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October 31, 2024

Maine Governor Vetoes Bill to Limit Regional Transmission Lines

Maine Gov. Janet Mills on Wednesday vetoed a bill designed to limit development of transmission lines that would deliver electricity out of the state.

“The bill (LD 170) would create inappropriate barriers to the development of transmission lines, which could hinder the ability of the state and region to meet our critically important climate and energy goals,” Mills said in a veto letter.

As passed with a committee amendment, the bill sets guidelines for regulatory approval of transmission lines that are deemed “nonessential,” in that they are not needed primarily for in-state electric reliability, in-state retail electric service or meeting Maine’s climate goals.

“LD 170 does not prevent future transmission lines in Maine to serve Massachusetts and others in the region,” Rep. Seth Berry (D), House chair of the joint Energy, Utilities and Technology (EUT) Committee, said in a statement. “On the contrary, it asks that they be developed for mutual benefit and in consultation with communities and landowners who may otherwise be forced to host new infrastructure.”

Designating transmission lines as nonessential based on their functional benefit outside of Maine misrepresents the regional nature of the New England power grid and the global nature of the climate crisis, according to Mills. For Maine and other states in New England to meet their climate goals, “it will be essential to work strategically on a regional level, and this bill would seriously interfere with those efforts,” she said.

Amendments made by the EUT Committee established nonessential line approval requirements that Mills called “vague, ill-considered and unworkable.” The requirements included ensuring the developer demonstrates it has negotiated with stakeholders, attempted to work with impacted communities and negotiated for shared ownership if the developer cannot finance the project through revenue bonds.

The bill also would direct regulators to consult with municipal governments affected by the potential taking of land by eminent domain for a proposed transmission line before approving it.

“I worked hard to address concerns that the public flagged in the [New England Clean Energy Connect (NECEC)] debate so that we have a more transparent and accountable process moving forward and that our clean energy transition proceeds at the necessary pace to meet our climate goals,” the bill’s sponsor, Rep. Nicole Grohoski (D), said in a statement.

Mills has been a steadfast proponent of the NECEC project, which is planned to deliver Canadian hydropower to the New England grid via a 145-mile transmission line that would run through Maine. Voters in the state, however, approved a measure in November to halt construction of the project.

Avangrid subsidiary Central Maine Power, developer of the project, agreed to stop constructing NECEC while the courts consider its claim that the referendum is unconstitutional.

Legislators will return May 9 to consider LD 170 and other vetoed bills. Mills urged the legislature to sustain her veto.

Grohoski said she is “surprised and disappointed” by Mills’ veto and hoped her colleagues will join her in voting to override it.

CAISO Issues EDAM Straw Proposal for the West

CAISO on Thursday published its much-anticipated proposal to add a day-ahead market to its real-time Western Energy Imbalance Market as it tries to secure a larger share of a more regionalized Western energy landscape.

The extended day-ahead market (EDAM) plan covers key components, including transmission commitment, resource sufficiency evaluation and market-power mitigation.

“EDAM is a voluntary day-ahead electricity market with the potential to deliver significant economic, environmental, and reliability benefits for participants across the West,” CAISO said in the straw proposal. It “builds upon the proven ability of the Western Energy Imbalance Market (WEIM) to increase regional coordination, support state policy goals, and cost effectively meet demand.”

The WEIM recently surpassed $2 billion in cumulative benefits for participants since it went live in November 2014. It has 17 members and is expected to grow to 22 participants by 2023, its benefits keeping pace with participation, CAISO said.  (See Western EIM Tops $2B in Benefits.)

CAISO is hoping that the WEIM’s growth record will attract new and current members to its day-ahead offering and fend off competition from SPP, which also has a real-time market — the Western Energy Imbalance Service (WEIS) — and is planning to start its own day-ahead market in the West as part of its Markets+ program, now under development. (See Western Utilities to Support SPP Market Development.)

Western Energy Imbalance Market (CAISO) Content.jpgA map in CAISO’s Q1 2022 benefits report shows transfer paths in the Western Energy Imbalance Market. | CAISO

The stakes in the CAISO-SPP day-ahead competition could be higher than in the real-time segment because real-time trades account for only about 5-10% of energy transactions in the Western Interconnection while the day-ahead market accounts for 40% or more of all transactions, according to WECC.

CAISO projects EDAM benefits, above those already seen in the WEIM, at $95 million to $400 million annually. The ability to trade greater amounts of renewable output and reduce curtailments as states transition from fossil fuels to clean energy is viewed as a primary benefit of the EDAM.

The day-ahead market will also promote reliability, a prime concern in the West, where resources have been spread thin during summer heat waves as fossil-fuel plants retire and weather-dependent wind and solar resources take their place.

“The EDAM will … enhance reliability across [its] footprint … through a robust resource sufficiency evaluation and an imbalance reserve product that accounts for a level of uncertainty … between the day-ahead and real-time [markets],” CAISO said.

The Western Power Pool’s Western Resource Adequacy Program (WRAP), covering much of the West, is aimed at the same problem — one of a number of current efforts to promote greater regional cooperation in the balkanized Western Interconnection.

Some FERC commissioners have urged the formation of one or more RTOs in the West, while CAISO and SPP have been developing their own regional market programs, including SPP’s planned RTO West. (See Changing Grid, State Policies Favor Western RTO.)

Key Components

After a pandemic hiatus, CAISO fast-tracked EDAM development starting last fall. Three stakeholder working groups met from January through mid-March to offer input on important design elements, and CAISO incorporated the groups’ results into Thursday’s straw proposal.

“First, voluntary participation is a key feature, as it is with the WEIM,” the straw proposal said. “This will allow for voluntary entry and exit, as well as resource participation.” Ensuring fair rates for EDAM participation and confidence in market transfers were additional “threshold features” determined by the stakeholder groups, CAISO said.

Transmission commitment was another must-have, the ISO said.

