrades with annual transmission planning.

Staff announced Wednesday during a Planning Advisory Committee (PAC) teleconference that it will table the effort to analyze network upgrades stemming from interconnection requests for economic benefits and possible cost-sharing. They said MISO would wait until the end of the year and see how the long-term transmission plan develops.

“We received feedback from stakeholders last month that it’s probably better to wait until more information of the long-range transmission plan comes at the end of the year,” Senior Manager of Economic Planning Neil Shah said. “Let’s put this issue on hold, and we will continue to monitor the progress of the long-range plan.”

Stakeholders, particularly those belonging to the environmental sector, seemed fine with the breather.

“It did seem like it was appropriate to pause work on this since there are so many moving parts that could affect [it],” Clean Grid Alliance’s Natalie McIntire said. “I don’t want to lose this issue. It may be that it gets addressed somehow with long-range transmission and its allocation.”

Shah agreed that some long-term projects may ease network upgrade costs for interconnecting generators.

Stakeholders have warned MISO that system upgrade costs for interconnection hopefuls have been snowballing in recent years because of scant transmission planning, threatening a clean energy transition. (See “Coordinated Planning Effort Continues,” MISO Planning Advisory Comm. Briefs: Sept. 23, 2020.)

Before hitting pause on the network upgrade analysis, the RTO had proposed to conduct economic evaluations of interconnection upgrades with signed interconnection agreements rated at 230 kV or above and costing at least $50,000/MW. If the upgrades demonstrated the same 1.25:1 benefit-to-cost ratio required of market efficiency projects, they would have been included as economic projects in MISO’s annual Transmission Expansion Plan (MTEP).

The Long View

While interconnection upgrade coordination took a back seat, stakeholders at the PAC were left wondering how often they’ll be apprised of MISO’s long-term transmission planning.

They asked for monthly updates on the progress of MISO’s burgeoning long-term transmission plan, the first in a decade. (See MISO Begins Longterm Tx Modeling.) The February PAC meeting did not have an agenda item on the long-term plan.

Director of Planning Jeff Webb said MISO will begin delivering regular reports to stakeholders when it has “substantive materials.” He said so far, there is little to report.

“We can give updates, but they’ll probably be brief status updates,” Webb said, adding that the RTO plans to hold a discussion on long-term planning at the March PAC.

The grid operator is currently relying on the 20-year futures scenarios developed for MTEP 21.

Todd Hillman, MISO’s senior vice president and chief customer officer, said the RTO is first focusing on Future I, which most closely resembles member utilities’ collective plans. The future assumes an 85% likelihood that utilities meet their current decarbonization plans and full certainty that their stated generation retirements and additions come to pass. The scenario will likely translate into a 60% carbon reduction in MISO from 2005 levels.

“Future I was largely developed in talking with our members and stakeholders,” Hillman said during an informational forum in January.

MISO expects to have preliminary project solutions from its Future I modeling within the next few months. Staff is also beginning long-term modeling for the more aggressive Futures II and III. Webb said he thought that any transmission projects coming out of Future I would most likely be “baseline” and serve as a foundation for other needs found using the second and third futures.

WEC Energy Group’s Chris Plante said he wasn’t sure that MISO was predicting enough storage technology in its futures. He noted utilities are increasingly turning toward storage.

The Natural Resources Defense Council said late last month that the RTO has failed to prepare for a clean-energy future through sufficient transmission planning. The nonprofit said MISO’s recent transmission planning ignored the rapid pivot to clean resources and only anticipated “incremental clean energy development over the coming decade, rather than transformational clean energy development that is anticipated by 2035 and beyond.”

“In 2020, [MISO] ignored the demand for the regional transmission necessary to transition the Midwest into a clean energy hub. This year [it] can and should do better by building regional transmission,” the NRDC’s Toba Pearlman wrote in a blog post. She said the RTO’s inaction intensified its interconnection queue backlog.

NRDC reported that 278 storage, hybrid, wind and solar projects were withdrawn at “advanced stages” in the grid operator’s interconnection queue between 2016 and October 2020.

Senior Transmission Planning Engineer Andy Witmeier said the grid operator’s current transmission planning would be inefficient without a long-term package, and without it, “the resource shift contemplated by MISO stakeholders’ goals will be difficult to achieve.”

Speaking during a cost allocation working group teleconference on Thursday, Witmeier pointed to MISO’s newest instantaneous wind peak on Dec. 23, when 20.2 GW of wind generation served almost 27% of system load. He said even more wind power was available that day but was “trapped behind transmission congestion.”

“We have to make sure we enable the delivery of that extra generation,” he said. “With an additional 4,500 MW expected to come online in the next 12 months, it is increasingly important to see how the system is currently handling production of renewable resources and [preparing] for future growth.”

Cost Allocation Decisions Loom

MISO’s cost allocation group will eventually consider a benefit measurement and cost-sharing design for the long-range transmission plan.

Witmeier said the RTO’s current market efficiency project cost allocation won’t likely capture all long-term transmission benefits.

The Organization of MISO States convened a special cost-allocation committee late last year to draw up principles on how staff should approach long-term projects’ cost sharing. The resulting principles are broad, driving home that costs should be portioned out as precisely as possible to beneficiaries and cost-causers. OMS said generation and load — including regions with decarbonization goals — can be considered beneficiaries. It also suggested MISO use subregional allocations and bundle certain transmission projects’ costs when it makes sense.

MISO Executive Director of System Planning Aubrey Johnson acknowledged there’s not much appetite among stakeholders for a footprint-wide postage stamp rate for long-term transmission.

“That camp is very small. There’s not a high likelihood of success,” he said during an OMS meeting in January.

February 14, 2021January 15, 2025

Southeast Seeks FERC OK for Expanded Bilateral Market

Utilities and cooperatives in 11 Southeastern states on Friday proposed using automation and free transmission capacity to expand bilateral trading and allow 15-minute energy transactions.

Led by the Tennessee Valley Authority, Southern Co. and Duke Energy, the Southeast Energy Exchange Market (SEEM) seeks to reduce the “friction” in bilateral trading by using an algorithm to match buyers and sellers and eliminating transmission rate pancaking in the region’s 10 balancing authority areas.

Electric providers purchase cheaper power when they can back down more expensive generation in their own fleets; sellers earn profits to offset their operating costs.

To make a transaction currently “the parties must discover one another, negotiate the terms of the sale, arrange and pay for transmission service across all utilized transmission systems, and schedule the delivery of energy. All of this is done with ‘traditional’ methods of communication, by phone and electronically, thus creating transactional friction,” Southern Company Services said in a FERC filing on SEEM’s behalf (ER21-1111, et al.). “Trades generally occur on an hourly basis as the shortest increment, and most often occur only with entities in the same or directly interconnected balancing authorities.”

The SEEM proposal, which would allow participants to move power over unused transmission capacity at $0/MWh, “will enhance efficiencies and reduce opportunities to exercise market power by allowing more buyers to transact with more sellers over a much bigger region,” SEEM said.

Although the group’s name includes “market,” participants made clear that they do not see the proposal as a prelude to an RTO. “The Southeast EEM is not — and was never intended to be — a top-to-bottom reimagining of the Southeast energy market; rather, it reflects incremental improvement to the existing bilateral market,” the group said.

Among SEEM’s “core principles” are that each electric service provider and state will maintain control of generation and transmission investment decisions and that each transmission provider will remain independent, with its own transmission tariff. There will be no changes to reliability, state jurisdiction or responsibilities for resource adequacy, it said.

SEEM had provided some details of its proposal in an informational filing with the North Carolina Utilities Commission in December. (See Southeast Utilities Announce Regional Energy Market.) Friday’s filings provided many more details on its governance, cost allocation and measures to address potential market power.

Fourteen utilities and cooperatives have signed the SEEM agreement and five others are “contemplating or in the process of seeking” approvals to do so. Members opened 13 dockets detailing the agreement and changes to their transmission tariffs. (Some of the members are not FERC jurisdictional.)

Members and Participants

TVA; Southern’s Alabama Power (ER21-1111, ER21-1125), Georgia Power (ER21-1119) and Mississippi Power (ER21-1125, ER21-1121; and Duke Energy Carolinas (ER21-1116) and Duke Energy Progress (ER21-1115, ER21-1117) represent nearly three-quarters of SEEM’s net energy for load (NEL).