“An EDAM entity and its transmission customers will need to make transmission available for the market to commit supply optimally within the EDAM [balancing authority areas] and identify transfers between EDAM BAAs,” it said. “The proposal retains the transmission bucket concept previously put forward by WEIM entities, where high-quality firm or conditional firm transmission is made available to support transfers between EDAM BAAs.”

The proposal requires participants to pass a day-ahead resource sufficiency evaluation (RSE) to show they have enough supply to meet internal demand and reserve requirements to avoid “leaning” on the market for additional supply. Failure to pass the RSE could lead to transfer limits or an opportunity for the entity to cure the deficiency through residual supply for a fee.

Other elements of the straw proposal include:

  • Integrated forward market (IFM) and residual unit commitment (RUC) would be “two primary processes of the day-ahead market,” CAISO said. “The IFM balances supply and demand, which results in optimized supply commitment schedules and identification of market transfers. The RUC process runs after the IFM and will procure incremental or decremental capacity, as a backstop to the IFM, to ensure there is sufficient physical capacity to meet demand in real-time.”
  • Market power mitigation tools would ensure that, when supply is limited, “suppliers cannot exercise market power to influence prices at arbitrarily high levels,” it said. “As a starting point for consideration, we propose to extend the WEIM market power mitigation methodology for EDAM but seek stakeholder input on the need for potential enhancements to evaluate market power across groupings of BAAs, instead of individual BAAs [in the WEIM], to better account for dynamic constraints affecting the groupings.”
  • Convergence bidding would allow submission of financial bids in the IFM that do not represent physical supply or demand, CAISO said. “Convergence bidding is a common feature of forward electricity markets and is designed to improve price convergence between the day-ahead and real-time market,” it said.
  • External resource participation would let resources outside of the EDAM footprint offer supply into the market. “These resources may be pseudo-tied or dynamically scheduled into an EDAM BAA,” CAISO said. “We propose that economic bids and self-schedules continue to be supported in the EDAM.”
  • Transfer revenue is the “settlement difference between the revenue paid to the import transfers and the cost charged to the export transfers,” CAISO said. “The ISO will distribute the transfer revenue to the EDAM entity that made the transmission available to the day-ahead market. The distribution of the transfer revenue between BAAs depends on the type of transmission used to facilitate the transfer at the transfer point. We are proposing a transmission settlement method to ensure each EDAM BAA is equitably compensated for releasing transmission capacity at each transfer point that is optimized in the day-ahead market.”
  • For greenhouse gas (GHG) accounting and reporting, the EDAM proposal recommends two potential options: a “resource-specific bidding and attribution approach, an extension of the WEIM framework for GHG accounting, and the zonal approach, which allows resources to be reflected as internal to a GHG regulation area or utilizes a hurdle rate for transfers.”

“We are considering deploying the resource specific approach at the onset of EDAM because it is more developed and better aligned with the WEIM design,” CAISO said.

The 37-page straw proposal goes into greater detail on these elements and more. A stakeholder meeting on the proposal is scheduled for May 25-26, both in-person at CAISO headquarters, in Folsom, Calif., and via a virtual option.

ISO-NE Planning Advisory Committee Briefs: April 28, 2022

ISO-NE is starting the process of figuring out how to solve future transmission challenges raised by a study looking at the system in 2050.

The preliminary results of the 2050 Transmission Study found that “paradigm shifts” in the region’s grid could lead to overloads on as much as half of the region’s 9,000 miles of transmission lines. (See 2050 Tx Study Finds Thousands of Miles of Overloads in ISO-NE.)

In a presentation to the Planning Advisory Committee on Thursday, ISO-NE officials laid out how they plan to begin addressing those shortfalls. Its primary set of solutions would consist of adding new transmission lines, rebuilding existing lines, and adding or replacing transformers.

The grid operator would also add specific transmission elements to deal with aligned but separate needs found by 2035 and 2040, and a specific winter peak load case that sees the region using 57 GW of energy.

Dan Schwarting, an ISO-NE transmission planner, warned that the study comes with a “certain degree of uncertainty” and that “developing detailed cost estimates for each component could be very costly and time-consuming.”

The study was done at the behest of the New England States Committee on Electricity, and ISO-NE is working with the states to fine-tune its results and proposed solutions, Schwarting said.

Cape Cod Curtailments

ISO-NE’s Al McBride also presented at the PAC a new pilot study analyzing potential curtailments that could be caused by new generation, specifically big additions of offshore wind off Cape Cod and at Brayton Point.

Looking at a scenario with up to 3,200 MW of wind injected into the Cape Cod area and up to 2,000 MW into Brayton Point, the study found that “a number of lines in the area have the potential to be binding and cause curtailment.”

In particular, the 399E line, a 345-kV line from West Barnstable to Bourne, Mass., was found to be the most limiting for injecting new offshore wind on Cape Cod.

But upgrading it would just mean that other constraints upstream would become the limiting factors, the study found.

Planning for Geomagnetic Disturbances

ISO-NE also outlined its plan for meeting a NERC standard on transmission system planning for geomagnetic disturbances (GMDs).

Transmission planning engineer Jinlin Zhang presented the outline of a 2026 needs assessment project regarding NERC standard TPL-007-4.

GMDs, caused by solar flares, can introduce new currents to the grid, driving transformer cores into saturation and leading to a number of adverse effects. A nine-hour blackout in Quebec in 1989 was caused by a GMD that hit power grids across North America and Europe, according to Zhang.

ISO-NE is weighing a number of contingencies to determine how vulnerable the region’s grid is to these events, which Zhang laid out in her presentation.

Maryland GHG Cuts Beat 2020 Goal, State Says

Maryland’s greenhouse gas emissions in 2020 were 32% below 2006 levels, according to the state Department of the Environment, besting its goal of a 25% cut.

The 2016 Greenhouse Gas Emissions Reduction Act (GGRA) requires the agency to publish updated inventories of statewide greenhouse gas emissions every three years. Mark Stewart, climate change program manager for MDE, disclosed preliminary figures for 2020 at Wednesday’s quarterly meeting of the Maryland Climate Change Commission.

“2020 transportation emissions were significantly lower than likely they would have been without shutdowns related to COVID,” he said. “So, backing out the COVID impacts, the reduction would probably be in the ballpark of a 28% reduction from 2006 levels.”

The agency will share final inventory numbers with the commission this summer, he added. These inventories draw on statewide activity data from agriculture, fossil fuel combustion, industrial processes, natural gas transmission and distribution, transportation, solid waste and wastewater treatment.

The Climate Solutions Now Act (SB 0528), which became law April 8, resets the state’s emissions-reduction goals to 60% below 2006 levels by 2031 and net zero by 2045. That’s half as large as the GGRA goals, which mandated a 40% reduction in emissions from 2006 levels by 2030. (See Md. Climate Change Comm. Chasing New State Law’s Ambitious Goals.)

Addressing the Climate Change Commission Wednesday, state Sen. Paul Pinsky (D) said that much of this year’s spate of climate change legislation was informed by the commission’s work. Pinsky said he and other authors of the legislation included “broad goals and examples of policies we should follow,” but he acknowledged that what’s in the text “won’t get us there.”

“We need bold actions,” he said.

Expanding on this point afterward, Pinsky said in an email, “We’ll need to: move large numbers of people out of their cars; make a huge jump in EVs [electric vehicles]; likely increase existing building emission reductions; hope for advances in improved battery storage, among other things.”

During the meeting, he noted that the question of building electrification, which is the focus of one of the commission’s working groups, “was a center of the discussion in Annapolis.”

Requiring all future buildings to be electrified “was debated hotly and for a very long time,” though it didn’t end up being included in the text, he said. Instead, the new law calls for the Building Codes Administration to study and make recommendations on the building electrification. (See Md. Climate Bills Become Law Without Hogan’s Signature.)

“That issue won’t go away,” Pinsky cautioned.

Commission Has Its Work Cut Out for It

The 60% reduction goal “will not be an easy lift, as Secretary [of the Environment Ben] Grumbles has said,” Pinsky added. “The bill wasn’t as strong as I may have liked, but does put us in the top tier, the top two, three or four states in the country.” Other states will be looking to copy features of the 2022 law, he predicted.

Pinsky and Del. Dana Stein (D) both stressed the need to focus on transportation in future years. Collaboration and partnership will be necessary “to help us meet our aggressive but necessary climate goals in terms of transportation,” R. Earl Lewis, Jr., Maryland’s deputy transportation secretary for policy, planning and enterprise services, said.

The new law requires the commission to establish four new working groups: Just Transition Employment and Retraining; Energy Industry Revitalization; Energy Resilience and Efficiency; and Solar Photovoltaic Systems Recovery, Reuse and Recycling.

Michael Powell, co-chair of the commission’s Mitigation Working Group, said there is a “need for coordination” among the increased number of working groups because “there is a lot of overlap, or at least actions that could come into conflict.” Overlapping group membership could help prevent a situation where working groups might differ on whether certain actions are possible or not, he suggested.

MISO Warns of Summer Emergencies, Load Shedding

MISO last week warned that even a normal amount of demand and generation outages will likely send it into emergency procedures this summer.

The RTO also didn’t rule out summertime load shedding during combinations of high demand and high generation outages.

At a summer readiness workshop Thursday, MISO said it projects “insufficient firm resources” to handle summer peak forecasts. The grid operator said it will probably rely on a combination of emergency resources and non-firm energy imports from neighbors to maintain system reliability in June, July and August.

MISO Resource Adequacy Coordination Engineer Eric Rodriguez said the RTO’s projections square with the 1.2-GW capacity shortfall across the Midwest that was exposed in last month’s Planning Resource Auction. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

The RTO said all summer months will require emergency resources to meet peak load conditions. Using a probable peak load forecast, MISO said it has 116 GW of firm resources to cover a 116-GW peak in June, an insufficient 119 GW to tackle a 124-GW peak in July and another 119 GW that will be no match for August’s 121-GW peak forecast.

Rodriguez said that while June is “pretty tight,” July and August contain significant reliability risks.

“Hopefully, with careful management of emergency resources, we’ll be able to navigate through the summer,” Rodriguez said.

MISO has about 12 GW worth of load-modifying resources (LMRs) and operational reserves that can only be accessed if it first declares an emergency.

The RTO said it could be in even worse shape if it encounters higher-than-normal temperatures coupled with a high level of generation outages. The grid operator said it’s possible it will find itself depleting all emergency resources and still coming up a few gigawatts short over all three months. In a worst-case scenario, MISO could have a little less than 114 GW in firm capacity and a daunting 131-GW demand during the July peak. In that case, it would be about 5 GW short after all firm and emergency resources are factored in.

MISO staff didn’t rule out the possibility of load shedding if it exhausts all its firm resources, emergency reserves and LMRs and emergency energy purchases from neighbors.

In a press release, Executive Director of Market Operations J.T. Smith said MISO Midwest is “at increased risk of temporary, controlled outages to preserve the integrity of the bulk electric system.”

“We exhaust every last megawatt before us before we get to that point,” Smith assured stakeholders at the workshop.

Smith also acknowledged that MISO is heading into summer without its usual 1,000 MW of firm capacity between Midwest and South, which also poses an additional, if small, risk when it and its neighbors experience heavy demand simultaneously. (See MISO Midwest-South Transfer Service on Outage until July.)

This summer, MISO expects above-normal to slightly above-normal temperatures in Midwest and South. The grid operator is also bracing for a lively Atlantic hurricane season and a “potentially active” storm pattern in the Midwest.

MISO Shift Manager Dan Munson said members should now expect maximum generation procedures during any season, even in spring and fall when temperatures spike.

“The thing to remember as we inch toward the summer is it could happen at anytime now,” Munson said. “The risk tolerances are changing.”