The other initial members are: Associated Electric Cooperative Inc.; Dalton Utilities; Dominion Energy South Carolina (ER21-1112, ER21-1128); Louisville Gas & Electric (ER21-1114, ER21-1118) and Kentucky Utilities (ER21-1120) (LG&E/KU); North Carolina Municipal Power Agency Number 1; PowerSouth Energy Cooperative; and North Carolina Electric Membership Corp.

Those planning to join are Georgia System Operations Corp. (GSOC); Georgia Transmission Corp. (GTC); Municipal Electric Authority of Georgia (MEAG); Oglethorpe Power Corp. (OPC); and South Carolina Public Service Authority (Santee Cooper).

The 19 expected members have 160 GW of summer generating capacity (180 GW winter) in parts of 11 states across the Eastern and Central time zones and serve more than 32 million retail customers.

New members — which must have a load-serving responsibility or serve an entity with that responsibility — will be allowed to join during an enrollment period from July 1 through Sept. 30 annually. Nonmembers that want to submit bids and offers into SEEM will be called participants.

Yes or No Decision for FERC

SEEM asked FERC to allow a comment period of 30 days, rather than the usual 21, and sought an effective date in 90 days — May 13. Members hope to select a vendor to build the system in the first quarter of this year with the buildout complete by the third quarter and trading beginning in the first quarter of 2022.

SEEM said FERC can only opine on whether the rates proposed in the group’s Federal Power Act Section 205 filing are just and reasonable, limiting any changes to “minor deviations.”

But FERC is likely to hear complaints from intervenors who contend SEEM does not go far enough to modernize the region’s electric industry.

When news of SEEM’s efforts became public in July, the Solar Energy Industries Association and the Southern Environmental Law Center said they would push regulators to demand more competition. The Southern Alliance for Clean Energy said SEEM appeared to be an effort to avoid legislative action to create an RTO in the Carolinas. “We remain concerned that SEEM is being constructed as a way for participating utilities to avoid being pushed to form or join a competitive energy market.” (See Southeast Utilities Talking Regional Market.)

Stakeholder Outreach

The proposal arose out of a year of discussions among the electric providers and other stakeholders, including “governmental entities and non-governmental entities such as environmental groups, trade associations and individual customers,” SEEM said.

“Comments have been overwhelmingly supportive, but a common request was that the members take the Southeast EEM construct further, to have more ambitious aims entailing far greater complexity. … The current proposal is the one that struck a delicate balance among the members, and thereby enables, for the first time, a regionwide market enhancement in the Southeast.”

“This is not the first effort to develop a regional market in the Southeast … but it is the first one to enjoy such broad support from the transmission owners and load-serving entities in the region,” Aaron Melda, TVA’s senior vice president for transmission and power supply, and Lonnie Bellar, chief operating officer of LG&E/KU, said in an affidavit submitted to FERC, referencing the collapse of a four-year effort following Order 2000 in 1999.

The group said it will post trading data on a public website and that it will hold annual meetings “open to all interested parties.”

Any changes to the market rules will be filed at FERC, providing an opportunity for public comments.

No Impact on Reliability

SEEM proposes a new zero-cost, non-firm energy exchange transmission service (NFEETS) provided on an as-available basis after all other uses have been considered. It would be available solely for 15-minute energy exchanges, have the lowest curtailment priority, and unable to be reassigned, sold or redirected.

It could only be provided by a transmission provider whose system — when added to the other participating transmission providers — creates a continuous contract path. Because it would be a non-firm, as-available product, no transmission studies would be required.

“The Southeast EEM will not have any negative impact on reliability, because it will not change any current reliability roles or responsibilities and will rely on unused transmission given the lowest curtailment priority,” the group said, adding that the market will not offer capacity transactions. “The reliability obligations that BAs and transmission providers have today are unchanged under the Southeast EEM.”

Split the Savings

SEEM said it will save customers money by allowing more efficient use of unused transmission capacity over a large footprint, increasing the opportunities for win-win trades. It will use a “split-the-savings” approach with the transaction price at the midpoint between the seller’s offer and the buyer’s bid, with an adjustment for transmission losses.

SEEM will be a “low-risk, high-reward venture,” members said, citing a 20-year benefits analysis by Guidehouse and Charles River Associates that projected a minimum of $40 million in benefits per year (2020$) in a scenario based on recent integrated resource plans and equivalent data.