Since 2016, MISO has spent more than 40 days under a maximum generation alert, warning or event. Prior to 2016, it had not experienced any grid emergencies.

Over 2021, MISO spent 29 days in conservative operations mode for some or all of its regions; nine days were from hot weather, while 13 were from Hurricane Ida’s late August strike and recovery, limited to MISO South only.

Capacity Shortage Prompts MISO to Consider Broadened Retirement Studies

Faced with a capacity supply shortage in the 2022/23 planning year, MISO is considering broadening its generator retirement studies to consider resource adequacy.

During an April 27 Planning Advisory Committee meeting, MISO’s Sydney Yeadon said the grid operator is considering changes to its Attachment Y process — the procedures it uses to study whether retiring generation needs to stay online longer under a System Support Resource agreement.

MISO’s current evaluation process focuses solely on the reliability impacts of the retirement to the transmission system.

Yeadon said MISO’s capacity shortfall for 2022/23 is causing it to consider whether it should expand the study to include resource adequacy impacts and mitigation options. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

“A trend of increased retirements is developing quickly across the footprint,” Yeadon said, adding that while MISO respects states’ jurisdiction over resource adequacy decisions, the retirements are causing the Midwest footprint to feel a supply squeeze.

MISO said EPA regulations, paired with renewable energy and greenhouse gas emissions targets, are “rushing generation to retirement.” The grid operator singled out the EPA’s recent Good Neighbor NOx pollution limits and coal ash regulations. (See EPA Coal Ash Enforcement Impacts Midwest Coal Plants.)

According to the Institute for Energy Economics and Financial Analysis’ 2022 U.S. Power Outlook, 99.2 GW of coal-fired generation in the U.S. is expected to retire or be converted to natural gas from 2021 through 2030. The nonprofit said it expects more closure announcements on top of that.

“I completely disagree with MISO blaming coal retirements … on EPA regulations and state goals,” Sustainable FERC Project attorney Lauren Azar said.

Azar said even during her time as a Wisconsin Public Service Commissioner more than a dozen years ago, it was “abundantly clear” that coal plants were going to retire at an unprecedented rate while renewables were poised for growth.  

“Instead, I would look in the mirror,” Azar said to MISO staff. “We are unable to connect generators in much of MISO because of insufficient transmission capacity. … I’m less than articulate right now; I’m pretty wound up.”

MISO’s Andy Witmeier said MISO wasn’t trying to blame regulations for the poor resource adequacy showings.

Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out that five years ago, MISO ended its regional transmission overlay study with some members convinced that federal regulations weren’t on the horizon. That 2017 study was designed to identify long-term transmission needs under a shifting resource mix; MISO did not recommend any transmission projects from the study.

All the while, Ham said, Wall Street was trending toward decarbonization.

“We really need to pay attention to money,” he said.

America’s Power CEO Michelle Bloodworth said MISO’s retirement studies must consider resource adequacy.

Bloodworth said EPA regulations are “putting pressure on dispatchable resources to retire when they still have economic life left in them.” She asked for MISO to “send signals for those resources to stay as long as they’re needed.”

Stakeholders asked if MISO will simply conduct deeper analysis and share the results with states, which have final say over resource adequacy decisions.

MISO staff said the first discussions will focus on how it can improve its retirement studies, which are becoming more frequent.

MISO plans to hold discussions on improvements in meetings of the Planning Subcommittee through summer; however, stakeholders said the topic might be better left to the Resource Adequacy Subcommittee.

WPPI Energy’s Steve Leovy said assigning the initiative to the Planning Subcommittee was “confusing” given MISO’s many references to resource adequacy. Nevertheless, he said he agreed with the Planning Subcommittee as the starting forum.

PJM Stakeholders Endorse New Interconnection Process

PJM stakeholders overwhelmingly endorsed the RTO’s proposal for a new interconnection queue process and a related transition plan after several hours of debate and procedural motions at Wednesday’s Markets and Reliability Committee and Members Committee meetings.

The proposal, which was developed at the Interconnection Process Reform Task Force over the last year, was endorsed with a sector-weighted vote of 4.37 (87%) at the MRC and 4.52 (90%) at the MC. The new interconnection process was nearly unanimously endorsed at the January Planning Committee meeting, while the transition proposal received 91% support at the February PC. (See “New Interconnection Rules Endorsed,” PJM PC/TEAC Briefs: Jan. 11, 2022 and PJM Planning Committee Endorses ‘Fast Lane’ Criteria for Gen Projects.)

PJM said it plans to file the proposal with FERC before the end of May.

In a statement issued after Wednesday’s meetings, PJM CEO Manu Asthana thanked RTO staff and stakeholders for developing the proposal.

“These changes represent a landmark accomplishment for PJM stakeholders and staff that establishes a better process to handle the unprecedented influx of generation interconnection requests and is critical to clearing the backlog of projects,” Asthana said. “We remain committed to our strategy of facilitating decarbonization policies while preserving reliability and cost-effectiveness and will continue to work on issues raised by stakeholders during deliberations that were not part of the package.”

Jack Thomas of PJM’s Knowledge Management Center reviewed the RTO’s proposal, which includes moving away from the concept of “first come, first served” projects in the queue to a “first ready, first served” concept. PJM said the change will ensure projects that are ready to be built are prioritized instead of allowing speculative projects to fill the interconnection queue.

The number of generation projects entering the interconnection queue has nearly tripled over the last four years as more renewable projects are planned in PJM. The RTO started the year with almost 2,500 projects under study in the queue, and about 95% of the more than 220 GW is from renewables, storage or a combination of the two.

The proposal also adds language indicating that if a project doesn’t require a facility study or network upgrades it could move to the final agreement stage early, speeding up the process. The study window for projects is proposed to be 710 days, or just under two years.

PJM’s proposal includes a two-year transition to wade through the backlog of projects in the queue by prioritizing more than 1,200 projects submitted into the queue before 2021. The transition also includes a “fast lane,” which will seek to complete about 450 projects (Queues AE1 through AG1) with upgrade cost allocations up to $5 million within 18 months.

“This has really been a tremendous body of work by our staff and all of our stakeholders to come together to find consensus to some very difficult and complex issues,” said Ken Seiler, vice president of PJM’s planning department. “This is an opportunity today to control our own destiny and really represents a large step forward towards providing our region and the whole industry with more certainty.”

CGA Requests MISO Help for Late-stage Interconnection Projects

Clean Grid Alliance is asking MISO to develop a means to see late-stage generation projects through the interconnection queue when they’re dogged by uncertain and delayed affected-system study results.

The request comes as MISO and SPP have filed to enact a new relative interconnection queue priority for generation projects that stand to affect the seams for the purposes of system impact studies, affected-system studies and cost assignments for network upgrades.

MISO and SPP’s ongoing Joint Targeted Interconnection Queue transmission planning study compelled them to pivot from a “first-come, first-served” queue priority approach to a “first-ready, first-served” method. The RTOs have a filing before FERC to apply the new prioritization (ER22-1533).

MISO is processing queue applications that were submitted in 2019 and 2020, while SPP is working on interconnection requests submitted in 2017. In some cases, MISO interconnection customers that entered the queue in 2018 are already signing generator interconnection agreements, the final step before grid access.

Andy Witmeier, MISO director of resource utilization, has said it “doesn’t make sense” for MISO interconnection customers to be held up by projects in SPP’s queue that may have entered earlier but have yet to be sited. SPP’s Neil Robertson has also said the RTOs must “evolve” beyond the instinct that whoever lines up first must finish first. (See Midwest Energy Policy Series Addresses JTIQ Projects.)

But in MISO, batches of projects that entered the queue in 2018 and 2019 were left out of the new priority. The RTO said those cycles of projects are destined for generator interconnection agreements (GIAs) before the changes have a chance to take effect.

CGA’s Rhonda Peters said those projects in the late stages of MISO’s interconnection could also use a solution from the RTO to ensure they clear the queue.

Speaking to stakeholders at the Planning Advisory Committee’s meeting Wednesday, Peters said the generation projects are approaching GIAs without “final or accurate” upgrade costs from MISO’s and SPP’s affected-system studies. She said these interconnection customers don’t have a complete enough picture of the affected-system studies or the upgrades they could be on the hook for “to commit significant capital in a GIA or other construction contracts.” She said many are considering filing GIAs unexecuted — “not an ideal solution” for either them or MISO.

CGA’s Natalie McIntire called for a way to help interconnection customers’ advanced-stage projects with uncertain affected-system studies.

“I’m not aware of other industries where you have to sign on the dotted line [while] not understanding what your costs are going to be,” McIntire said.

Both EDF Renewables and Invenergy have protested MISO and SPP’s FERC filing based in part on similar arguments. EDF said it is “often faced with having to execute a GIA 12 to 18 months before obtaining clarity on final affected-system costs.” Invenergy called the affected-system study process “broken.”

Peters said advanced-stage interconnection customers in the 2018 and 2019 cycles have already spent millions that could be passed on to ratepayers even if the projects don’t reach commercial operation. “These projects are the rule-followers and ones that have gone by the book,” she said.

If the projects don’t ultimately connect to the grid, it could impact MISO’s reliability models and resource adequacy. “As the age-old saying goes, an ounce of prevention is worth a pound of cure,” she said.

In February and again in early April, Peters tried to submit a presentation on the topic but was blocked by MISO and the stakeholder leadership of the Interconnection Process Working Group (IPWG). Several stakeholders insisted MISO add the presentation to its website and devote time to stakeholder discussion on the 2018 and 2019 projects.

Future discussions on the topic are likely to take place at IPWG meetings.

FERC, NERC Drill down on Generators’ Winter Readiness

More than a year after the events of February 2021, in which an unprecedented winter storm nearly led to the entire collapse of the Texas Interconnection, FERC and NERC continue to gather information from utilities, generators and grid operators on maintaining electric reliability during severe cold weather.

That continued this week with a two-day joint FERC-NERC technical conference on winterizing generation. Staff heard from more than 25 stakeholders on the best practices, lessons learned and continuing challenges of generator owners’ and operators’ preparations for the winter season.

“It’s a very important discussion,” Chairman Richard Glick said, starting off the conference Wednesday. “I think people recognize what happened in Texas. … One of [the] factors was that the generating facilities, in many cases, didn’t operate very well under the cold weather that was experienced, and we need to make sure that doesn’t happen again.”

He referred to a similar event 10 years before, when an arctic cold front in Texas and New Mexico caused 1.3 million customers to lose power in early February 2011. More than 200 generating units in ERCOT experienced an outage, derate or failure to start, and a joint FERC-NERC report found that many generators had failed to adequately prepare for winter, even though extreme cold fronts hit the region every few years.

“We know for a fact that a decade before Winter Storm Uri, there was a similar issue in Texas and some of the other Southwest states,” Glick said. “A report was done. The report said, ‘We have a problem. We need to winterize these generating facilities.’ The report was put on the shelf, and nothing happened.”

During last year’s storm, dubbed by The Weather Channel as “Uri,” ERCOT ordered a total of 20,000 MW of rolling blackouts as it tried to prevent grid collapse — the largest manually controlled load shedding event in U.S. history.

More than 4.5 million people lost power for as long as four days, with numerous deaths resulting from the outages, another report by FERC, NERC and six regional entities said. Among its recommendations was to hold a tech conference “to discuss how to improve the winter readiness of generating units” before NERC reliability standards approved by FERC in August — in response to another prior cold snap in the Midwest in 2018 — become effective on April 1, 2023. (See FERC, NERC Release Final Texas Storm Report.)