Under a “carbon constrained” scenario, benefits will increase to more than $100 million annually by 2037, according to the analysis. The scenario was based on participants’ IRP carbon-reduction plans and “reasonable assumptions of what a high-renewable-and-storage, low-carbon future may look like in the Southeast.”

Start-up and ongoing costs are estimated at a total of $3.1 million annually (2020$) levelized over the 2021-2040 period.

SEEM acknowledged that the new free transmission service could result in a “slight decrease” in point-to-point revenues used to offset network service charges but said the revenues at stake are “minimal.”

Its benefits will result from bilateral trades unlikely to occur under current rules, the group said. “The automated system will have a substantial advantage in searching for transmission paths with available transmission to complete beneficial trades, overcoming transaction costs and information barriers. Further, the algorithm will exhaustively seek out all possible beneficial trades across the territory.”

In addition, it “will allow for better integration of diverse generation resources, including rapidly growing renewables, and will reduce renewable curtailments,” Melda and Bellar said in their affidavit.

Because of the lack of sub-hourly market liquidity, transmission providers currently must balance all variation in renewable output across the full hour.

“By creating greater liquidity in sub-hourly wholesale transactions, especially across a broad geographic area encompassing possibly different weather conditions and renewable policies, the Southeast EEM can provide additional opportunities for transmission service providers to either procure additional energy or to dispose of excess energy, rather than having to rely exclusively on increasing or decreasing the output from their own generation resources that provide imbalance service,” they said.

Governance, Cost Allocation

Each of the members would have a seat on a Membership Board, which “will be responsible for all significant decisions,” while a revolving subset of four members would run the Operating Committee, responsible for overseeing the day-to-day operations and working with an independent entity that would administer the system.

The Operating Committee would have two members from the investor-owned utility sector and one each from the cooperative sector and governmental utility sector, reflecting the sectors’ shares of load. To prevent any subset of members from dominating, votes by the Operating Committee would have to be unanimous, with any issues that cannot be resolved taken to the Membership Board. All members would be permitted to “attend, observe and participate” in Operating Committee meetings.

The group plans a hybrid cost allocation formula, with 25% of costs allocated equally among all members and 75% assigned based on NEL.

Market Power

The members said they would contract with an auditor to “review and analyze” market data to ensure that the system is functioning properly, but they have no plans to create a market monitor, contending that SEEM does not create new opportunities to exercise market power.

“Any additional market monitoring functions beyond the auditor’s responsibilities would be superfluous, creating additional administrative costs that are not justified. For these reasons, members are unwilling to fund the costs of a market monitor and believe the traditional means of commission oversight of [market-based rate] transactions will continue to provide adequate opportunities for review and regulatory protection,” SEEM said.

To avoiding potentially anticompetitive price discovery, all reported pricing information would be aggregated and its release delayed until at least the day after the trading day.

The group submitted an affidavit from Susan Pope, a managing director at FTI Consulting, who said no participant could exercise market power in SEEM “unless it already could exercise market power in today’s hourly bilateral market.”

Companies will be able to put constraints into the algorithm to ensure that they continue to obey current mitigation measures, Pope said. “Dominion Energy South Carolina, Duke and LG&E/KU anticipate complying with their mitigation requirements by toggling ‘off’ their home BAAs, thus ensuring that they are not matched with any bidder in their home BAAs and more than meeting the market power mitigation requirement.”

Pope said it would be problematic if a participant could unfairly obtain zero-cost NFEETS or profit from manipulating the average hourly energy exchange prices.

But she said the requirement that all participants have “toggled on” at least three unaffiliated potential counterparties would prevent collusion “to trick the algorithm into moving the schemers to the front of the line for zero-cost transmission.”

“The number of counterparties renders it difficult and risky for parties to coordinate to implement such a scheme, particularly in light of the small benefit to be obtained (i.e., a greater probability of obtaining zero-cost NFEETS),” she said.

TVA ‘Fence’

In crafting the SEEM agreement, members said they were careful to honor the so-called TVA “fence,” which Congress enacted to prevent the federal utility from selling power outside the areas it was selling to as of July 1, 1957.

Among the current SEEM participants, TVA can sell power to only Duke, LG&E/KU and Southern, although it can purchase from any SEEM participant.