“We’re not going to let that happen again, and today’s technical conference is one of the steps that we are taking to ensure that to be the case,” Glick said. “We will work with our partners at NERC and the regional entities as well. I think at the end of the day, we’re going to have a much stronger and much more reliable grid because of it.”

“I can’t stress enough how important communication is,” NERC CEO Jim Robb said in opening Day 2 of the conference Thursday. “I think one of the worst things to happen to a grid operator is to be surprised when they’re expecting resources to be there and they aren’t. … We’re hoping for a lot of insights to come out of this conference. …

“And of course, while this is focused on winter prep, we have to remember that changing climate conditions aren’t just limited to cold-weather events. We also have to be cognizant of hot-weather events and in general rethink how we plan and operate the system to deal with extreme events, which are not rare, as we’ve seen over the last several years.”

Cold Weather Preparedness Plans

The conference’s first panel consisted of utility executives discussing the measures they were taking to head off another winter catastrophe.

Most natural gas plants in Texas are outdoor facilities that require additional protection during cold fronts, they said.

Garry Waggoner, senior director of engineering services for Luminant, the main generation subsidiary of Vistra, said that following the 2011 cold front, the company began hardening its generation units against freezing by instituting measures to be completed by November of each year.

Luminant’s fleetwide measures include temporary wind breaks for critical equipment, freeze-protection circuitry monitoring and enclosing sensitive equipment in heat- and humidity-controlled boxes, he said.

Other generators said they use similar measures.

Roger Morgan, vice president of operations at NRG Energy, said that the company’s outdoor generating units in ERCOT installed wind breaks, additional insulation and roofing over essential systems susceptible to the cold and precipitation.

Precipitation, especially in the form of freezing rain, had a big impact during the storm and “probably caused a lot more grief at the plant levels than people may recognize or understand,” Morgan said.

NRG also pre-starts gas units before cold snaps to avoid icing, he said. Each generation site has a winter-readiness coordinator who reports to a regional coordinator. And after every winter, the company conducts a root-cause analysis of problems to avoid repeating them in future years, he said.

“We revise and develop mitigation plans and put those back into our procedure to make sure that we never have a repeat issue at any of our sites,” Morgan said.

Experiences and Lessons Learned

A panel on planning, engineering and technologies for weatherization offered some practical insights and suggestions for addressing cold weather events in what are typically warm climates.

“In the South, we used to use an event time of about 24 hours as a common design [standard],” said Mark Dittus, a project manager for infrastructure consulting firm Black and Veatch. “You would expect to see the freeze event during the night, but then you’d expect to go above freezing again the next day. So you only had a short period that you were worried about.”

But growing instances of “unprecedented” long-duration cold snaps are driving the firm’s clients to upgrade their systems, Dittus said.

El Paso Electric (EPE) is one of those clients. The utility, which serves about 450,000 customers in far West Texas and southeast New Mexico, dealt with the winter events of 2011 and 2021 but faced “severely different” outcomes in each, according to Kyle Olson, director of power generation and asset management at the utility.

EPE “did not do so well” during and after the 2011 storm. “We had major issues with our generation fleet, and we had days of rolling blackouts as a result,” Olson said, noting that in 2011 the majority of the EPE’s generation fleet had been built between 1957 and 1988.

In the wake of the storm, EPE worked with Black and Veatch to devise new facility design criteria rated to -10 degrees F, 2 degrees below El Paso’s all-time low temperature. The consulting firm helped the utility prioritize equipment for freeze protection based on risk to a unit’s operational ability. Top priorities included steam drum level transmitters and major control valves; further down the list were water lines used for a facility’s drinking water.

EPE has also brought on about 500 MW of new generation since 2011 and is currently adding another 228 MW, most of which is gas-fired. Olson said the utility’s newer gas-fired Montana plant is designed for minimal water use and freezing risk and can run on diesel as a backup.

The utility fared much better during the 2021 storm, in part because of its access to power from the Palo Verde nuclear plant in Arizona, which helped the utility avoid price spikes in the market. But the utility did identify one new vulnerability after the storm: inexperienced staff.

“They hadn’t gone through the training and then gone through the implementation of the freeze protection in 2011, so what they thought was good freeze protection, being a summer-peaking utility,” was inadequate, Olson said. “We found gaps where they would go by and walk past something and go, ‘That looks fine; that looks good.’”

Amanda Frazier, senior vice president of regulatory policy at Vistra, said her company “had a disappointing performance” during the 2011 storm but experienced different problems in February 2021, despite having worked with NERC, ERCOT and Texas regulators to implement recommended best practices around weatherization.

Between 2011 and 2021, Vistra retired about 4,000 MW of coal-fired generation and discontinued use of fuel oil backup at several plants because both were considered uneconomic, Frazier said. Like other Texas utilities, Vistra faced frozen coal piles and limitations on the gas system during the 2021 storm. The company has since invested $50 million to winterize its plants and is working to restore dual-fuel capability at those facilities with permitted fuel tanks.

But Frazier said weatherization of generating plants won’t be enough to head off another grid event like that stemming from Uri.

“It’s necessary, but it’s not sufficient to prevent the next winter storm event,” Frazier said. “Unique to Winter Storm Uri were gas shortages, exceptionally high gas prices and lack of incentives to invest properly in the weatherization of the gas infrastructure facilities. … So, there must be an equivalent focus on improving the reliability of that key supply chain.”

In a similar vein, Steve Metcalf, vice president of power production and delivery at Arkansas Electric Cooperative Corporation, pointed to yet another exigency that’s not within a utility’s control during cold weather events: the standards of other utilities.

Metcalf noted that while his co-op’s consumer-owners might be willing to pay more than other electricity customers to ensure winter reliability, the broader market might have higher tolerance for risk that could force his company to institute outages anyway.

“It’s not up to us whether or not we’re experiencing or required to do rolling blackouts or brownouts; it’s up to the market,” he said.

A Rare Success Story

During the third panel, FERC heard from representatives of ISO-NE, NYISO, PJM and SPP about their generators’ winter readiness procedures.