“Given TVA’s central location in the Southeast, if TVA cannot participate in a redesigned market, then others (LG&E/KU and AECI) would not have a contiguous connection to the rest of the market,” Pope noted. “If they cannot connect through TVA, they must connect through one of the neighboring RTOs, thus adding another wheel, and the added transmission expense, to any transaction with a counterparty in the Southeast.”

February 14, 2021November 10, 2023

NYPSC OKs Clean Energy Programs, Local Transmission Planning

The New York Public Service Commission on Thursday approved several programs to speed up the state’s transition to renewable energy.

The measures include money for communities hosting solar or wind resources and those losing old power plants and their tax payments, new regulations on handling utility and customer data related to energy usage, and a mechanism for utilities to bypass rate case proceedings in local transmission planning.

The PSC also granted a certificate of environmental compatibility and public need to New York Transco to build a new, double-circuit 54-mile 345/115-kV transmission line, estimated at $530 million, along the Hudson River from near Albany down to Duchess County (Case No. 19-T-0684). The commission also approved the 20-mile, 345-kV Empire State Line project by NextEra Energy Transmission New York in the western part of the state (Case No. 18-E-0765).

New York state agencies last month released a study that urges faster permitting, planning and approval to build the transmission needed to integrate nearly 40 GW of new renewable energy into the grid over the coming decades. (See NY Grid Study Pushes Meshed OSW Tx, Coordination.)

The commission’s fast pace is being driven by New York’s Climate Leadership and Community Protection Act (CLCPA), which requires the state to consume 70% renewable electricity by 2030, switch to 100% zero-emission power by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by midcentury.

Utility Leverage

The PSC unanimously approved a “Phase One” local transmission planning mechanism that allows utilities to bypass the usual rate case process and acquire funding approval by petitioning the commission for such authority (Case No. 20-E-0197).

The state’s investor-owned utilities on Nov. 2 jointly filed a report in which they collectively proposed to undertake about $7 billion in transmission and distribution upgrades by 2025 (Phase One) and another $10 billion in projects for the following five years (Phase Two). (See Meshed OSW Tx Grid May Work Best, NY Officials Hear.)

The commission’s order said that relying strictly on rate case cycles to provide for cost recovery of proposed Phase One projects may delay achievement of CLCPA goals.

“However, we expect that this mechanism will be needed only in the short term … and once those [CLCPA] deadlines and requirements are incorporated into the utilities’ capital planning processes and rate plans, the commission does not anticipate a continuing need to rely on petitions for incremental funding of Phase One projects,” it wrote.

“In my eyes, this is a thoughtful and practical item founded on an open and thorough process founded on ample opportunity for input, and in fact ample and helpful uptake on that opportunity,” said PSC Chair John B. Rhodes. “It represents the next milestone to developing out the grid that we know we will need, in today’s case both on the distribution and local transmission side of the grid.”

“This really does mark the change in how transmission planning moves from serving native load, exclusively at lowest cost, to a more environmentally sensitive and environmentally driven system,” Commissioner John Howard said. “Most of the items here on Phase One were going to go forward regardless of the CLCPA, and we do get some tremendous environmental benefits by their construction.”

Most comments on the docket supported approval of the proposed Phase One projects, but the state’s Utility Intervention Unit, the City of New York and LS Power Grid New York filed comments opposing some or all of the projects on the basis that they either go beyond the scope of the PSC’s initial grid study order last May or that the utilities failed to provide adequate details or cost information.

In its comments, Multiple Intervenors, a coalition of about 60 large industrial, commercial and institutional energy customers, asked “that more robust cost-containment measures be applied to CLCPA-driven projects and especially those approved outside of the rate case process.” The group recommended NYISO’s public policy transmission planning process as a framework under which “developers submit highly detailed proposals” to allow the ISO to assess viability and sufficiency.

Relying on Property Taxes

The PSC unanimously approved a program that provides bill credits to residential electric customers in municipalities in which major renewable energy facilities are located, possibly dampening local opposition to such projects (Case No. 20-E-0249).

The type and size of the facility determine the amount of the credit. Any new solar or wind project greater than 25 MW that goes into service after April 2020 will be required to pay the utility serving the affected municipalities an annual fee of $500/MW and $1,000/MW of nameplate capacity, respectively.

Howard was not entirely pleased with the host community benefit program but said he was encouraged by the provisions to assess its effectiveness every two years.

“In the interim I would urge all municipalities that border host communities for large-scale renewable projects engage in the siting process to assure that any affected residences receive compensation under this program,” he said.

Two other energy-related items on the consent agenda had one or two votes in opposition, either from one or both of the Republican members on the five-member commission.

Commissioner Diane X. Burman provided the only dissenting vote on creating an integrated energy data resource that will provide a platform for collecting, integrating, managing and accessing customer and system data from the state’s energy utilities (Case No. 20-M-0082).

“While I think that the proposal for a statewide integrated energy data resource may have some merit, it is something we should not undertake as a commission right now,” Burman said, adding that the arrangement needs more discussion. “Frankly, I think we can and should wait until the new, permanent chair to decide if this is the direction … to have staff deeply invested in.”

Both Burman and Howard voted against authorizing the New York State Energy Research and Development Authority (NYSERDA) to provide approximately $12.5 million each year through 2029 to help local communities offset the loss of property taxes that typically occurs when a large power plant closes (Case No. 20-E-0473).

The plant closing mitigation program will not be backed by imposing incremental funding obligations on ratepayers. Instead, NYSERDA would transfer Regional Greenhouse Gas Initiative (RGGI) funding to Empire State Development for the program, with aid not to exceed $112.5 million in total through 2029.

“I must say I’m very troubled by this item for several reasons, first being the use of RGGI funds to compensate communities for loss of property tax revenues due to power plant closures,” Howard said.

The legislature has the power to compensate the loss of tax revenue in various ways, and the new program “takes off any veil” from RGGI and related fees on emitters or ratepayers being taxes, and in fact fungible, thus able to be used for purposes not foreseen when the environmental programs were created, he said.

“This is a perfect example of our state’s overreliance on property taxes to fund essential local services,” Howard said. “No state taxes energy infrastructure to the extent that we do in New York. … We also need to understand that massive capital investments to meet the carbon reduction goals of the CLCPA will only exacerbate this very flawed system.”

The PSC approved a resolution to petition Gov. Andrew Cuomo to increase the number of commissioners on the board from five to seven, given the increasing workload for commissioners and staff. The session closed with PSC Secretary Michelle Phillips reading a resolution from staff and commissioners thanking Rhodes, whose term ended Feb. 1, for his “faithful service to the residents of New York.”

February 14, 2021

NYISO Proposes ‘Grid in Transition’ Metrics

NYISO on Feb. 9 proposed a three-tier approach to its Grid in Transition initiative and measuring the effects of market changes to make sure they are working as intended.

The ISO in December 2019 issued a report on reliability and market issues related to integrating a host of clean energy resources into the electric power system over the next few years, a “grid transition” driven primarily by state policy. (See Public Policy Challenges Top NYISO Grid Plans.)

NYISO proposed categorizing projects under the initiative as imminent or underway; medium-term; or long-term.

The first category includes carbon pricing, which went through the NYISO stakeholder process but has yet to receive the state support needed to move beyond the planning stage, James Pigeon, manager of distributed resource integration, told the Installed Capacity Working Group.

Other projects underway now and expected to be completed this year and next are the ISO’s Comprehensive Mitigation Review, which involves updating its buyer-side mitigation processes. (See NYISO Explores Improving BSM Processes.)

There is also a separate effort to refine NYISO’s participation model for distributed energy resources. The ISO this year will deploy a software‐defined wide area network, an enabling technology for telemetry that could potentially be used by market participants, including demand‐side ancillary services program resources and energy storage resources (ESR).

Tracking and Metrics

The new recommendations build on a more detailed analysis presented to stakeholders in December, with NYISO now proposing tracking and metrics to establish an early warning system to review if the market rules are inconsistent with what is needed for reliability, starting with whether net forecast uncertainty is causing inefficiencies.

The ISO’s strategy is informed by its own Climate Change Study and Reliability Gap Assessment of last year. The proposal “addresses that narrow subset of the recommendations … with the idea being that these tracking and metrics would really address some of the questions that we have based on that gap analysis,” Pigeon said. “Part of it is to see if some of these metrics can give us an early-warning indicator … on a monthly or quarterly outline basis to keep an eye out for any problems indicative of a changing fleet and grid.”