But also on the panel was Andrew Valencia, senior vice president of generation for Lower Colorado River Authority, whom FERC and NERC were “very eager to hear from,” according to Heather Polzin, of the commission’s Office of Enforcement.

While many gas plants did not operate during the 2021 storm, the Austin, Texas-based nonprofit utility’s Thomas C. Ferguson plant — a 556-MW gas-fired combined cycle facility located in the nearby city of Horseshoe Bay — “actually performed quite well” despite the many challenges staff faced, Valencia said.

The plant broke ground in 2012 and, according to Valencia, was “designed with the 2011 event in mind,” able to withstand down to 0 F and up to 40-mph winds.

But the plant was not designed to withstand below-freezing temps for extended periods of time. Valencia said that is true of most plants in Texas, even those with very low temperature ratings, so “it’s definitely a concern going forward.” Even with the plant’s performance, LCRA installed permanent wind walls and shielding around certain pieces of equipment that froze during the event, Valencia said. Though they required responses, increased staffing meant the freezing did not impact plant operations. LCRA called for Level 3 staffing — what Valencia said is called “battle stations” — in place about two days before the most severe weather hit because in 2011, the extreme cold came earlier than forecast.

One of the challenges to cold weather preparation that Valencia wanted to stress during his presentation is that a plant “can’t functionally test [its] weather-protection systems. You know we can test relays; we can test water-induction systems; we can test all of the different subsystems … [but] the only way [to test] is to actually endure some type of an event.”

Another challenge, especially in Texas, is “that the things that you do to protect your plant from extreme cold hurt your plant in extreme heat. We can go and add enclosures and things of that nature to protect us from the cold, but an enclosure around a pump or a motor during the hot summer season is going to be problematic.”

Gas-Electric Coordination Key to Resilience

In the last panel, participants discussed how last year’s winter revealed just how intertwined the gas and electric industries have become, and the pitfalls that can result when they don’t communicate their needs.

“We’ve found that training and drill exercises are critical to preparedness,” said Jessica Lucas, senior director of reliability coordination at MISO. “Experience has proven to be the best teacher, and we’ve had quite a bit of that in recent years.”

Among the lessons that MISO learned from Uri was to bring more urgency to both its weekly fuel data requests and its annual generation winterization survey. Both information requests are still voluntary, but for the latest winter, Lucas said the RTO attempted to impress on its entities the importance of supplying accurate information.

Measures to encourage cooperation with the annual survey this year included preseason conferences with major utilities. For the weekly fuel surveys, Lucas said MISO has elevated them to formal data requests. While this format is still voluntary, she said the goal is to emphasize to respondents how seriously the RTO views the situation.

Last year’s storms also brought home the fact that generators’ theoretical performance doesn’t always match their real-world functioning, said Todd Staples, president of the Texas Oil and Gas Association. He reminded participants not to take for granted the ability to respond to changing grid conditions in real time.

“Even with the best hardening of field assets, we have to keep in mind that most of these assets are unmanned. … There are more assets than there are people,” Staples said. “And so there’s going to be a production decline, depending on the severity of the weather, and it’s very important for reliability that we plan on this production decline and take the steps that are going to mitigate that.”

Representatives of the pipeline industry focused on the efforts their companies have made to work with electric utilities and regulators on predicting how loads are likely to shift in response to changing weather conditions.

“We really believe in the continued improvement of the balancing authority websites — that’s a huge asset for us as a pipeline operator,” said Frank Rozmus, vice president of gas control and facility planning at Northern Natural Gas. Rozmus said he and his team “spend possibly hours a day on the websites of the [BAs] in our footprint, making sure that we get up-to-date information, and it really assists us with our load supply forecast.”

Speakers also highlighted the role that government can play in facilitating the sharing of information across industries. Staples pointed to the Railroad Commission of Texas’ recent designation of critical load facilities as a sign that the needed collaboration, not only between industry segments but also with the public sector, is finally taking root.

“In my eight years here … I’ve never seen this level of engagement … between industries. The Railroad Commission of Texas, ERCOT, the Public Utility Commission [and] Division of Emergency Management have all been fully engaged, and private industry has been having multiple conversations,” Staples said. “And so I think we’re moving in the right direction.”

GOP to Granholm: ‘You’re Anti-Fossil Fuels, Aren’t You?’

Energy Secretary Jennifer Granholm announced Thursday that the United States will boost its liquified natural gas (LNG) exports to 15 billion cubic feet per day by the end of the year, with most of the increase going to European allies attempting to cut their dependence on Russia’s fossil fuels.

The announcement came as Granholm parried attacks from Republican lawmakers on the House Energy and Commerce Subcommittee on Energy, criticizing President Joe Biden’s clean energy policies and his response to high gasoline prices — and the near-term need to increase natural gas and other fossil fuel production.

Granholm was on Capitol Hill ostensibly to discuss the Department of Energy’s $48.2 billion 2023 budget request, but the Energy and Commerce hearing provided yet another demonstration of the politicization and polarization of energy policy in the wake of Russia’s invasion of Ukraine and post-COVID-19 inflation.

In her opening statement, Rep. Cathy McMorris Rodgers (R-Wash.), the full committee’s ranking member, called out a recent Granholm statement that “perhaps renewable energy is the greatest peace plan this world will ever know.”

“I cannot overstate how dangerous I believe this statement is for our energy security, our national security, our future as Americans,” Rodgers said. She called on Congress and the administration to “say yes to flipping the switch on domestic production of cleaner oil and natural gas.”

Rep. Jeff Duncan (R-S.C.) was equally confrontational. His first question to Granholm was: “You’re anti-fossil fuels, aren’t you?”

Granholm replied, “I would like to transition away from unabated fossil fuels to a clean energy future.”