One stakeholder asked if the ISO is going to have metrics for when the early-warning system is triggered, and how long it would have to be tracked before the need for a change became obvious.

NYISO Grid in Transition — A possible decarbonization path assuming a capacity addition model with “high electrification” load forecast, New York state policies and current wholesale market rules | *NYISO*

“We don’t know yet because it requires further analysis,” Pigeon said. “The first question concerns net forecast uncertainty and whether or not there are some inefficiencies being born out of that,” which the ISO would answer by starting to track some units’ revenues and other aspects of inflexibility in the system.

The main point is to provide accurate price signals for the market to run efficiently, said Michael DeSocio, NYISO director of market design. “Given the way the system is evolving and the way the market tools are committing resources that we have access to today, can we come up with more efficient ways to run the grid, given the resources we have in front of us, or are the current market processes best?”

To the extent that there are resources that get day-ahead market awards that then self-schedule in the market and take flexibility away, “we probably need to go back and reconsider the market rules to consider whether that should be allowed,” DeSocio said. “And if it shouldn’t be allowed, what’s the penalty or the market incentive to prevent it? So those are the kind of things we’re trying to get at here.”

The ISO also needs to “get a good grasp” on some of the existing run-limited resources to understand the services they provide and their limitations, Pigeon said.

Run-limited resources include ESRs, demand response, emissions-restricted output and noise-restricted output resources.

NYISO will come back in early March “and talk more in detail but limit the ballooning of hypotheticals that would sidetrack discussion,” Pigeon said. It would ten begin discussions in the second quarter on energy market improvements.

February 12, 2021

ERCOT Bracing for Winter Storm, Record Demand

ERCOT has issued several notices and advisories as it prepares for expected record electric usage into early next week.

The Texas grid operator on Monday declared an operating condition notice through Feb. 16 for extreme cold weather expected in the region. It has since issued an advisory and a watch; a watch indicates the control room anticipates tight grid conditions.

ERCOT CEO Bill Magness said the weather system is projected to bring the coldest weather that Texas has seen in decades.

Based on the current load forecast and dropping temperatures, staff expect ERCOT to set a new all-time winter peak demand record Feb. 15.

ERCOT Winter Demand — ERCOT is bracing for wintry conditions over the weekend. | *Xcel Energy*

“With temperatures rapidly declining, we are already seeing high electric use and anticipating record-breaking demand in the ERCOT region,” he said in a statement released Thursday.

The grid operator’s current winter peak demand high is 65.9 GW, set in January 2018.

Senior Meteorologist Chris Coleman expects temperatures in the 20s and 30s into the weekend, “peaking” on Feb. 16 in the single digits. The winter storm will drop several inches of snow on Dallas and bring ice to Houston next Monday, he said.

ERCOT has asked generators to prepare their facilities by reviewing fuel supplies and planned outages and implementing winter weatherization procedures. Staff are also working with transmission operators to minimize transmission outages.

The grid operator said the Texas Commission on Environmental Quality will maximize dispatched generation by exercising “its enforcement discretion” for resources’ “exceedances of emission and operational limits … that exceed air permit limits.”

February 12, 2021

EEI: Net Zero by 2035 ‘Incredibly Difficult’

The Edison Electric Institute is skeptical about the industry’s ability to meet the Biden administration’s goal of carbon-free electricity by 2035, insisting natural gas generation will be needed for the foreseeable future.

The transition to wind and solar backed by energy storage in just 15 years would be an extremely difficult goal, EEI’s President Tom Kuhn said during its annual Wall Street briefing Wednesday. “I think the 2035 date was a campaign initiative and would be an incredibly difficult situation to handle for most of the companies in the industry,” he said.

Edison Electric Institute Net Zero — Coal’s share of the U.S. generation mix has dropped by more than half since 2010, while wind has quadrupled and natural gas has almost doubled. | *Energy Information Administration*

Instead, EEI says its investor-owned utility members are “collectively … on a path” to cut their carbon emissions by at least 80% by 2050 from 2005 levels.

The association’s top executives said although its members strongly advocate renewable energy, the rollout of electric vehicles and rejoining the Paris climate accords, meeting climate goals will require a massive expansion of the transmission grid, including electronic control systems still being developed and federal investments.