Rep. Fred Upton (R-Mich.) called on DOE to lead by example by “issuing waivers to streamline the permitting process for LNG export facilities and send the signal that our country will be a stable and reliable supplier of natural gas for many decades to come. Our European allies need more certainty to push back on Russia and build new import facilities and pipeline interconnections.”

Granholm and Democrats on the committee countered with arguments that clean energy would lower prices and the dependence of the U.S. and its allies on fossil fuels from Russia and critical minerals — such as lithium for energy storage batteries — from China.

COVID, Ukraine and the rising number and severity of extreme weather events “tell us that global energy security and energy independence all depend on a shift toward American-made clean energy,” Granholm said in her opening remarks. DOE is “committed to securing the clean energy supply chains needed to reduce our reliance on unabated fossil fuels and increase our energy independence.”

At the same time, Granholm said the administration and DOE are “using every tool at our disposal to increase oil supply,” citing the president’s release of 1 million barrels of oil a day from the U.S. Strategic Petroleum Reserves and DOE’s approval on Wednesday of permits allowing two LNG facilities to increase their capacity.

With the approvals, both facilities, one in Louisiana and the other in Texas, will be able to increase their combined exports by 500 million cubic feet per day, the DOE announcement said. The Texas facility is scheduled to come online in 2024; the Louisiana plant is still in development, the announcement said.

Current export levels are about 12 billion cubic feet per day, DOE said.

“We have permitted completely 30 billion cubic feet of liquefied natural gas that has not been constructed yet,” Granholm said. “Every molecule of natural gas that can be liquefied at a terminal is being liquefied and exported.”

Echoing Granholm, Rep. Frank Pallone (D-N.J.), chair of the full committee, argued that natural gas production and LNG exports are at “record highs.”

“Five decades of fossil fuel dependency have left us reliant on volatile commodities that are priced at the whim of global markets,” Pallone said. “If we truly want to lower prices and to reduce our reliance on foreign adversaries, we must invest in renewable energy and domestic supply chains here in America.”

Solar Tariffs and Supply Chain Acceleration

While Democrats on the committee mostly offered Granholm questions that allowed her talk up DOE programs and accomplishments — like Tuesday’s release of new standards for energy-efficient light bulbs — she faced some hard questions from them as well.

Rep. Scott Peters (D-Calif.) raised concerns about the Commerce Department’s investigation of potential import violations of solar manufacturers in Cambodia, Malaysia, Thailand and Vietnam, and the devastating impact the investigation is already having on the U.S. solar industry. (See SEIA Predicts Severe Fallout from Commerce Probe of Solar Imports.)

“Is the Department of Energy researching how this potential loss in solar deployment could affect energy reliability and our climate goals, and planning what steps the administration needs to take to offset the solar project losses if they decide to impose tariffs?” Peters said.

While the final decision in the case will be “adjudicative,” Granholm said DOE and the White House Office of Domestic Climate Policy share “deep concern” about the case. “It’s safe to say that there is an awful lot of effort around how to address this given that it is an adjudicative proceeding.”

Granholm also pointed to funding in the 2023 budget for a solar manufacturing accelerator that “would help to achieve what the manufacturing processes are that can be accelerated in the solar realm, in addition to research that’s necessary in advanced components. Whether it’s the use of technology, the use of integrated systems, the bottom line is, we have to accelerate,” she said.

House Appropriations Committee

Granholm had an easier time before the Subcommittee on Energy and Water Development Thursday afternoon, where both Democrats and Republicans wanted to talk about the figures and programs outlined in Granholm’s 16-page written testimony.

While both sides of the aisle chided Granholm for not providing them with a more detailed budget justification report, she said a key priority for the 2023 budget will be building on the $62 billion in energy funding contained in the Infrastructure Investment and Jobs Act (IIJA).

That “historic long-term investment … is not on its own sufficient to address the nation’s energy challenge,” Granholm said. “That’s why our request includes base-year funding to complement the infrastructure law and maximize its impact to lower costs, to make us energy secure and to provide us with reliable baseload power.”

For example, a newly created Office of the Undersecretary of Infrastructure will be getting $2.1 billion in total, for a range of programs, including:

  • $90 million for the Grid Deployment Office “to catalyze the development of new and upgraded high-capacity electricity and distribution systems nationwide.” The money will also fund two new programs to focus on improving wholesale electricity markets and removing barriers to offshore wind deployment.
  • $214 million for the Office of Clean Energy Demonstrations for a new program that will “support full-scale and commercial-scale demonstrations that address integration issues of renewable energy in the U.S. transmission and distribution grid. The office also oversees the DOE’s initiative to develop and build two advanced nuclear reactors, one in Washington and one in Wyoming.
  • $727 million for state and community energy programs “to reduce energy costs for households and businesses, deploy low-cost clean energy solutions [and] weatherize at least 50,000 homes.”

Republicans on the committee criticized what they called the budget’s skewed priorities, with defense-related spending getting minimal increases versus more substantial increases for non-defense spending.

“The request for the nuclear program is a mere $10 million,” said Rep. Michael Simpson (R-Idaho). “In contrast, the increase for energy efficiency and renewable energy … is more than $1.7 billion, or more than a 54% increase.”

Simpson also criticized the DOE’s programs on rare earth and critical minerals as “scattered and unfocused, not only with the Department of Energy, but with other agencies that have a role to play” in developing those supply chains.

Similarly, Rep. Ken Calvert (R-Calif.) voiced disappointment that “you’re requesting a mere 3.7% increase for the [National Nuclear Security Administration] compared to 17% nondefense. … That’s a hefty cut when you account for inflation. I’m not sure how anyone can justify [shortchanging] our national security, especially now.”

Calvert was particularly concerned that the DOE has fallen behind on the production of nuclear “pits,” a key component in nuclear warheads. Granholm said the Los Alamos National Laboratory was on schedule to produce 30 pits, and the Oak Ridge National Laboratory is currently being redesigned to ensure it can also meet its quota of 50 pits, though she could not say when the redesign would be complete.