EEI’s presentation highlighted changes in the generation mix (“nearly 40% carbon-free”), which it said had resulted in the lowest level of CO₂ emissions in 30 years.

Even if an expanded grid eliminates bottlenecks that impede delivery of renewables to load centers, EEI said gas-fired power plants and nuclear energy must remain in the generation mix. The nation’s 94 nuclear reactors produce nearly 20% of electricity and 50% of carbon-free power it said. The group said it supports “strong and cost-effective” federal regulations to reduce methane emissions throughout the natural gas supply chain.

Brian Wolff, vice president of public policy, noted that EEI has partnered with environmental groups to figure out the mix of sophisticated technologies that will be necessary to squeeze the last 20% of carbon out of the industry. In 2018, EEI and the NRDC unveiled 21 policy recommendations and made it clear that it would be expensive. And funding continues to be an issue.

“While we did a down payment on those technologies in the energy bill that passed in the lame duck session [of Congress] last year, we are really looking now to set the stage for the budget coming up that Congress will be dealing with as well as the administration putting forth their own budget to make sure [there are] appropriate levels of investments in these technologies,” Wolff said. (See Wind, Solar, EE, CO2 Storage Win Tax Breaks.)

EEI’s “carbon-free technology initiative” is focusing on five areas:

advanced, dispatchable renewables (e.g., superhot deep geothermal) and advanced power electronics;
zero-carbon fuels, such as hydrogen or ammonia, “from a variety of sources”;
advanced nuclear energy (fission and fusion);
carbon capture, utilization and sequestration, especially for natural gas facilities; and
advanced demand efficiency and long-duration storage.

Phil Moeller, vice president for business operations, said the industry has invested more than $1 trillion since 2010 to build smarter energy infrastructure and to integrate new generation. “These investments continue to be central to our vision of a cleaner, smarter, strong energy future,” he said, noting 75% of U.S. households now have smart meters.

But the leap to the kind of integrated national grid the industry envisions will need a raft of new public policies, he said. Some of these policies are certain to encounter pushback at the local level.

“We are focused on advocating for public policies that enable us to get critical transmission and grid infrastructure built more quickly,” he said. “The transmission system is key to increasing the integration of clean energy. It enhances the resiliency of the grid, powers electric transportation and facilitates the adoption of a broad array of smart technologies.”

Richard McMahon, vice president for energy supply and finance, warned that the industry’s plans could be hurt by federal tax increases. The Biden administration has signaled it wants to raise the current 21% corporate tax rate to 28%.

February 12, 2021

FERC Fines NY Generator on Fuel Data

FERC on Monday approved a settlement agreement requiring Alliance NYGT to pay nearly $900,000 for running two small power plants on natural gas for more than three years while being reimbursed for more expensive kerosene (IN21-4).

Under the terms of the agreement with the commission’s Office of Enforcement, the company will pay NYISO $463,984 for restitution and compensating market participants and remit a $420,000 civil penalty to the U.S. Treasury.

The agreement also requires that Alliance submit two annual compliance monitoring reports, with a third annual report at the office’s option, and to conduct at least one training program relating to compliance with the commission’s regulations and the NYISO tariff.

New York fuel data — Alliance’s 40-MW Hillburn plant in Hillburn, N.Y. | *Alliance Energy Group*

Alliance bought the Hillburn and Shoemaker generators in 2007. The units are located in Orange County, and each has a 40-MW nameplate capacity. Between January 2009 and January 2012, Alliance operated the generators exclusively on kerosene while making repairs to remedy operational issues that were most pronounced when burning gas.

Alliance completed the generators’ gas equipment upgrades in 2012 and contacted NYISO to request information about updating the reference prices in advance of the repairs being completed. Alliance failed to start on gas in response to a January 2013 dispatch request, but thereafter “the generators began operating primarily on gas to fulfill their awards.” However, the units’ reference prices remained indexed to the more expensive liquid fuel, the commission said.

NYISO in September 2013 began communicating with Alliance about the type of fuel used to operate the generators, but the company’s responses were “untimely, inaccurate or incomplete,” according to FERC, and it wasn’t until March 2016 that the firm began updating its reference prices to reflect gas capabilities for both generators.

During the period that it failed to notify NYISO of the generators’ ability to operate on gas, Alliance received inflated make-whole payments.